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OMV has acquired a 25% interest in PL 615 and PL 615 B from operator Equinor. The deal was reported by the NPD on 25 July 2018 and is effective from 29 June 2018. PL 615 covers a 410 sq km area over part of blocks 7324/1, 7324/2, 7324/3 and 7325/1. Two wells have previously been drilled in PL 615 targeting the Apollo (dry) and Atlantis (minor gas discovery) prospects. In October 2018 Equinor plans to return to the licence to drill an exploration well on the Intrepid Eagle prospect (see separate article). PL 615 B covers a 568 sq km area over blocks 7425/10 and 7425/11. Exploration well 7324/2-1 (a dry hole) targeted the Apollo prospect which had a Realgrunnen Group target similar to OMV’s 2013 Wisting Central discovery. The well encountered 15 m of good quality sandstone in the Jurassic Sto Formation. The Snadd Formation comprised a 170 m poor reservoir quality section. The well was dry. The second exploration well in PL 615 was 7325/1-1 targeting the Atlantis prospect. The well encountered a 10 m sandstone with hydrocarbon shows in the main objective – the Middle Triassic Kobbe Formation – but reservoir quality was poor. The Snadd Formation contained 55 m net of sandstone with a 10 m section containing gas. No sandstone was present in the Klappmyss Formation – a secondary target – but there was a 10 m gross sandstone section with poor reservoir properties in the Havert Formation. The find is not considered to be commercial. Interest in PL 615 and 615 B is now held as follows: Equinor Energy AS (55% + operator), OMV (Norge) AS (25%) and Petoro AS (20%).

OMV has acquired a 25% interest in PL 615 and PL 615 B from operator Equinor.

Chrysaor has agreed with OKEA to acquire a 15% stake the latter’s PL 038D / block 15/12a containing the Grevling oil find south of Sleipner. When completed, partnership in the 33-sq km block will be OKEA (op, 55%), Petoro (30%), Chrysaor (15%).

Chrysaor takes 15% interest in PL 038 D, which contains the Grevling oil discovery, from Okea (->55%, Petoro 30%).

The Ministry for National Development disclosed on 17 November 2017 that following recommendation of the tender committee from the Hungarian Office for Mining and Geology, it selected Magyar Olaj- es Gazipari Rt (MOL) as the winner of the bid round for the prosection, exploration and production of hydrocarbons in the Őrség area in southwestern Hungary. Following the pre-award, the company has now two months to negotiate the contract. The 669 sq km Őrség area is located in the Zala and Vas political provinces, within the Pannonian Basin..

Hungary, not found

Santos Ltd spudded the Raffle Northwest 1 exploration well in PL 1046, located in the Cooper-Eromanga Basin, on 8 June 2019.  The well was drilled to a total depth of 2,468 m, before being suspended as a successful gas well, on 28 June 2019. The well was drilled around 3 km north of the Raffle field and around 2 km southwest of the Hector South 1 gas discovery. PL 1046, which covers an area of 51 sq km, was awarded on 8 May 2019.  Participants in the permit are Santos Ltd (37.5% + Operator), Beach Energy subsidiary Delhi Petroleum Pty Ltd (30%) and Santos subsidiaries Santos Petroleum Pty Ltd (25%) and Vamgas Pty Ltd (7.5%).

Raffle Northwest 1 expl. (Santos 52,5% op., Beach 30%, Vamgas 7,5%) in PL 1046, gas disc.

On 18 October 2018, the ANP granted approval for Parnaiba Gas Natural and Parnaiba Participacoes SA to transfer their combined 100% working interest in the PN-T-084 block to parent company Eneva SA.  Parnaiba Gas Natural was the operator of the ANP Round 13 block and held 70% working interest and subsidiary company Parnaiba Participacoes SA held 30% working interest.  Two working interest transfers between the subsidiary companies took place in 2017. On 10 May 2017, the ANP granted Parnaiba Gas Natural approval to acquire 70% working interest from subsidiary company Parnaiba Participacoes SA in the PN-T-084 block who will retain a 30% non-operated working interest.  Parnaiba Gas Natural and Parnaiba Participacoes SA are subsidiaries of Eneva.  Eneva re-structured most of its contracts under the Parnaiba Gas Natural subsidiary in May 2017. On 10 May 2017, the ANP granted Parnaiba Gas Natural approval to acquire all of the working interest in eight contracts in the Parnaiba Basin from Eneva subsidiary partner BPMB Parnaiba.   BPMB was a 30% working interest non-operating partner in all of the blocks and production concessions with the exception of the ANP Round 13 PN-T-084 block where it had 70% working interest and was the operator.  The operations have been transferred to Parnaiba Gas Natural with the 70% working interest.

Brazil, PN-T-084

Yichuan 1 was drilled to a TD of 2,802m MD on 27 April 2017 and was suspended (results TBC) in May 2017. The gas exploration well was spudded on 29 January 2017 to drill to a PTD of 3,400m targeting the Carboniferous and Permian interval within the Yichuan Sag, Luoyang Basin. Yichuan 1 is in the Sinopec operated Luoyang Basin Block in Henan Province. <P />

China, Luoyang Basin

In parallel to its Disouq farmin offer (DEA 8 Jun '20), SDX is looking to sell its 25% in the Al-Amir JV operating the NW Gemsa acreage, onshore Gulf of Suez Basin, encompassing the NW Gemsa (Dev) Geyad, NW Gemsa (Dev) Al Amir + NW Gemsa (Dev) Al Ola field leases (fully developed). The fields are run by Al-Amir Petroleum, a JV between North Petroleum (25%, op), GANOPE (50%) + SDX (25%).

Egypt (Gulf of Suez B.), North West Gemsa (Dev), SDX Energy (SDX) confirmed its decision to farm-out its entire stake in the N.W. Gemsa concession, onshore Gulf of Suez Basin. The concession consists of three producing fields included in the North West Gemsa (Dev) Geyad, North West Gemsa (Dev) Al Amir and North West Gemsa (Dev) Al Ola blocks.

A total of 14 service areas have been tentatively earmarked for in the Philippines Conventional Energy Contracting Programme, due to open 2H ’18: included are 4 blocks in W. Luzon, 2 in the Cotaboto Basin, 1 in the Cagayan - Agusan-Cotaboto basins, 3 in the Sulu Sea + East Palawan basins. The Philippines Energy Resource Development Bureau will conduct several promotional meets, in Singapore, Australia, Texas (presumably Houston) and London. The application period will be 120 days as of round opening. Round info from the DoE, or contact the Petroleum Resources Development Division, email [email protected].

Philippines, not found

PRL 129, Cooper Eromanga, P&A gas shows at TD 2,790m on 30 Jun ’18, Saxon rig 183. Next on schedule Webb-1 nfw in PRL 239, target gas, same rig.

Barry 1 (Beach 50%, Great Artesian O&G 50%) in PRL 129 block, P&A gas shows.

As of 20 September 2019, Societe Nationale des Petroles du Congo (SNPC) is still understood to be looking for a partner in the in its Lower Congo Basin Le Mayombe permit. According to sources up to 49% is available but not operatorship. Local sources suggest that SNPC is awaiting a new exploration lease for the Le Mayombe block which they hope to include the Nanga III block (which formed part of the Licensing Round phase II 2018-2019).    In April 2017, SNPC was discussing with a south African company (Niari Company) regarding a partnership in the permit. The licence covers some 2,050 sq km (2,500 sq km with the addition of Nanga III) on the eastern flank of the Lower Congo Basin. CNPC acquired 189 km of 2D seismic data between 5 May and 24 October 2012. The data was processed between 8 February and 1 August 2013. Commitments relating to the first exploration period included the acquisition, processing and interpretation of 600km of 2D seismic data and/or 300 sq km of 3D seismic data and the drilling of two wells, one being optional (the seismic component is understood to have been partially completed). USD100,000 was to be dedicated to social projects and USD 200,000 to studies relevant to the hydrocarbon potential of the Zaire Basin. Each of the subsequent two three-year periods calls for drilling of two wells, one being optional, and for USD 100,000 for social projects. Decree 2006-426 for Le Mayombe exploitation permit was issued on 31 July 2006. The application was filed on 12 May 2006. Contact details: Groupe SNPC B.P. 188 Brazzaville Tel: + 242 810964 Fax: +242 810492 Email: [email protected] Background information Except for the 189 km of 2D seismic survey acquired within the Le Mayombe, very little exploration has been conducted. The Nanga III block flanks five oil discoveries four of which are very small but the M’Boundi field in production since 2002 (currently operated by Eni) is a 300 MMbo field and is located towards the north western portion of the Nanga III block. Its worth noting that several wells were drilled within the Nanga III block aimed at Oil sand exploration.

Congo, Le Mayombe

Effective 2 May '20, the C-NLOPB has issued a new exploration licence to ExxonMobil (op), Equinor + Suncor, namely EL 1165, a consolidation of EL 1134 + 1135. Partners have committed to USD 409 MM on R&D + exploration in phase 1 to 15 Jan '23. Commitments Harp + Hampden nfw's have been drilled + spudded therein.

ExxonMobil (op), Equinor + Suncor have been awarded by the C-NLOPB a new exploration licence, namely EL 1165, a consolidation of EL 1134 + 1135 in the deepwater Flemish Pass Basin. Effective 2 May '20. Partners have committed to USD 409 MM on R&D + exploration in phase 1 to 15 Jan '23. Commitments Harp + Hampden nfw's have been drilled + spudded therein.

ONE-Dyas is assumed to be looking to dilute its 100% interest in P1914 / part-block 49/19b, following the acquisition of Sterling. The 28-sq km block lies on the Silverpit Platform and is home to a committed well on the Niadar Rotliegendes gas prospect.

ONE-Dyas is assumed to be looking to dilute its 100% interest in P1914 / part-block 49/19b, following the acquisition of Sterling. The 28-sq km block lies on the Silverpit Platform and is home to a committed well on the Niadar Rotliegendes gas prospect.

On 8 December 2017, the Comision Nacional de Hidrocarburos (CNH) officially signed the contracts granting official awards for 13 of the 14 provisional awards from the CNH-RO2-LO3/2016 Bid Round. The tie-break bonus of USD 2.2 million was not paid by the consortium of Shandong, Sicoval, and Nuevas Soluciones and as a result the second-place bidder Roma Exploration and Production LLC, Tubular Technology, S.A. de C.V., Suministros Marinos e Industriales de Mexico, S.A. de C.V., and Golfo Suplemento Latino, S.A. de C.V. will have 140 days to pay its offered tie-break bonus of USD 1.5 million and sign the contract.  The Shandong consortium now forfeits its bid guarantee bond of USD 250,000 for not signing the contract.  Most of the companies and consortia have changed the official operator name from the company names approved of when granted provisional awards.  Some of the consortia have consolidated under one official operator name but the individual consortium companies still have obligations as financial guarantors. On 14 July 2017, the Comision Nacional de Hidrocarburos (CNH) officially sanctioned the results of the CNH-RO2-LO3/2016 Bid Round with the preliminary award of all 14 blocks to the high bidders. On 12 July 2017, the Comision Nacional de Hidrocarburos (CNH) held the CNH-RO2-LO3/2016 Bid Round and all of the 14 blocks on offer were bid on and were provisionally awarded.  There were a total of 52 bids by 17 companies individually or in consortia.  The bid round was highly contested with 12 of 14 blocks having more than one bid and four blocks had four or more bids.  Companies also bid the maximum additional royalties on 12 of the 14 blocks which resulted in seven ties.  The most contested block was the Area 9 block in the Sureste Basin with nine bids that resulted in a tie between eight companies who offered the maximum additional royalties of 45% and the maximum additional work units factor of 1.5 equivalent to two wells.  Jaguar Exploracion won the block with its tie-break bonus offer of USD 28.89 million, the 2nd closest bonus was USD 10.117 million from the consortia of Promotora y Operadora and Consorcio 5M del Golfo.  The second most contested block was the Area 5 block in the Tampico-Misantla Basin where again seven companies offered the maximum additional royalties of 40% and additional work units factor 1.5.  Jaguar again won the block offering a bonus of USD 26.1 million compared to the second-place bidder who offered USD 5.002 million.  Jaguar was the company that dominated the round but left USD 39.87 million on the table just for those two blocks.  The company won a total of five blocks in the round and was a partner in six of the seven blocks taken in the CNH-RO2-LO2/2016 Bid Round that was running concurrently.  Jaguar Exploracion is based in Monterey and its President is Javier Zambrano, ex Schlumberger, and backed by Grupo Topaz, presided by the ex-president of the Alfa Group. The Chinese led consortium of Shandong was also aggressive in the round placing eight total bids and winning three blocks.  Also, Carso Oil and Gas, the Carlos Slim company, placed four bids and won two blocks and it left some money on the table also with a tie-break bonus on the Area 13 block of USD 13.17 million compared to the Shandong consortium bonus offer of USD 2.35 million.  The Newpek consortium also won two blocks.  It is a subsidiary of the Alfa Group.  The Iberoamericana de Hidrocarburos company is a joint venture between Monclova Pirineos Gas and the Spanish based Cobra Instalaciones y Servicios 2007. Total area awarded in the round was 2,594.80 sq km and an estimated USD 279.1 million in exploration work commitments based on the 25 additional wells bid as extra work commitments.  Total additional bonus payments to the state by the companies due to the seven tie-breaks will be USD 83.74 million.  The average additional royalties offered was 35.2% and the CNH published that it calculates average state take for the 14 blocks of 74.5% ranging from a low of 41.6% to a high of 98%.  It is not clear if the 98% figure is an error because it is very far from the other high estimated take values of 86% to 88%.  Jaguar had the highest average CNH estimated state take at 84.94%. The tables below illustrate the Ronda 2.3 Bid Round provisional results including estimated work commitments in USD and also estimating consortia partnership working interest breakdowns which haven’t been officially reported yet.  Based on the estimated work commitments Jaguar led the round with net area to working interest, USD commitments, and Net Bonus to WI in USD. Results - CNH-RO2-LO3/2016 Bid Round – 13 of 14 Official Awards – 12/8/2017 Basin Area Contract Block Official Award - Operator - Company or Consortium Provisional Award - Company or Consortium Area sq km Additional Royalty % Minimum Work Units Approx WU Value at bo = USD 45-50 = USD1,000/WU Add Work Factor Bid - 0, 1 = 1 well, 1.5 = 2 wells Estimated Additional Work Commitments Value USD Total Work Commitments USD Winning Bonus for Tie Situations USD Total Financial Commitment USD Contract Signature Date Burgos 1 CNH-RO2-L03-BG-01/2017 BG-01 Iberoamericana de Hidrocarburos CQ, Exploracion & Produccion de Mexico, S.A. de C.V. (100%) Iberoamericana de Hidrocaruburos, S.A. de C.V. / Servicios PJP4 de Mexico S.A. de C. V.              99.25 25                3,700  $     3,700,000 2  $       16,400,000  $       20,100,000  $          4,237,264  $              24,337,264 12/8/2017 Burgos 2 CNH-RO2-L03-BG-02/2017 BG-02 Newpek 50% / Verdad 50% Newpek Exploracion Y Extraccion, S.A. de C.V. / Verdad Exploration Mexico LLC            162.95 25                4,000  $     4,000,000 2  $       21,000,000  $       25,000,000  $          2,980,000  $              27,980,000 12/8/2017 Burgos 3 CNH-RO2-L03-BG-03/2017 BG-03 Newpek 50% / Verdad 50% Newpek Exploracion Y Extraccion, S.A. de C.V. / Verdad Exploration Mexico LLC            199.60 23.56                4,700  $     4,700,000 0  $                        -     $         4,700,000    $                4,700,000 12/8/2017 Burgos 4 CNH-RO2-L03-BG-04/2017 BG-04 Iberoamericana de Hidrocarburos CQ, Exploracion & Produccion de Mexico, S.A. de C.V. (100%) Iberoamericana de Hidrocaruburos, S.A. de C.V. / Servicios PJP4 de Mexico S.A. de C. V.            199.30 3.91                4,100  $     4,100,000 1  $       10,500,000  $       14,600,000    $              14,600,000 12/8/2017 Tampico-Misantla 5 CNH-RO2-L03-TM-01/2017 TM-01 Jaguar Exploracion y Produccion 2.3, S.A.P.I. de C.V. (100%) Jaguar Exploracion y Produccion de Hidrocarburos, S.A.P.I. de C.V.              72.40 40                3,100  $     3,100,000 2  $       13,000,000  $       16,100,000  $       26,100,000  $              42,200,000 12/8/2017 Veracruz 7 CNH-RO2-L03-VC-02/2017 VC-02 Jaguar Exploracion y Produccion 2.3, S.A.P.I. de C.V. (100%) Jaguar Exploracion y Produccion de Hidrocarburos, S.A.P.I. de C.V.            251.40 40                4,300  $     4,300,000 2  $       13,800,000  $       18,100,000    $              18,100,000 12/8/2017 Veracruz 8 CNH-RO2-L03-VC-03/2017 VC-03 Jaguar Exploracion y Produccion 2.3, S.A.P.I. de C.V. (100%) Jaguar Exploracion y Produccion de Hidrocarburos, S.A.P.I. de C.V.            231.70 40                4,700  $     4,700,000 2  $       20,200,000  $       24,900,000    $              24,900,000 12/8/2017 Sureste 9 CNH-RO2-L03-CS-01/2017 CS-01 Jaguar Exploracion y Produccion 2.3, S.A.P.I. de C.V. (100%) Jaguar Exploracion y Produccion de Hidrocarburos, S.A.P.I. de C.V.              95.20 45                3,100  $     3,100,000 2  $       34,200,000  $       37,300,000  $       28,890,000  $              66,190,000 12/8/2017 Sureste 10 CNH-RO2-L03-CS-02/2017 CS-02 Shandong and Keruy Petroleum, S.A. de C.V. (100%) Shandong Kerui Oilfield Service Group Co, Ltd / Sicoval MX, S.A. de C. V. / Nuevas Soluciones Energeticas A&P, S. A. de C. V.            248.00 40                2,800  $     2,800,000 2  $       12,400,000  $       15,200,000    $              15,200,000 12/8/2017 Sureste 11 CNH-RO2-L03-CS-03/2017 CS-03 Shandong and Keruy Petroleum, S.A. de C.V. (100%) Shandong Kerui Oilfield Service Group Co, Ltd / Sicoval MX, S.A. de C. V. / Nuevas Soluciones Energeticas A&P, S. A. de C. V.            215.10 45                2,500  $     2,500,000 2  $       13,000,000  $       15,500,000    $              15,500,000 12/8/2017 Sureste 12 CNH-RO2-L03-CS-04/2017 CS-04 Operadora Bloque 12, S.A. de C.V. (100%) Carso Oil & Gas, S.A. de C.V.            244.80 45                2,700  $     2,700,000 2  $       11,600,000  $       14,300,000  $          6,182,000  $              20,482,000 12/8/2017 Sureste 13 CNH-RO2-L03-CS-05/2017 CS-05 Operadora Bloque 13, S.A. de C.V. (100%) Carso Oil & Gas, S.A. de C.V.            233.60 40                2,600  $     2,600,000 2  $       20,400,000  $       23,000,000  $       13,170,000  $              36,170,000 12/8/2017 Sureste 14 CNH-RO2-L03-CS-06/2017 CS-06 Jaguar Exploracion y Produccion 2.3, S.A.P.I. de C.V. (100%) Jaguar Exploracion y Produccion de Hidrocarburos, S.A.P.I. de C.V.            148.20 40                1,800  $     1,800,000 2  $       31,600,000  $       33,400,000    $              33,400,000 12/8/2017   Totals/Avg                2,594.80 35.2    $   48,400,000 25  $     230,700,000  $     279,100,000  $       83,738,264  $            362,838,264     Preliminary Results - CNH-RO2-LO3/2016 Bid Round – 14 Provisional Awards – 7/12/2017 Area Name Basin Area sq km Max Additional Royalties % Total Number of Bids Additional Royalty % Minimum Work Units Approx WU Value at bo = USD 45-50 = USD1,000/WU Additional WUs for 1 well Approx WU value for 1 well USD1,000/WU Add Work Factor Bid - 0, 1 = 1 well, 1.5 = 2 wells Estimated Additional Work Commitments Value USD Winning Bonus for Tie Situations USD Winning Operator - Company or Consortium 2nd Bid Company/ Consortium 2nd Bid Royalty % 2nd Bid  Additional Work Factor 2nd Bid Bonus USD CNH Estimated Total State Take % 1 BG-01 Burgos        99.25           25.00                 3        25.00 3,700                3,700,000              8,200             8,200,000                         2  $               16,400,000  $              4,237,264  Iberoamericana / Servicios PJP4 Shandong  / Sicoval / Nuevas Soluciones E          25.00 2  $             3,193,000 82.7 2 BG-02 Burgos      162.95           25.00                 3        25.00 4,000  $            4,000,000            10,500  $       10,500,000                         2  $               21,000,000  $              2,980,000 Newpek / Verdad Petrosynergy / Quimica Apollo          25.00            2.00  $             1,000,002 56.8 3 BG-03 Burgos      199.60           25.00                 2        23.56 4,700  $            4,700,000            11,000  $       11,000,000                        -    $                              -     Newpek / Verdad Petrosynergy / Quimica Apollo          18.66            2.00   77.9 4 BG-04 Burgos      199.30           25.00                 1          3.91 4,100  $            4,100,000            10,500  $       10,500,000                         1  $               10,500,000    Iberoamericana / Servicios PJP4         41.6 5 TM-01 Tampico-Misantla        72.40           40.00                 8        40.00 3,100  $            3,100,000              6,500  $         6,500,000                         2  $               13,000,000  $            26,100,000 Jaguar DEP PYG          40.00            2.00  $             5,002,019 98 6 VC-01 Veracruz      193.30           40.00                 3        40.00 4,300  $            4,300,000              6,300  $         6,300,000                         2  $               12,600,000  $              2,179,000 Shandong / Sicoval / Nuevas Soluciones Roma/Tubular/Sum Marinos/Golfo Suplemento          40.00            2.00  $             1,500,061 76.1 7 VC-02 Veracruz      251.40           40.00                 3        40.00 4,300  $            4,300,000              6,900  $         6,900,000                         2  $               13,800,000   Jaguar Petrosynergy / Quimica Apollo          25.66            2.00   88.1 8 VC-03 Veracruz      231.70           40.00                 1        40.00 4,700  $            4,700,000            10,100  $       10,100,000                         2  $               20,200,000   Jaguar         77 9 CS-01 Sureste        95.20           45.00                 9        45.00 3,100  $            3,100,000            17,100  $       17,100,000                         2  $               34,200,000  $            28,890,000 Jaguar Promotora y Operadora/Petrolero 5M de Golfo          45.00            2.00  $           10,117,000 75.4 10 CS-02 Sureste      248.00           40.00                 3        40.00 2,800  $            2,800,000              6,200  $         6,200,000                         2  $               12,400,000   Shandong / Sicoval / Nuevas Soluciones DEP PYG          22.51                -     74.5 11 CS-03 Sureste      215.10           45.00                 6        45.00 2,500  $            2,500,000              6,500  $         6,500,000                         2  $               13,000,000   Shandong / Sicoval / Nuevas Soluciones Tonalli Energia          33.30                -     76.7 12 CS-04 Sureste      244.80           45.00                 4        45.00 2,700  $            2,700,000              5,800  $         5,800,000                         2  $               11,600,000  $              6,182,000 Carso Oil and Gas Shandong  / Sicoval / Nuevas Soluciones E          45.00            2.00  $             2,179,000 73.3 13 CS-05 Sureste      233.60           40.00                 3        40.00 2,600  $            2,600,000            10,200  $       10,200,000                         2  $               20,400,000  $            13,170,000 Carso Oil and Gas Shandong  / Sicoval / Nuevas Soluciones E          40.00            2.00  $             2,350,000 69.9 14 CS-06 Sureste      148.20           40.00                 3        40.00 1,800  $            1,800,000            15,800  $       15,800,000                         2  $               31,600,000   Jaguar Perseus          40.00            1.00   86.2 Totals/Avg       2,594.80                 52 35.2    $          48,400,000                           25  $             230,700,000  $            83,738,264          $           25,341,082 74.5   Preliminary Results - CNH-RO2-LO3/2016 Bid Round – By Company – 7/12/2017 Company NAWI sq km Net Work Commitments to WI_USD Net Bonus to WI USD CNH Estimated Total State Take % by Operator Jaguar       798.90  $       129,800,000.00  $     54,990,000.00                                           84.94 Carso Oil and Gas       478.40  $         37,300,000.00  $     19,352,000.00                                           71.60 Iberoamericana       149.28  $         17,350,000.00  $       2,118,632.00                                           62.15 Servicios PJP4       149.28  $         17,350,000.00  $       2,118,632.00   Shandong       223.18  $         16,184,000.00  $         740,860.00                                           75.77 Nuevas Soluciones       216.61  $         15,708,000.00  $         719,070.00   Sicoval       216.61  $         15,708,000.00  $         719,070.00   Newpek       181.28  $         14,850,000.00  $       1,490,000.01                                           67.35 Verdad       181.28  $         14,850,000.00  $       1,490,000.01   Totals    2,594.80  $       279,100,000.00  $     83,738,264.02     Count CNH-RO2-LO3/2016 Bid Round - Preliminary Participating Companies - Individual - 11 Winning Bids Total Number of Bids 1 Carso Oil & Gas, S.A. de C.V. 2 4 2 DEP PYG, S.A.P.I. de C.V.   3 3 Ecopetrol Global Energy, S.L.U.   1 4 Grupo R Exploracion y Produccion, S.A. de  C.V.   3 5 Iberoamericana de Hidrocaruburos, S.A. de C.V.   1 6 Jaguar Exploracion y Produccion de Hidrocarburos, S.A.P.I. de C.V. 5 6 7 P&S Oil and Gas, S. de R.L. de C.V.   1 8 Perseus Exploracion Terrestre, S.A. de C.V.   1 9 PetroBal, S.A.P.I. de C.V.   2 10 Tonalli Energia S.A.P.I. de C.V.   4 Count CNH-RO2-LO3/2016 Bid Round - Final Participating Consortia - 7     1 Iberoamericana de Hidrocaruburos, S.A. de C.V. / Servicios PJP4 de Mexico S.A. de C. V. 2 2 2 Newpek Exploracion Y Extraccion, S.A. de C.V. / Verdad Exploration Mexico LLC 2 4 3 NG Oil and Gas, S.A.P.I. de C.V. / AINDA Consultores S. A. de C. V. / Petroleos Madere, S.A. de C. V.   2 4 Petrosynergy S.A. / Quimica Apollo, S.A. de C. V.   5 5 Promotora y Operadora de Infraestructura, S.A.B. de C. V.  / Petrolero 5M de Golfo, S.A.P.I. de C. V.   1 6 Roma Exploration and Production LLC / Tubular Technology, S.A. de C.V. / Suministros Marinos e Industrialies de Mexico S.A. de C. V. / Golfo Suplemento Latino, S.A. de C. V.   4 7 Shandong Kerui Oilfield Service Group Co, Ltd / Sicoval MX, S.A. de C. V. / Nuevas Soluciones Energeticas A&P, S. A. de C. V. 3 8     Blocks on offer CNH-RO2-LO3/2016 Bid Round and Additional Royalties as published by the CNH on 17 May 2017   Area Name Basin Area sq km Number of Fields Fields Type Hydrocarbons Min Work Units Mininum Additional Royalties % Maximum Additional Royalties % CNH - Est Prospective Resources - MMboe CNH - Fields Est Original Remaining Volumes - MMboe 1 BG-01 Burgos 99.25 4 Carlos, Carlota, Picadillo, Llano Blanco Gas and condensate 3,700            2.40           25.00                     3.30                8.70 2 BG-02 Burgos 162.95 3 Francisco Cano, Trevino, Tundra Oil & gas 4,000            2.40           25.00                     5.10               74.90 3 BG-03 Burgos 199.6 4 Cruz, Escobedo, Niquel, Palito Blanco Gas and condensate 4,700            2.40           25.00                     7.30                1.50 4 BG-04 Burgos 199.3 2 Aquiles, Nutria Dry gas 4,100            2.40           25.00                   20.00               87.20 5 TM-01 Tampico-Misantla 72.4 3 Gutierrez Zamora, Miguel Hidalgo, Vicente Guerrero Oil & gas 3,100            2.70           40.00                     1.30               54.60 6 VC-01 Veracruz 193.3 3 Lagarto 2, Plan de Oro, Tres Higueras Oil 4,300            2.70           40.00                     3.80                5.30 7 VC-02 Veracruz 251.4 1 Manuel Rodriguez Aguilar Oil 4,300            2.70           40.00                     8.00                2.00 8 VC-03 Veracruz 231.7 3 Adolfo Lopez Mateos, Casa Blanca, Mata Violin Oil & gas 4,700            2.70           40.00                   17.80                2.40 9 CS-01 Sureste 95.2 2 Cafeto, Vernet Oil, gas and condensate 3,100            3.90           45.00                   22.60               91.00 10 CS-02 Sureste 248          -     Light oil & gas 2,800            2.70           40.00                   13.40                    -   11 CS-03 Sureste 215.1          -     Light oil & gas 2,500            3.90           45.00                   31.30                    -   12 CS-04 Sureste 244.8          -     Light oil & gas 2,700            3.90           45.00                   38.10                    -   13 CS-05 Sureste 233.6          -     Light oil & gas 2,600            2.70           40.00                   48.40                    -   14 CS-06 Sureste 148.2          -     Light oil & gas 1,800            2.70           40.00                   30.70                    -      

Mexico (Campeche Deep Sea B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: 11 op. by REPSOL (60.0%, SIERRA PER 40.0%) to be check.10 op. by ENI SPA (100.0%) to be check.12 op. by LUKOIL (100.0%) to be check.14 op. by ENI SPA (60.0%, CITLA 40.0%) to be check.Area 13 op. by SHELL (50.0%, TOTAL 25.0%, EXXONMOBIL 17.5%, STATOIL 7.5%) to be check.2 op. by PEMEX (50.0%, RWE 50.0%) to be check.7 op. by ENI SPA (45.0%, CAIRN EN 30.0%, CITLA 25.0%) to be check.9 op. by OTP (49.0%, ETAP 51.0%, TPS 0.0%) to be check.15 op. by TOTAL (60.0%, SHELL 40.0%) to be check.

The DGH has delayed the Discovered Small Fields round II by a month or so – it had been due for launch between May-Jun ’18.  26 contract areas, covering 60 discovered small fields/fallow discoveries, are to be offered over 3,100 sq km in 8 basins - 15 are onshore and 11 offshore.

The DGH has delayed the Discovered Small Fields round II by a month or so – it had been due for launch between May-Jun ’18. 26 contract areas, covering 60 discovered small fields/fallow discoveries, are to be offered over 3,100 sq km in 8 basins - 15 are onshore and 11 offshore.

As of 31 January 2018, Mebana Energy Limited is continuing the hunt for a partner on Block 9 located onshore in the North Cuban Province of Cuba. The company has been searching for a partner since November 2017 following the Cuban government’s refusal to grant Petro Australis the right to exercise a 40% back-in option on the block, as a result Melbana retains a 100% interest. On 11 October 2017 Melbana Energy Limited announced the company had notified Cuba Petroleo Union (CUPET) authorities it has fulfilled all its commitments required for the 1st sub-period of exploration on the Block 9 PSC located onshore in the North Cuban Province. The commitments included reprocessing of 200 km of 2D seismic data and a number of geological studies. The 2nd sub-period of exploration starts on 3 November 2017 and has a term of 2 years and requires the drilling of one well on the block. The company completed a prospectivity assessment of the 2,380 sq km block in February 2017 and estimates the block to contain 12.5 Bbbl of in-place oil resources, with prospective recoverable resources pegged at 637 MMbbl. Melbana also reported that it has identified 19 prospects and leads within the tract. Drilling in 2018 is expected to target the Alameda prospect, which will test three independent objectives with a deviated well, and possibly the Zapato or Piedra prospects. Costs for the two-well campaign are estimated at USD 20 – 30 million. The Cuban government is targeting accelerated oil exploration to increase its production volumes, currently reported to be approximately 45,000 b/d of oil plus 3 MMcm/d (100 MMcf/d) of gas.

Cuba, Block 9

On 10 March 2020, partner Parex Resources Ltd announced it drilled and abandoned the Montuno 1 new-field wildcat (NFW) on the CPO 11 Block in the Llanos Basin. The NFW is located toward the central western part of the CPO 11 Block, about 20 km southeast of the Daisy 1 NFW, which spudded in late November 2019 and was tested and abandoned. The Montuno 1 NFW spudded sometime during 4Q 2019 or 1Q 2020 and reached an undisclosed depth. The 2,587.58 CPO 11 Block is owned and operated 100% by Hupecol. The original CPO 11 Block was officially awarded to Ecopetrol (operator, 100%) in December 2008. Per terms of an August 2018 farm in agreement with Hupecol, Parex will acquire 108 km 2D seismic over the acreage and pay 100% of two exploration wells (Anacaona and Montuno) to earn 50% interest in the CPO-11 Block, subject to regulatory approvals. Background Information The CPO-11 Block has relatively good 2D seismic coverage, but no 3D surveys. A total of 12 wells exist in the block, 7 NFWs and 2 outposts. The first well drilled in the block was the Kantaka 1, which was plugged and abandoned dry in December 2011. Final TD 4,305 ft (1,312 m) was reached on 6 February 2013 and main objective in the Mirador Formation. The first discovery in the block was the Venus 2, drilled in 2013. The well tested 630 bo/d of 17° API oil with a 39% water cut during production tests, and it is assumed to be targeting Oligocene – Eocene sandstones of the Carbonera Formation.

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

Ithaca Energy acquired 50% in Moray Firth Basin licence P2345 from Equinor, as released end May 2020. P2345 covers 856 sq km blocks 14/23, 24, 28 & 29b, located 25km W of the Scott and Telford fields, and 30km NE of the Atlantic and Golden Eagle fields. P2345 contains the N extent of the abandoned Goldeneye Field, otherwise the area contains 14 unsuccessful NFW wells (plus two junked wells) with shows at best. It was awarded in the 30th Seaward Licensing Round on 1 October 2018 with an initial term (to 2023) firm commitment to obtain 3D seismic ending in a drill or drop decision. Delek subsidiary Ithaca Oil and Gas Ltd is now 100% operator.

Ithaca Energy acquired 50% in Moray Firth Basin licence P2345 from Equinor, as released end May 2020. P2345 covers 856 sq km blocks 14/23, 24, 28 & 29b, located 25km W of the Scott and Telford fields, and 30km NE of the Atlantic and Golden Eagle fields

Oil and Gas Development Company Ltd (OGDCL) has assigned 2.5% working interest in Ranipur 2768-11 EL (Middle Indus Basin) onshore block to Government Holdings (Pvt) Ltd (GHPL) and 2.5% working interest to Sindh Energy Holding Company Ltd (SEHCL) (2.5%) with effect from 5 January 2018. As a result, the revised equity split is as follows: OGDCL 95% (operator), GHPL (2.5%) and SEHCL (2.5%). Ranipur 2768-11 EL covers an area of 2,415 sq km area and is located in the Khairpur, Larkana and Nausharo Feroz districts of Sindh province. OGDCL recently drilled its first new field wildcat well, Ranipur 1, in the block which was plugged and abandoned (P&A) during November 2017 after it failed to encounter hydrocarbons. The company had carried out a drill stem test (DST) after drilling to a TD of 4,746 m, reached in late August 2017.  

Oil and Gas Development Company Ltd (OGDCL) has assigned 2.5% working interest in Ranipur 2768-11 EL (Middle Indus Basin) onshore block to Government Holdings (Pvt) Ltd (GHPL) and 2.5% working interest to Sindh Energy Holding Company Ltd (SEHCL) (2.5%)

A ‘discovery’ (believed oil) has reportedly been made in the Aseng field area in offshore block 1, TD 4,417m. The well classification (expl, npw, dpw) is not mentioned, however the well does boast a 400m horiz section to be readied for production. Although gas was first mentioned, more recently this has been corrected to oil. Aseng currently produces from 5 wells connected to an 80,000-b/d FPSO.  Noble (op), partners Atlas Petr., Glencore + Gunvor.

Aseng 6P (Noble 38%, Atlas Petr. 27,55%, Glencore 23,75%, Osborne 5,7%, GEPetrol 5%) in Block 1 hc (believed oil) disc. The well classification (expl, npw, dpw) is not mentioned, however the well does boast a 400m horiz section to be readied for production.

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

Niger, Tenere

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

The Niger Republic Ministry of Oil is offering 36 open blocks on an open-door policy.

Kinross International, a subsidiary of Bakrie Group, is in the process of finalizing the acquisition deal with Mitsubishi Corp on the latter’s divestment of 25% participating interest in the Kangean PSC, located offshore in the East Java Basin, as of late August 2019. To finance the acquisition, Kinross has secured a USD 88,250,000 loan from two financial companies, Elektra Assets Ltd and Efa Ret Management Pte. Ltd, with Madison Pacific Trust Limited as guarantee agent, and affiliated company PT Energi Mega Persada (EMP) as guarantor. EMP will hold a shareholders meeting on 27 September 2019 to approve the corporate action. The loan amount is broken down under two facilities: Facility A, amounting to USD 61,250,000, is subjected to 15% interest per year and Facility B, amounting to USD 27,000,000, has an interest rate of 18% per year. Payments that need to be fulfilled under Facility A are as below, while Facility B is to be paid no later than the maturity date. First payment of USD 20,000,000 to be paid by 30 June 2019 Second payment of USD 20,000,000 to be paid by 31 December 2019 Third payment of USD 10,000,000 to be paid on 30 March 2019 Remaining balance to be paid no later than 24 months effective from the utilization date EMP will be the guarantor for the full amount of loan plus interest. The company will receive in return a guarantee fee of 1% per year from Kinross’s total loan owed for six months. Kinross was chosen to be the entity to take over the 25% share from Mitsubishi due to EMP has restrictions taking up new loan with existing lenders. The Kangean block generated 47% of the total revenue for the company in 1H 2019. Reportedly, gas lifting generated by the block for 1H 2019 amounted to approximately 133 MMcf/d or 67% of the targeted 200 MMcf/d. Upon closing of the deal, EMP will remain as the operator of the PSC, holding 50% operatorship, with Japex holding a 25% participating interest and new partner Kinross holding the remaining 25%. Background Information The Kangean PSC was originally awarded in 1980 to ARCO. Energi Mega Persada took over operations in 2004. South Saubi 1 was spudded in August 2016, using the “ENSCO 8504” S/S. The well targeted Oligo-Miocene carbonates of the Kujung Formation. The top of the carbonates was intersected at around 3,300 m MD. The limestones were thinner than expected due to the unexpected occurrence of a volcaniclastic interval. The volcaniclastics could be a secondary reservoir in the area, however no hydrocarbon was found in South Saubi 1. The well was drilled to a TD of 4,460 m MD. Source rock and migration have been indicated as likely reasons for the lack of success in this prospect. South Saubi was reported as a large oil prospect. The block contains the Pagerungan Utara oil field, which commenced production in January 2011. The operator brought the Terang field (part of the Terang, Sirasun, Batur project) onstream in May 2012 through the FPU “BW Joko Tole”. On 10 March 2019, the remaining two fields, Sirasun and Batur were also brought onstream, with the aim of achieving the targeted production rate of 200 MMcfg/d.

Mitsubishi is selling its 25% stake in the Kangean PSC (4,082 sq km) to Kinross Intl (Bakrie Grp). (Energi Mega Persada op, Japex ).

On 15 November 2018 it was announced that Azinor Catalyst has been successful with operations on its Plantain prospect and appraisal of its Agar discovery. Following two re-spuds of initial wellbore 9/14a-17 (A & B), the well 9/14a-17B targeting Plantain, was drilled to a depth of 2,254 m where it encountered the prospect at 2,066 m. A total of 27 m of high quality net reservoir sandstones in the Eocene Lower Frigg Formation were encountered and through logging-while-drilling and pressure analysis indicated a thin net oil pay zone with a significant underlying zone of residual hydrocarbons. Based on this result the sidetrack was kicked-off. Well 9/14a-17Z encountered the Upper Frigg Formation at 1,763 m and penetrated a gross reservoir of 20 m with a high net to gross ratio confirmed by log and pressure analysis and an average porosity of 30%. No Oil-Water contact was encountered. The sidetrack reached a depth of 1,962 m. It is thought recoverable resources from Agar are estimated at 15 to 50 MMboe. In terms of development the Beryl Bravo facilities are located 12 km to the north east of Agar-Plantain and the Alvheim FPSO is located approximately 14 km to the south east. The well was plugged and abandoned and the rig left location on 18 November 2018. On 24 August 2018 Azinor Catalyst spudded an exploration / appraisal well, 9/14a-17, targeting the Plantain prospect located down-dip of the Agar discovery. On 4 September 2018 it was confirmed that the well had been re-spudded as 9/14a-17A. Then, on 23 September 2018, a second re-spud occurred as 9/14a-17B. On 31 October 2018 operations on well 9/14a-17B were completed and the company kicked-off sidetrack 9/14a-17Z. The company is used the Transocean ‘Leader’ (S/S) for the well. The Agar discovery was made in 2014 with well 9/14a-15A which encountered a 33 ft oil column in high quality Eocene Frigg Formation sands. The well was drilled by MPX which was primarily targeting the Upper Jurassic sands of the Aragon prospect. The Upper Jurassic sands were encountered in the well but were water bearing. The appraisal well is planned to delineate the down-dip element of the Agar discovery with the sidetrack aiming to test the Plantain prospect. Agar is thought to hold commercial 2C volumes of 15 MMboe and Plantain could hold up to 45 MMboe (Pmean) and 98 MMboe (P10). If the operations are successful then development options could be tie backs to Beryl Bravo, Alvheim FPSO or a standalone FPSO. On 14 August 2018 it was announced that Faroe Petroleum has farmed into the licence taking a 12.5% interest from AziNor. Following completion of a deal interest in P1763 will be held by Apache Beryl Limited (50% + operator), Cairn subsidiary, Nautical Petroleum Limited (25%), AziNor Catalyst Limited (12.5%) and Faroe Petroleum (12.5%).

United Kingdom, Frigg

On 20 April 2020 it was reported that ExxonMobil signed a memorandum of understanding (MoU) with Sonatrach to discuss exploration and development opportunities in Algeria. ExxonMobil has shown interest in Algeria for some time (see below) and the passing of the new hydrocarbon law led the company to take a further step towards establishing operations in the country. Since 12 March 2020 Sonatrach signed another three such MoU's with Chevron, TPAO and Zarubezhneft. The new hydrocarbon law brings developments which should make Algeria a more attractive upstream destination. The tax rate dropped from around 85% to 60-65% and three contract types are now available to an interested company: production sharing contract, joint venture contract and risk service contract. In early October it was reported that ExxonMobil joined an industry funded study initiated by Alnaft on onshore basins in Algeria. The study is carried out by Beicip-Franlab, participants are Eni, Equinor and Total. On 30 September 2019 it was reported that officials of ExxonMobil are in Algiers to discuss partnership opportunities with Sonatrach. On 27 August 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 currently deals only with day-to-day tasks to keep existing production going. The political transition is unlikely to be completed any time soon. In late March 2019 it was reported that talks between Sonatrach and ExxonMobil were temporarily suspended due to civil unrest about the presidential election. On 9 March 2019 it was reported that Sonatrach is holding talks with ExxonMobil in Houston. The Sonatrach delegation was led by its CEO Abdelmoumen Ould Kaddour and the ExxonMobil delegation included the Vice-President for African opportunities, David MacLean, the marketing manager Africa, Ufuoma Ewherido, the director for global opportunities, Pete Rumelhart and the director for Middle East and Africa international government relations, Rochdi Younsi. The talks centered on technical, fiscal and economic aspects of the projects proposed to ExxonMobil. Among other things, Sonatrach is proposing an unconventional gas development in the Ahnet Basin. In June 2018 Sonatrach CEO Abdelmoumen Ould Kaddour had two meetings with ExxonMobil representatives on the sidelines of the 27th World Gas Conference which was held in Washington from 25 to 29 June. The first meeting was with Darren Woods, COE of ExxonMobil, the second one was with David MacLean, Vice-President for Africa and Brad Corson, Vice-President for upstream joint ventures. Ould Kaddour and the ExxonMobil officials discussed concrete projects such as cluster developments of small stranded hydrocarbon discoveries. Some sources also indicated that the development of shale gas was discussed and that an agreement could be signed by the end of the year. In February 2018, Ould Kaddour held a first round of talks with ExxonMobil during a visit to the U.S. So far, the company is not present in Algeria’s upstream.

ExxonMobil, TPAO and Zarubezhneft each signed an MoU with Sonatrach paving the way for discussions over joint E&P opportunities in the country, taking advantage of its new hydrocarbon law. Inter alia, this includes the absence of the 51% required state participation in all foreign investment projects, and likewise the state’s pre-emptive right in proposed sale of Algerian assets to foreign investors.

Fateh Jang EL, Potwar onshore, suspended at TD 5,241m (Eocene) after testing between Oct-Nov '19, co. N-4 rig.

Garhi X-2 expl (OGDCL 100%) in Fateh Jang EL, onshore block, suspended at TD=5241m (Eocene) after testing. Results unreported yet.

Tethys reports the award of sole 3-year rights to an EPSA contract for block 58 (Qatbeet), 4,557 sq km in Dhofar, S. Oman, adjacent to the company's own block 49 (Montasar). The new permit straddles the western flank of the South Oman Salt Basin and the Western Deformation Front. A 15 + 5-year production licence applies if warranted. An Oman govt co. (OOC?) will then have a (up to) 30% back-in right against refunding of past expenditures. Commitments during the first period call for 3D seismic + 2 wells. www.tethysoil.com.

Tethys reports the award of sole 3-year rights to an EPSA contract for block 58 (Qatbeet), 4,557 sq km in Dhofar, S. Oman, adjacent to the company's own block 49 (Montasar). The new permit straddles the western flank of the South Oman Salt Basin and the Western Deformation Front.

Lease AA-093131, NPR-A North Slope, N. of Horseshoe Nanushuk oil discovery, oil pay believed encountered in the target Nanushuk fm (Cret.), Arctic Fox rig 1. ConocoPhillips (op), partner Anadarko.

United States (Taroom Trough (Bowen - Surat B.s)) Horseshoe

Petrobras has completed the sale of its 100% interest in 10 fields comprised in the Enchova + Pampo packages, Campos Basin, to Trident Energy for USD 418.6 MM + contingent USD 650 MM. The fields include Bicudo, Bonito, Enchova, Enchova Oeste, Marimbá, Piraúna, Badejo, Linguado, Pampo, + Trilha. ANP map below.

(Campos b.), Petrobras has completed the sale of its 100% interest in 10 fields comprised in the Enchova + Pampo packages, Campos Basin, to Trident Energy. The fields include Bicudo, Bonito, Enchova, Enchova Oeste, Marimbá, Piraúna, Badejo, Linguado, Pampo, + Trilha.

On 31 October 2018, Triangle Energy (Global) Ltd (Triangle) reported that it has entered into a farm-in agreement with Key Petroleum Ltd (Key), to acquire a 50% participating interest in Production Licence L 07, located in the Perth Basin. The licence contains the depleted Horner oil field and is currently 100% owned and operated by Key. Key acquired 100% interest in L 07 on 6 July 2018 from AWE Ltd. Under the farm-in agreement, which remains subject to regulatory approval and the consent of a landholder, Triangle will earn 50% interest after completing an extensive work programme and carrying Key’s proportional costs of the programme. In return for carrying Key’s upfront costs, Triangle will be entitled to 87.5% of production from the licence during the first two years of any commercial production, and 75% thereafter until the costs are recovered. Key shall maintain responsibility for decommissioning costs associated with the existing Mt Horner wells and associated surface facilities The proposed work programme to be carried out under the new joint venture will include the workover of two of the existing Mt Horner wells in an attempt to restart oil production and a 3D seismic survey of at least 50 sq km. Two new wells are also proposed under the agreement after the acquisition of the survey. L 07 covers the Mt Horner oil field which produced around 1.9 MMb oil between 1982 and 2011. The reservoir is deemed to be depleted based on the current recovery system and known reservoir structure and characteristic. However, Key reports that the existing infrastructure could make future developments feasible and bring discovered hydrocarbons to market quickly and also perhaps relate back to further development options for Mt Horner (subject to regulatory and government approvals). Triangle has also engaged technical advisers Tamarind Resources to review the prospectivity around Mt Horner. The companies believe there is a high potential for additional reserves at Mt Horner. L 07 lies adjacent to the Senecio and Waitsia fields and also the Wye Knot Prospect for which Key’s joint venture partners have approved the work programme and budget for the drilling of the Wye Knot 1 oil exploration well. The Wye Knot prospect is located in a down-dip location to the crestal Wye 1 well which discovered gas in 1996. Combined prospective resources of between 0.2 MMbo (low) and 6.1 MMbo (high) (1.4 MMbo best) within the Bookara and Arranoo sandstone members of the Lower Triassic Kockatea Shale Formation has been estimated by the operator. L 07 was awarded on 14 May 1984 and is not scheduled to expire until 2027 after a successful renewal in 2006. Once the farm-in agreement between operator Key Petroleum and Triangle Energy is completed, participants will become: Key Petroleum (Australia) Pty Ltd (50% + operator) and a subsidiary company of Triangle Energy (Global) Ltd (50%). Triangle will have the option of operating the licence once the farm-in deal and associated work programmes are completed.

Australia (Greenough Shelf (Perth B.)) Wye 1

Penglai 13-2-5d (PL 13-2-5d) was plugged and abandoned, failing to intersect hydrocarbons in the target reservoirs, on or around 26 July 2019 after having been spudded on or around 9 July 2019, using the "Bohai 7" jack-up. The deviated oil and gas appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations. Penglai 13-2-5d is in the CNOOC operated Bozhong 06 Block in the offshore Bohai Gulf Basin.<P /><P />

Penglai 13-2-5d (PL 13-2-5d) was plugged and abandoned, failing to intersect hydrocarbons in the target reservoirs. The deviated oil and gas appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations. Penglai 13-2-5d is in the CNOOC operated Bozhong 06 Block in the offshore Bohai Gulf Basin

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

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

OMV AG, via wholly owned subsidiary OMV New Zealand Ltd. is offering 30-40% equity in its exploration permit PEP 57073, located in the East Coast Basin.  The opportunity is one of several that OMV is currently offering offshore New Zealand.  Under the current work programme a drill or drop decision, along with a 50% area relinquishment, is required before 1 April 2021. The first well would be required to be drilled before 31 March 2022 should the permit be retained. OMV has already secured one partner in the permit, with Statoil ASA (now Equinor ASA) acquiring a non-operated 30% share in February 2016. The joint venture has committed to the stage 2 work programme which now includes refinement of the basin modelling analysis based on sequence stratigraphic framework, refined structural model and/or seismic facies analysis, the application of a sequence stratigraphic framework to the stratigraphic succession, and undertake detailed facies mapping based on sequence stratigraphic framework, refined structural model and/or seismic facies analysis. These obligations are due to be completed before 1 October 2020. PEP 57073 is considered frontier acreage, with only minor exploration having taken place to date. No well has been drilled within the permit, however the Tawatawa 1 and Titihaoa 1 wells, both having encountered gas shows, lie just inboard of the permit boundary. The extensive Pegasus MC3D broadband survey acquired by Schlumberger in 2016 covers a significant portion of the permit. Preliminary interpretation of the survey has defined a number of leads and prospects, both structural and stratigraphic, within the Neogene stratigraphy. The primary plays are associated with compressional related anticlines, and drape and pinch-outs of turbidite sands within inverted “mini-basins”. Many of the mapped structural traps have fluid indications or amplitude anomalies. PEP 57073 was awarded on 1 April 2015 and covers an area of 9,800 sq km. Interests in the permit are OMV New Zealand Ltd (70% + Operator) and Equinor New Zealand BV (30%). Interested parties should contact: Alan Clare, Exploration & Appraisal Manager Address: Level 20, The Majestic Centre, 100 Willis Street, Wellington 6011, New Zealand Email: [email protected]

OMV AG, via wholly owned subsidiary OMV New Zealand Ltd. is offering 30-40% equity in its exploration permit PEP 57073, located in the East Coast Basin. The opportunity is one of several that OMV is currently offering offshore New Zealand.

On 14 January 2019, PICO announced that the Ramadan Marine South 3ST (SRM-3ST) appraisal well in the South Ramadan concession, offshore Gulf of Suez had encountered 33.5 m of oil pay in three horizons. 23 m were intersected in the Santonian Matulla primary target, 6 m in the pre-Miocene Brown Limestone and 4.5 m in the Maastrichtian Sudr formation. SRM-3 appraisal well was suspended in September 2018, after encountering drilling problems and was then sidetracked and drilled to a TD of 4,766 m. The well is to be completed in the Matulla section and tested. The well was spudded on 14 June 2018 to test the extension of the Matulla formation in an undrained light oil volumes up-dip of one of the previous producing wells in the field. The SRM-3 well is the last remaining commitment well on the South Ramadan concession. PICO operates the concession with a 37.25% interest, GPC holds 50% and SDX holds the remaining 12.75% interest. Background information The Ramadan Marine South field was discovered by Total Proche-Orient in July 1982. The field was put onstream in 1985. Recoverable reserves have been estimated at 5 MMbo in four reservoirs of the Nukhul, Sudr and Matulla formations. The field produced a total of 3.75 MMbbl before being shut in. The field is operated from two platforms and two production lines, with a terminal at Ras Gharib used to store crude oil. Contingent resources at the South Ramadan concession are estimated at a total of 13.56 MMbo. The concession’s production sharing agreement stipulates a cost oil of 30% and a profit oil of 22%.

Ramadan Marine South 3 (SRM 3) (Pico op. 37,5%, SDX 12,5%, EGPC 50%) in South Ramadan block, a total of 33,5m of oil pay across three horizons, hitting 23m of net pay in primary Matulla target. There was also 6m of pay in the Brown Limestone and 4,5m in the Sudr section. The well will now be completed in the Matulla section and tested to see if it flows at commercial rates. TD=4766m.

Columbus has agreed in principle the acquisition of a further 50% stake in the 22 b/d Icacos field on the tip of the SW Peninsula for USD 0.5 MM. This would be from current optr Primera O&G and Leni would become sole holder of the field. The deal is subject to a SPA and regulatory approvals. www.columbus-erp.com.

Columbus has agreed in principle the acquisition of a further 50% stake in the 22 b/d Icacos field on the tip of the SW Peninsula for USD 0.5 MM. This would be from current optr Primera O&G and Leni would become sole holder of the field.

According to reports in late-January 2018, subsidiary of Chilean state company ENAP, ENAP Sipetrol, has signed an agreement to acquire 100% interest in the Octans-Pegaso offshore block from Total.  A decree authorizing the acquisition of the area was already published in the Official Gazette of Santa Cruz Province in December 2017, pending on approval by the Argentinean Ministry of Energy and Mining. The concession is valid until September 2031, with option to extend it for another 10 years afterwards. Octans-Pegaso block covers 883 sq km offshore area in Austral Basin, and situated adjacent to Total’s Cuenca Marina Austral 1 concession or CMA-1 (also known as Area-01 Cuenca Austral). CMA-1 area includes the Vega-Pleyade gas and condensate field that was put on stream in February 2016 and became the third largest gas producer in Argentina during that year.

Enap Sipetrol has acquired an offshore block, Octans Pegaso, on the Argentine continental shelf. It was purchased from the consortium made up of Total (35%), Wintershall (35%) & ENI (30%).

The NPD confirmed on 27 April 2018 (with effect from 23 April 2018) that Statoil has acquired 40% interest in PL 762, PL 785 S, PL 872 and PL 893 from Fortis. PL 762, awarded in APA 2013, covers parts of blocks 6608/6, 6608/9, 6609/4 and 6609/7. It contains the 1983 dry hole 6609/7-1 drilled by Phillips. PL 785 S lies south of Troll and covers parts of blocks 31/11 and 26/2 (below Base Cretaceous). PL 872 is located adjacent to Skogul and covers part of block 25/1. PL 893 is located northeast of Skuld and covers parts of blocks 6608/9 and 6609/7. Lime Petroleum, partner in PL 762, announced on 30 January 2018 that it is withdrawing from the licence. Its 20% interest will be sold to an as-yet unknown external third party. See separate article for more details. Dry hole 6609/7-1, drilled by Phillips, was targeting hydrocarbons in the Upper Paleozoic but the Cretaceous Lange Formation sat directly upon the Zechstein Group, which in turn rested on metamorphic Basement. No sands were present in the Paleozoic and there were only traces of migrated hydrocarbons identified in cuttings from the Cretaceous section. No wells have historically been drilled on the acreage covered by PL 785 S, PL 872 and PL 893. Following completion of the deals interest in PL 762 is held by Statoil Petroleum AS (40%), Aker BP ASA (20% + operator), Lime Petroleum AS (20%) and Petoro AS (20%), interest in PL 785 S is split between Total E&P Norge AS (60% + operator) and Statoil Petroleum AS (40%), interest in PL 872 is divided between Aker BP ASA (40% + operator), Statoil Petroleum AS (40%) and MOL Norge AS (20%) and interest in PL 893 is held by Aker BP ASA (60% + operator) and Statoil Petroleum AS (40%).

Norway (Ras-Voring Sub-basin (Voring B.)) Skuld

Panyu 4-2/5-1 fields area, PRMB, South China Sea, WD 100m, ops terminated early Aug '20, SinoOcean Auspicious JU. Target Oligo-Miocene clastics.

(Pearl River Mouth B.) Panyu 5-6-1 (PY 5-6-1) nfw, in Panyu 4-2 & 5-1 Fields block, operated by CNOOC LTD (100%), WD 100m, ops terminated, results n/a. Target Oligo-Miocene clastics.

CNOOCI is offering negotiable equity in so far wholly-owned P2298 / blocks 206/16b, 206/17 + 206/21 containing the Howick prospect SW of Clair. Contact: Robert Hughes, [email protected].

United Kingdom, P2298

On 20 July 2020 Strike Energy Ltd reported that it has agreed terms with Talon Petroleum Limited to farm out 45% non-operated interest in the Walyering exploration permit EP 447, located in the Perth Basin. The agreement includes the formation of an unincorporated joint venture for the appraisal and future development of the Walyering field. Talon will receive interest in the license in return for a USD 6 million free carry in the upcoming appraisal well. The farm out completion remains subject to the execution of definitive transaction documentation and ministerial approval. Talon will pay the first USD 6 million of the Walyering appraisal well, up to a total gross USD 9 million spend, with all costs post this to be incurred on a pro-rata basis. The company has also issued a five year right of first refusal if Strike commence the marketing of Ocean Hill for farm out. Farming out the Walyering field will accelerate the appraisal drilling into CY2021, with Strike adding the Walyering well into its Perth Basin drilling programme, which will likely realise a potential cost saving. The Walyering field was discovered in 1971 and produced a total of 261 MMcf of gas from the Lower Jurassic Cattamarra Coal Measures over a four-month period before the reservoir was considered depleted and production ceased. Conventional sandstone reservoirs of Jurassic age, similar to the Gingin West and Red Gully gas and condensate trend, have been identified in the permit area over a structure area of approximately 10 sq km. It’s considered that original drilling failed to target the highs due to poorly positioned 2D seismic data. The field is located in close proximity to existing infrastructure and existing industrial gas users. Strike reported that the farm out is inline with the company's strategy of accelerating production of large volumes of domestic gas in its Perth Basin assets, where a supply shortage is predicted in the mid to late 2020's. Successful appraisal drilling will prove up a commercial development, which may result in a material uplift in valuation of Strike's 1,853 sq km acreage across the Jurassic West Gas Play in the Cattamarra sequence. EP 447 covers an area of 1,108.21 sq km and is scheduled to expire on 22 February 2022. Current interest in the permit is Strike North West Pty Ltd (50% interest and operatorship) and Strike South Pty Ltd (50% interest). Once the farm in is complete, Strike will hold 55% interest and operatorship, and Talon Petroleum will hold 45% interest.

(Perth b.), EP 447 block, Strike has agreed to farmout a 45% non-operated interest in so far wholly-owned EP 447, 1,108 sq km onshore Perth Basin, to Talon Petroleum.

Lundin confirmed on 3 October 2018 that it has agreed a deal with Equinor to acquire its 15% interest in PL 359 (which contains the Luno II oil discovery). As part of the deal Lundin will transfer 20% interest in PL 825, covering the Rungne prospect, to Equinor. Luno II has estimated recoverable reserves of 40-100 MMboe. The development concept is a phased subsea tie-back to Edvard Grieg with PDO submission expected in early 2019. The deal will be effective from 1 January 2018. Luno II discovery well 16/4-6 S was drilled in 2013. A 280 m Jurassic / Triassic sandstone with high net to gross was encountered containing a 45 m gross oil column. The oil is light, the OWC is at 1,950 m and there is a thin gas cap. The well flowed at a rate of over 2,000 bo/d through a 48/64” choke. Later in 2013 Lundin drilled appraisal well 16/5-5 to test the potential southeasterly extension of Luno II. A 150 m thick fine-grained Triassic sandstone came in high to prognosis but was of poor quality. It was concluded that there is a pressure barrier between this well and the discovery well and that 16/5-5 lies in a separate sub-basin. A further appraisal well, 16/4-8 S, was drilled in 2014 and proved a 500 m thick sandstone in the Jurassic / Triassic with a 30 m oil column lying below a very thin gas zone. The well flowed at a rate of 450 bo/d through a 28/64” choke. Faroe will drill an exploration well on the Rungne prospect in PL 825 in late September 2018. 30/6-30’s objective is the Middle Jurassic Oseberg Formation (Broom/Rannoch equivalent of the Brent Group) at 3,361 m and there are secondary objectives in the Middle Jurassic Etive (3,336 m) and Ness (3,266 m) formations. Potential recoverable reserves are 70-110 MMboe and partner Lundin puts chance of success at 36%. Following completion of the deal interest in PL 359 will be divided between Lundin Norway AS (65% + operator), OMV (Norge) AS (20%) and Wintershall Norge AS (15%) and interest in PL 825 will be split between Faroe Petroleum Norge AS (40% + operator), Spirit Energy Norge AS (30%), Equinor Energy Norge AS (20%) and DNO Norge AS (10%).

Lundin (->65%, OMV 20%, Wintershall 15%) has agreed to acquire Equinor’s 15% in PL 359, home to the Luno II oil find. The cash deal will be accompanied by Lundin transferring its 20% in PL 825 (Rungne) to Equinor.

Add. DEA 23 Mar ’19: AE-0056-2M-Mezcalapa-06 block, onshore Sureste Basin, susp. o&g on 20 Mar ’19. Of note the well had been suspended for a while already, results (at the time) and reasons unknown. PTD was 3,955m, target U. Miocene.

Cibix 1EXP op. by Pemex (100%) in AE-0056-2M-Mezcalapa-06 block, suspended as an o&g discovery, target U.Miocene

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

Netherlands, J9

Boda 1 was drilled to a TD of 4,336m MD in the Carboniferous interval on 30 October 2019 and was suspended for further evaluation and testing in mid-November 2019. A total of nine cores measuring 33.56m (99.2% recovery) were collected. Boda 1 was spudded on 13 March 2019 to drill to a PTD of 4,000m and was targeting the Carboniferous interval and Permian Wutonggou Formation with the objective of exploring the hydrocarbon potential of the eastern section of the Fukang Fault Zone, Junggar Basin. Boda 1 is in the PetroChina operated Santai High Block in the southern Junggar Basin.

Boda 1 was drilled to a TD of 4,336m MD in the Carboniferous interval on 30 October 2019 and was suspended for further evaluation and testing in mid-November 2019. A total of nine cores measuring 33.56m (99.2% recovery) were collected

ONGC is inviting offers for 15+5 year enhanced o&g recovery rights to 64 mature fields under a revenue-sharing model (production enhancement contract round, ref. DEA 21 Nov ‘18). This forms part of a bidding process announced for 17 onshore blocks comprising 64 fields with total in-place 300 MMtoe.  A pre-bid conference will be held at ONGC’s premises in New Delhi, info dockets and data packages available at the Institute of Reservoir Studies, ONGC, Ahmedabad. Bids are invited through https://etender.ongc.co.in. Release here.

ONGC is inviting offers for 15+5 year enhanced o&g recovery rights to 64 mature fields under a revenue-sharing model (production enhancement contract round, ref. DEA 21 Nov ‘18). This forms part of a bidding process announced for 17 onshore blocks comprising 64 fields with total in-place 300 MMtoe.

In early November 2017, Statoil Gulf of Mexico acquired WI from Samson Offshore in ten Walker Ridge blocks: 12.5% in WR 117 (G34629), WR 157 (G34631), WR 158 (G34632), WR 159 (G34633) and WR 160 (G34634) and 33.33% in WR 227 (G35732), WR 270 (G34640) WR 271 (G35080) and WR 272 (G35081and WR 315 (G35733), situated in the East Texas Coastal Basin. The transactions are effective as of 1 November 2017. Following completion of the transactions, equity in WR 117 and WR 157-WR 160 is now shared between Statoil Gulf of Mexico (62.5% WI + Op) and Anadarko US Offshore (37.5%). Furthermore, Statoil Gulf of Mexico is now the operator and sole interest-holder (100% WI + Op) in the remaining blocks (WR 227, WR 270-WR 272 and WR 315).

Not Found

On 19 September 2019, the Federal Agency for Subsoil Use held an auction for the Selli block in Dagestan Republic (North Caucasus). Infiniti Neftegaz won the contest with offer of RUB 0.982 million (USD 0.02 million). The winner will obtain a 25-year E&P license. The Selli block covers 114 sq km in the Terek-Caspian Basin and encompasses the depleted Selli oil field and the Ulluchayevskaya lead. 54 wells including 17 oil producers have been drilled at the field. In 1953-1972, the field produced 1.8 MMbbl of oil and 8 Bcf of gas. Hydrocarbon resources (category D1) of the block are estimated at 3 MMbbl of oil and 21 Bcf of gas. The starting price amounted to RUB 0.702 million (USD 0.01 million).

Infiniti Neftegaz won the Selli block in Dagestan Republic (North Caucasus).

Inpex's partner Shell is planning to divest its 35% participating interest (PI) in the Masela PSC, located in Timor Sea. As reported by local media on 5 July 2020, quoting SKK Migas's Deputy for Operations, Inpex and Shell are in discussion for the former to take up the PI, and at the same time Inpex could continue to look for a new partner to join the PSC. The block contains the Abadi field which is under development phase. The operator last finalized in mid-June 2020 two contractors for the subsea umbilicals, risers, and flowlines FEED work. Likewise, the operator also received approval from the Regional Governor of Maluku for the land acquisition implementation stage. The land area, that covers approximately 27 hectares, will host a port to be utilized for movement of goods, equipment, spare parts, as well as building the onshore LNG (OLNG) plant. The Abadi project was initially envisioned by Inpex as a Floating LNG (FLNG) development due to the remote location of the field, in deep water and away from existing infrastructure. However, in March 2016, the President of Indonesia instructed the operator to change the FLNG scheme to an OLNG development, in order to maximize the benefit for local communities. Inpex received approval for the revised Abadi POD on 12 July 2019. The project will require an investment of approximately USD 18-20 billion. Concurrently with POD approval, the Ministry of Energy and Mineral Resources also granted a seven-year additional time allocation for the current PSC plus a 20-year extension, moving the contract expiry date from 2028 to 2055. The seven-year period is to compensate for the time spent studying the previously proposed offshore LNG proposal, while the 20-year extension will allow for the realization and full monetization of the project, ensuring sufficient financial conditions for the participants. Background Information The Masela PSC was originally awarded to Inpex (100%, operator) in 1998. On 24 July 2011, Inpex signed an agreement to farm-out 30% participating interest in the Masela PSC to Shell. Official approval of the deal was reported on 8 December 2011. Shell’s involvement in the Prelude FLNG project in offshore Australia played a role in its selection as a partner. Farm-in opportunity for non-operating interest in the block continued to exist after the farm-out to Energi Mega Persada in November 2009. In 2013, Energi Mega Persada decided to exit the block, subsequently the 10 % PI by the company was taken over by Inpex and Shell, each added extra 5% to their existing share.

Indonesia (Bonaparte B.) Masela op. by SHELL (35%), INPEX (34%), JOGMEC (31%), Shell is planning to divest its 35% participating interest (PI) in the Masela PSC, located in Timor Sea.

WA-28-P, Dampier sub-basin (N. Carnarvon Basin), WD 124m, TD 3,285m, concluded in May, now confirmed dry by partner BHP, Ocean Apex SS.

Achernar 1 expl. (Woodside 15,78% op. Shell 15,78%, Japan Australian LNG 15,78%, Chevron 15,78%, BP 15,78%, CNOOC 5,32%) in WA-028-P, P&A dry.

DNO’s takeover of half of ExxonMobil 80% in the 324-sq km Baeshiqa block in Kurdistan, announced last September, became effective 10 Apr ’18. Resulting partnership DNO (new op), partners ExxonMobil + Turkish Energy Co (KRG 20% carried). Plans include a couple of explo wells.

Iraq, Baeshiqa

SapuraOMV is looking to sell-off its Peninsular Malaysia assets, comprising 50-80% stakes in shallow-water producing blocks PM-323 + 329 (operated) and PM-318 and the PNL/Abu Cluster (non-operated), partner Petronas. Production last year was around 21,000 bo/d + 6 MMcfg/d. Block details from GEPS.

SapuraOMV is looking to sell-off its Peninsular Malaysia assets, comprising 50-80% stakes in shallow-water producing blocks PM-323 + 329 (operated) and PM-318 and the PNL/Abu Cluster (non-operated), partner Petronas. Production last year was around 21,000 bo/d + 6 MMcfg/d.

On 23 April 2018, Savannah Petroleum PLC (Savannah) has announced that the Bushiya 1 well has discovered oil in its primary target Alternance Sokor “A” Sands. Preliminary results on wireline logs, fluid sampling and pressure estimations have shown the existence of 10 m net pay of excellent quality light oil in two intervals of 3 m and 7 m respectively. The well has been suspended for future re-entry with a dedicated production test to be performed once the planned drilling of the remaining two wells is completed (see below for more information). Bushiya 1 is located in the southernmost sector of the R3 block. Savannah Niger is the operator of the Agadem R1, R2, R3, and R4 blocks through a joint venture between Savannah Petroleum Ltd (95%) and Niger Exploration (5%) which is in turn 100% controlled by Savannah's country manager, Yacine Wafy. On 3 April 2018, Savannah announced that the drilling of its first prospect Bushiya in R3 block had started on 31 March 2018. The well Bushiya 1 primarily targeted the Alternance Sokor "A" Sands with the Upper Sokor Sands “US” as secondary target which was considered to be upside (see below for more information). The prospect had estimated total mean unrisked recoverable resources of 36 MMbbl. Well name: Bushiya 1 Spud date: 31 March 2018 Total Depth: 2,200 m Planned depth: 2,114 m Rig name: GW-215 (GWDC, subsidiary of China National Petroleum Corporation, CNPC) Duration: 16 days to reach the target, operations to be completed in 25 days (over estimated 35 days) Well cost: USD 6 to 8 million per well (Savannah, December 2017). Following the drilling of Bushiya 1 in 25 days, Savannah reported that the well cost was “under budget” Prospect overview: -        R3 block area: o   DRILLED: The Bushiya prospect (vertical well) is located the southernmost sector of the R3 East 3D survey area and covers a surface of approximately 16 sq km. It shows excellent hydrocarbon potential according to the interpretation of the seismic data. Bushiya has the Alternance Sokor "A" Sands (Eocene) as primary target and the Upper Sokor "US" Sands (Oligocene-Miocene) as secondary target with a volume potential of 28 MMbbl and 38 MMbbl respectively. o   100% OF PREPARATION WORKS READY (as of late April 2018): Savannah’s second well (deviated 20º) will target the Amdigh prospect, also located in the R3 East area few kilometers north of Bushiya. It covers a surface of around 20 sq km and also shows excellent reservoir potential. Targets are the same with volumes of 33 MMbbl for the "A" Sands and 25 MMbbl for the "US" secondary target. o   The third prospect to be drilled will be Kunama which is the northernmost prospect in the R3 East area, right on the block limits. It covers a surface of approximately 12 sq km and shows excellent reservoir potential. The targets are the same with volumes of 24 MMbbl for the "A" Sands and 75 MMbbl for the "US" sands. o   Eridal, Efital and Mujia are considered as optional drilling targets in R3 block. They cover a surface of around 12 sq km. The targets are the same with volumes of 15 MMbbl, 75 MMbbl and 47 MMbbl respectively for the "A" Sands and 28 MMbbl, 60 MMbbl and 59 MMbbl respectively for the "US" secondary target. -        R1 block area (DRILLING PLANS CANCELLED BY SAVANNAH IN DECEMBER 2017): o   The Damissa and Mena prospects will be evaluated once the seismic is done. They are located in the southern part of the R1 block and have volumes of 85 MMbbl and 54 MMbbl respectively for the "A" Sands and 55 MMbbl and 16 MMbbl respectively for the "US" secondary target. o   Kiski is considered as optional drilling target in the R1 block. It hosts volumes of 19 MMbbl for the "A" Sands while the “US" secondary target has not yet been evaluated. Note: Volumes are given as unrisked mean recoverable resources with an estimated recovery factor of 30% (CGG Robertson, December 2017). The drilling operations will be performed through three phases: the first phase will consist on the drilling itself and logging of the targets. In case of suspended well, a dedicated cheaper rig will test the reservoirs in the phase two. If satisfactory results, a workover rig will complete the well for future production in phase three. The drilling will take between 35 and 40 days on each prospect with a 7 to 10 days transition period. Total depths will range between 2,100 m and 2,600 m. GWDC is the drilling company in charge and is a subsidiary of China National Petroleum Corporation (CNPC) which holds the operatorship in Niger's Agadem, Bilma and Tenere permits. Savannah in Niger: timeline Savannah was awarded the Exclusive Exploration Authorization for the Agadem R1, R2 blocks on 4 August 2014. Signature bonus amounted to USD 42 million. Between November 2014 and February 2015, Savannah acquired an airborne Full Tensor Gravity (FTG) survey by the Arkex aircraft. On 14 May 2015, Savannah reported that it had interpreted 680 sq km of 3D seismic data in the south western part of the Agadem R1 block, leading to 14 drill-ready prospects. The survey covered approximately 8% of the whole R1, R2 permit. In July 2015 the R3/R4 licence was awarded to Savannah. On 30 September 2015, Savannah reported that the restart of exploration activity might be subject to the introduction of a partner. In July 2015 the company received approvals from the Ministry of Environment to acquire new seismic surveys and drill new exploration wells over the R1, R2 permit. Upon initial geological evaluation, Savannah identified 29 leads on the R3, R4 licence. On 17 February 2016, Savannah reported that it signed a contract with BGP Niger SARL to acquire some 2D and 3D data over the R1, R2 and R3, R4 permits. The start of the acquisition was scheduled for the first half of 2016. On 24 January 2017, Savannah reported that it had completed the acquisition of an 800 sq km 3D seismic survey over a portion (800 sq.km) of its R3 licence area. The survey was completed two weeks ahead of schedule and on budget. On 11 April 2017, Savannah confirmed that its three-well drilling programme will be focused on the R3 PSC area. The company would use the land rig GW215 which was already in Niger. Savannah also reported that the construction of the logistic camp had already started and that it was still expecting to start drilling the first well before the end of the first half year 2017. On 15 March 2017, Savannah reported that it signed a Letter of Award (LoA) with Great Wall Drilling Company Niger (GWDC) for a three-well drilling programme with the option to drill 6 more in the Block R3. On 4 December 2017, Savannah reported that it had extended its drilling campaign from three to five wells. The two new prospects to drill were Damissa and Mena located in block R1 with total unrisked mean recoverable resources of 101 MMbbl and 50 MMbbl of oil respectively. The company also announced that a seismic survey of approximately 500 sq km was going to be acquired over block R1. Drilling was planned to start in early 2018 targeting the Bushiya, Amdigh and Kunama prospects using the GWDC 215 rig at a cost of USD 6 to 8 million per well. On 20 December 2017, Savannah announced that regarding several changes with respect to the transaction with Seven Energy, it had decided to drill only the initially planned three prospects in Niger and not to acquire the additionally planned 3D seismic over block R1 in 2018. It was understood that the prospects not to be drilled in 2018 were Damissa and Mena, located in block R1. On 3 April 2018, Savannah announced that the drilling of its first prospect Bushiya in R3 block had started on 31 March 2018. The well Bushiya 1 primarily targeted the Alternance Sokor "A" Sands with the Upper Sokor Sands “US” as secondary target which was considered to be upside (see below for more information). The prospect had estimated total mean unrisked recoverable resources of 36 MMbbl.

Bushiya 1, op. by Savannah Petr. (100%) 1st of multi-well programme, R3 East area, in SE Niger, TD=2200m, results based on interpretation of available data set (wireline logs, fluid sampling + pressure data) indicate an estimated 10m net oil sandstones were encountered across 3m + 7m intv’s in the target Eocene Sokor Alternances. Testing planned, following which a reserves estimate will be determined.

On 22 May 2018, local media reported that Kuwait Energy Company KSCC (Kuwait Energy) is looking to divest its assets in Egypt and Iraq. The company hired Perella Weinberg Partners investment bank as the adviser for the sale and spin off Egypt assets. Kuwait Energy is looking for liquidity to pay back shareholders and creditors. The company owes USD 290 million due in 2019 and should start repayment of a convertible loan of USD 150 million during 2018 to Abraaj Group. Kuwait Energy’s Egypt interests are Abu Sennan - Abu Sennan, Abu Sennan GPZZ (KEE) (Dev), Abu Sennan H (KEE) (Dev), Al Zahraa (Dev), Burg El Arab North (Dev), Burg El Arab South (Dev), Diaa (Dev), East Umm El Yusr, Ghard (Dev), Kareem (Area A) Kheir (Area A), Rana (Dev), Shahd (Dev), Shahd South East (Dev), Shebl (Dev) - Shukheir (Area A), and Umm El Yusr (Area A). The company is looking to sell part or all its interests in Block 9 in Iraq. Talks for a possible merger with the UK’s SOCO international plc (SOCO) were terminated in March 2018.

Egypt, Al Zahraa (Dev)

An Oct ’18 agreement by Cue to sell 15% in WA-359-P and 5.36% in WA-409-P, Carnarvon Basin, to NZOG was cleared 9 Jan ’18.  to New Zealand Oil and Gas Ltd (NZOG) on 9 January 2019.  This marks a milestone towards completing the sale of equity. A similar move by BP and Beach is pending clearance.  Partners will become BP (op), Cue, Beach + NZOG. Details from GEPS.

An Oct ’18 agreement by Cue to sell 15% in WA-359-P and 5.36% in WA-409-P, Carnarvon Basin, to NZOG was cleared 9 Jan ’18. to New Zealand Oil and Gas Ltd (NZOG) on 9 January 2019. This marks a milestone towards completing the sale of equity. A similar move by BP and Beach is pending clearance. Partners will become BP (op), Cue, Beach + NZOG.

Lundin reported in early March 2020 that it will acquire Neptune's 20% interests in PL 886 and PL 886 B, subject to government approval. PL 886 covers blocks (or parts of) 6306/6, 6306/8 and 6306/9 and PL 886 B lies adjacent to the northeast, covering parts of blocks 6307/1 and 6307/4. Lundin plans to drill a well on the Melstein prospect, which is targeting a new play with potential recoverable reserves of 160 MMboe, in PL 886 in Q4 2020. It is also understood that there is a prospect in PL 886 B called Tarva, but no drilling plans have yet been released for this. The closest field to these licences is Fenja where development is progressing towards an onstream date of 2021. The company will develop the Pil accumulation initially, using a subsea tieback to the Njord A platform. Recoverable reserves are approximately 97 MMboe. The project will use two subsea templates hosting three horizontal producers, two water injectors and a single gas injector. Bue represents upside and will be confirmed by Pil development wells before it is potentially brought into production at a later date. Oil will be processed on Njord A before being transferred to Njord B for onward export via shuttle tanker. Gas will initially be re-injected into the Pil reservoir and will later be exported via Njord’s connection to the Asgard Transport System. According to the impact assessment from June 2017, oil production is expected to peak at approximately 42,000 bo/d in 2023 with gas production expected to peak at approximately 100 MMcf/d between 2025 and 2036. Total investment costs are approximately NOK 10.2 billion (USD 1.22 billion), with 16-year life forecast. Upon completion of the deal, PL 886 and PL 886 B interests will be divided between Lundin Norway AS (60% + operator), Petoro AS (20%) and Spirit Energy Norway AS (20%).

Lundin is to acquire a 10% stake from Wintershall Dea in PL 894 (Voring) and 5% interests in PL 533 and PL 533 B (Barents Sea).

Conrad Petroleum has upgraded Contingent Resources estimation for the Mako field in the Duyung PSC, located in the West Natuna Basin. Partners Empyrean Energy and Coro Energy reported on 14 April 2020 the results of a new internal assessment conducted by the operator following the successful appraisal drilling campaign conducted in Q4 2019. The new evaluation resulted in significant upgrades over the previous third-party evaluation completed in January 2019, prior to the appraisal drilling. Mid-case Contingent Resources (2C) are now estimated at 493 Bcf, a 79% increase from the previous estimate of 276 Bcf. The field development modeling has also been updated, with production capacity increased to 150 MMcfg/d compared to the previous scenario of 44 MMcfg/d. The partners are likewise awaiting for the results of a new third-party resources assessment which was commissioned after the drilling campaign. The results are expected to be slightly delayed, due to the current travel restrictions related to the coronavirus disease 2019 (COVID-19). The upgraded resources will likely require an update of the Plan of Development (POD) which was originally approved in March 2019. A Heads of Agreement with a Singapore gas buyer is likewise in place. Going forward, key milestones will include POD revision and finalization of a Gas Sales Agreement (GSA), prior to proceeding with Final Investment Decision (FID) on the field development. Details on the updated resources estimations are shown in the table below. Contingent Resources categories Previous estimate, January 2019 (Bcf) Updated estimate, April 2020 (Bcf) Increase (%) 1C 184 323 76 2C 276 493 79 3C 392 666 70   The drilling campaign conducted in late 2019 consisted of two wells, Tambak 1 and Tambak 2, which confirmed the presence of an extensive gas reservoir across the Mako structure. The first well in the campaign, Tambak 2, was drilled in October 2019. The well intersected approximately 10 m of Muda Formation sandstones, but did not flow due to formation damage sustained following a gas kick and mud loss. Tambak 1, drilled in November 2019, tested 11.4 MMcf/d of dry gas from the Muda Formation between 389 and 391 m TVDSS. Participants in the Duyung PSC are Conrad Petroleum (76.6%, operator), Coro Energy (15%) and Empyrean Energy (8.5%). Coro initially announced the 15% acquisition from Conrad and Empyrean in February 2019. The contract was converted from cost recovery to Gross Split terms in January 2019. Background Information The Duyung PSC was originally awarded to Transworld (100%) in January 2007. The block was offered under the direct mechanism during the second phase of the "Fifth Round" of Migas-controlled acreage releases which opened on 15 August 2006. A signature bonus of USD 1.5 million was paid and firm commitments included G&G studies worth USD 1 million, acquisition of 400 sq km 3D seismic data and drilling one exploration well. The seismic commitment was conducted from late 2008 to early 2009 using PGS's 'Orient Explorer’ vessel. Around 360 sq km of data was acquired. WNEL acquired 100% interest in the block in 2013. In September 2015, WNEL had agreed to farm out 85% interest to Hague and London Oil, however the agreement was terminated as of 1 April 2016 due to lack of the necessary regulatory approvals. On 12 May 2017, Empyrean reported the completion of the first stage of a proposed deal with Conrad Petroleum for the acquisition of a 10% stake in WNEL for an initial consideration of USD 2 million, pursuant to a Sale and Purchase Agreement (SPA) signed on 4 April 2017. Under the terms of the SPA, Empyrean had the option to pay further cash consideration of USD 2 million that would grant the company an additional 10% interest in WNEL. However, Empyrean reported on 30 May 2017 that it would not proceed to acquire the additional 10% interest, thus retaining only the initial 10% stake in WNEL while Conrad Petroleum retained the remaining 90% stake plus operatorship. The Mako structure is estimated to have a lateral extent of 304 sq km with tested reservoir of approximately 7 m of fine sand layer within the Intra Muda Formation. In August 2018, Empyrean reported that modeling studies on the field indicated estimated gas initially in place (GIIP) of 705 Bcf, with upside potential case of 1,317 Bcf. The company at the time also reported recoverable contingent resources of 433 Bcf (2C) and 646 Bcf (3C). The structure was originally drilled in 1999 by Lasmo with wildcat Mako 1, which encountered 7 m gas-bearing sandstones from logs, but was not tested. The structure was reinvestigated in mid-2017 by WNEL, with Mako South 1. The well flowed gas at a stabilized rate of 10.9 MMcf/d, with no CO2 recorded. According to the operator, test results indicated a laterally continuous reservoir with permeability in the order of multi-Darcy. The well reached a depth of 1,330 feet (approximately 405 m) on 19 June 2017.

Results of recent appraisal work (Mako field) (Conrad 76,5% op, Coro Egy 15%, Empyrean 8,5%) in the Duyung PSC offshore, have led to a 79% increase in est. gas resources to 493 Bcfg recov. Tambak 1 last year had tested up to 11.4 MMcf/d dry gas from 24m of sst in the Intra-Muda (only 7.3m in Mako S.-1). Up to 150 MMcf/d plateau could now be achieved, up from 44 MMcf/d earlier believed.

Santos Ltd and JX Nippon Oil and Gas Exploration completed the sale of interest in exploration permit WA-498-P, located in the North Carnarvon Basin, to Skye Alba Pty Ltd, on 14 December 2018.  Skye Alba, through wholly owned subsidiary Skye Energy Pty Ltd is now sole owner and operator of the permit. The sale and purchase agreement between the companies was entered into on 1 March 2018.  Prior to the dealing, Santos held 75% and operatorship, while JX Nippon held the remaining 25%.  The companies had been looking to divest interest in a number of North Carnarvon basin permits, including WA-498-P. No wells have yet been drilled in the permit’s validity, though it does contain one previously drilled well – Bligh 1, which was plugged and abandoned as a dry hole in 2002. There is one well outlined under the permit’s work programme, scheduled between April 2019 and April 2020.  The permit is due to expire, or be eligible for renewal, on 15 April 2020. WA-498-P, which covers an area of 81 sq km, saw an interest change completed as of 14 December 2018.  Skye Energy Pty Ltd now holds 100% interest and operatorship of the permit.

Skye acquired Santos’s 75% operating interest and JX Nippon’s 25% participating interest in WA-498-P block.

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.

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.

On 18 May 2020, CNOOC offered 15 blocks with a total area of 9,453 sq km for the CNOOC 2020 Offshore China Open Block Tender. The 15 blocks comprise one block covering 127 sq km in the Bohai Gulf Basin, one block covering 1,784 sq km in the East China Sea Basin, 10 blocks with a total of 5,890 sq km in the Pearl River Mouth Basin, two blocks with a total of 1,252 sq km in the Qiongdongnan Basin and one block covering 400 sq km in the Yinggehai Basin. The data room will run from 18 May-30 September 2020 with the tender closing on 31 October 2020. Interested parties can contact Ms Zhanglei at <A HREF="mailto:[email protected]">[email protected]</A> for further information.

On 18 May 2020, CNOOC offered 15 blocks with a total area of 9,453 sq km for the CNOOC 2020 Offshore China Open Block Tender. The 15 blocks comprise one block covering 127 sq km in the Bohai Gulf Basin, one block covering 1,784 sq km in the East China Sea Basin, 10 blocks with a total of 5,890 sq km in the Pearl River Mouth Basin, two blocks with a total of 1,252 sq km in the Qiongdongnan Basin and one block covering 400 sq km in the Yinggehai Basin.

Based on local sources on 12 June 2020, Shell drilled the Max 1 EXP directional new-field wildcat (NFW) in the CNH-R02-L04-AP-CS-G02/2018 contract, Area 21 Block in the ultra-deep-water Campeche Deep Sea Basin, spudded on early May 2020. Shell is operator of the contract and holds 60% working interest and Chevron holds 40% working interest. The NFW had a proposed total depth (PTD) of 7,480 m measured depth (MD) and 7,332 m true vertical depth (TVD) and was planned as a Type S directional with a maximum inclination of 22.46° in the section 3,690-4,026 m, Lower Miocene and Upper Oligocene, and then drill back to vertical below 4,026 m. The primary target was the Upper Jurassic Oxfordian from approximately 6,970 m to 7,100 m with the analog being the Jurassic Norphlet in the northern Gulf of Mexico or the productive reservoir in the Ek-Balam fields in the Sureste Basin. The rank NFW is in the north-eastern area of the block, nearest well is Chibu 1EXP located approximately 31.2 km north-west and the nearest historical well is the Tamha 1 plugged and abandoned (P&A) by PEMEX in 2008 located140 km south. The prospect trap is a north-east south-west oriented, salt nucleated anticline. The Max prospect has estimated unrisked prospective resources of 291 MMboe with 14% of Geological Chance of Success. The hydrocarbon expected is oil 26° API. The "Deepwater Thalassa" D/S drilled the well in a water depth of 2,511 m. The drilling cost for the well was estimated to be USD 84.8 million and the abandonment cost was estimated to be USD 7.0 million. On 7 May 2018, Shell was granted an official award for the CNH-R02-L04-AP-CS-G02/2018 contract, the 2,048.35 sq km, Area 21 block (alternate block name AP-CS-G01). On 13 June 2019, Shell was granted approval by the CNH for the first exploration plan related to the CNH-R02-L04-AP-CS-G02/2018 contract, Area 2, that includes geophysical and geological studies as well as the drilling of one firm commitment exploration well with an incremental case of drilling a second exploration well. On 13 February 2020, Shell was granted approval by the CNH to drill the Max 1EXP directional new-field wildcat (NFW),

Mexico (Campeche Deep Sea B.) Max 1EXP op. by SHELL (60%), CVX (40%) in Area 21 block (aka P-CS-G02), WD = 2511 m, ops recently concluded, rumoured unsuccessful. PTMD was 7,480m (7,332m TVD), main target oil in Oxfordian (Norphlet),

Draupner is offering equity in wholly-owned P2331 (blocks 38/22b, 38/23a, 38/27, 38/28, 44/2 + 44/3a, Balvenie prospect, 490 sq km on the N. Dogger Shlf) and P2487 (blocks 38/21b + 38/22c, Durham prospect, 252 sq km in the Mid NS High) in exchange for coverage of historic costs, work programme participation and/or a cash offer. Contact: Ann-Charlotte Hogberg, email [email protected].

United Kingdom (Anglo-Dutch B.) P2331 op. by DRAUPNER (100%), Draupner is offering equity in wholly-owned P2331 (blocks 38/22b, 38/23a, 38/27, 38/28, 44/2 + 44/3a, Balvenie prospect, 490 sq km on the N. Dogger Shlf) and P2487 (blocks 38/21b + 38/22c, Durham prospect, 252 sq km in the Mid NS High) in exchange for coverage of historic costs, work programme participation and/or a cash offer

Egdon Resources announced on 21 January 2020 that it has agreed a deal with Shell for the latter to farm-in to licences P1929 and P2304 which contain the Resolution and Endeavour gas discoveries. Under the terms of the deal Shell will acquire a 70% interest in the licences in return for funding 85% of the costs for the acquisition and processing of a 3D survey over the discoveries up to USD 5 million. Shell will also pay for all studies and costs included in a well investment decision on the licences. Completion of the deal is subject to regulatory approval. In April 2019 Egdon announced the results of a Competent Person's Report (CPR) prepared by Schlumberger Oilfield UK Plc which stated that the Resolution gas discovery is estimated to contain Contingent mean Gas Resources of 231 Bcf with a P90 to P10 range of 389 Bcf. Egdon plans to shoot 3D during spring 2020 subject to a successful farm-out. Following this the plan would be to drill and test an appraisal well on Resolution prior to a potential field development. In an update on 27 November 2019 Egdon reported that the OGA has approved six month licence extensions to P1929 and P2304 until 31 May 2020. In return for the extension Egdon must demonstrate to the OGA that a farm-in agreement has been executed by 31 January 2020 and that by 31 March 2020 the OGA is satisfied that Egdon and partner(s) is on track to deliver a 3D seismic programme over both licences. Resolution is a dip and fault closed structure defined on reprocessed 2D seismic. Resolution will be appraised with an offshore well because the well cost is comparable with an onshore to offshore well and has a lower delivery risk. Egdon will develop Resolution via offshore well head platformed linked via pipeline to an onshore gas processing facility. The main risk is thought to be the ability to produce gas from relatively tight carbonate. Total drilled well 41/18-2 in block 41/18 in 1966 and made a gas discovery which flowed 2.5 MMcf/d from Permian Hauptdolomit fractured carbonates. Interest in licences P1929 and P2304 is held solely by Egdon Resources UK Ltd. For further details please contact: Martin Durham Email: [email protected]

Egdon Resources announced on 21 January 2020 that it has agreed a deal with Shell for the latter to farm-in to licences P1929 and P2304 which contain the Resolution and Endeavour gas discoveries.

As of 1 July 2019, Oil Search Ltd., continues looking for a partner for development of the Pikka Unit on the North Slope of Alaska. The Pikka Unit was formed following the discovery of oil across three separate zones in multiple wells drilled over a three-year period by Repsol which included oil discoveries in the Cretaceus age Nanushuk and Kuparuk formations as well as the Jurassic age Alpine Formation. A data room was set up in the summer of 2018 with several companies expressing interest in farming into the project as of March 2019 the data room remained open. Oil Search became operator of the project through a farm-in with majority interest holder Armstrong in late 2017 and obtained a majority working interest through a recent transaction through the exercising of an option for additional working interest. Repsol still holds a large working interest in the unit but has agreed with Oil Search to seek an additional partner to help fund the development of the Unit in an effort to commence production by 2023.

Oil Search Ltd., continues looking for a partner for development of the Pikka Unit on the North Slope of Alaska. The Pikka Unit was formed following the discovery of oil across three separate zones in multiple wells drilled over a three-year period by Repsol which included oil discoveries in the Cretaceus age Nanushuk and Kuparuk formations as well as the Jurassic age Alpine Formation.

Heera ML + field area, Bombay shallow waters, drilled early Feb – early Apr ’19, TD 1,470m, assumed P&A, Greatdrill Chaaya JU off location 9 April.

Heera SS-3 appr Heera ML + field area, Bombay shallow waters, drilled early Feb – early Apr ’19, TD 1,470m, assumed P&A.

On 27 March 2018, the CNH concluded the successful CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) for 35 shelf blocks granting preliminary awards for 16 blocks out of 35 on offer covering a total provisionally awarded area of 11,158 sq km.  Companies made a total of 36 bids, dominated by bidding for all of the Sureste Basin blocks.  Companies also bid a total of nine additional wells as commitments, again all in the Sureste Basin.  Total estimated work commitments value for the round was USD 425.42 million, and there were three tie-break bonus bids made by companies that garnered the government USD 124.05 million. PEMEX dominated Ronda 3.1 winning four blocks as operator and three blocks as a partner in various consortia.  It also placed the largest number of bids individually or in consortia with 11.  Other companies who bid aggressively and won two or more blocks were CEPSA, DEA, Pan American, Premier, Repsol, and Total.  Sapura made its entry into Mexico winning the highly contested Block 30 in the consortium with DEA and Premier.  There were four companies that placed bids but failed to win a block including ECP, Galem, Inpex, and PC Carigali. In the Burgos Basin there were four of 14 blocks in the Burgos Basin bid on and granted preliminary awards, two to Premier Oil and two to Repsol all with 100% working interest and no additional work units bid.  There was only one second bid for the Area 5 block by PEMEX but it lost its bid to Repsol who bid 56.27% state take and no additional work factor compared to the PEMEX bid of 23.89% state take and no additional work units. In the Tampico-Misantla-Veracruz Basin there were also four of 13 blocks bid on and granted preliminary awards, one to the consortium of Capricorn and Citla, two to the consortium of PEMEX, DEA, and CEPSA, and one to the consortium of PEMEX and CEPSA.  There were no additional work units bid nor second bids for any of the blocks. In the Sureste Basin eight blocks on offer were bid on and granted preliminary awards.  There were second bids for all of the blocks.  The most contested block in the round was the Area 30 block with a total of seven bids, five of the bids offering the maximum state take of 65% and tie-break bonuses.  The consortium of DEA, Premier, and Sapura won the block with a tie-break bonus of USD 51.15 million versus the second place bid by ENI and Lukoil of USD 46.87 million.  The highest tie-break bonus in the round was made by PEMEX who won the Area 28 block with a tie-break bonus of USD 59.82 million. CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) - Preliminary Results – 27 March 2018     Area Basin CNH-Block Name Area sq km Number of Bids State Participation Bid % Add Work Factor Bid - 0, 1 = 1 well, 1.5 = 2 wells Total Est Work Unit Value USD Tie-Break Bonus USD Winning Consortium or Company 2nd Bid Consortium or Company 2nd State Part % 2nd Bid  Additional Work Factor 2nd Bid Tie-Break Bonus USD 5 Burgos G-BG-05 814                           2                                      56.27                                    -                                      2,227,896    Repsol PEMEX                   23.89                          -     11 Burgos AS-B-57 391                            1                                      29.47                                    -                                        1,125,432    Premier         12 Burgos G-BG-07 811                            1                                       48.17                                    -                                       2,221,632    Repsol         13 Burgos AS-B-60 392                            1                                      34.73                                    -                                        1,127,520    Premier         15 Tampico-Misantla-Veracruz G-TMV-01 962                            1                                      27.88                                        2,614,176   Capricorn, Citla         16 Tampico-Misantla-Veracruz G-TMV-02 785                            1                                      24.23                                    -                                       2,152,728   PEMEX, DEA, CEPSA         17 Tampico-Misantla-Veracruz G-TMV-03 842                            1                                       35.51                                    -                                      2,303,064   PEMEX, DEA, CEPSA         18 Tampico-Misantla-Veracruz G-TMV-04 813                            1                                       40.51                                    -                                      2,226,852   PEMEX, CEPSA         28 Sureste G-CS-01 808                           5                                      65.00                                     2                                  89,908,236                    59,823,145  ENI, Lukoil DEA, Premier                   65.00                      1.00                  14,170,000.50 29 Sureste AS-CS-13 471                           4                                      65.00                                     2                                   89,028,144                    13,075,075  PEMEX DEA, Premier, Sapura                   65.00                      1.00                                         -   30 Sureste AS-CS-14 528                           7                                      65.00                                     2                                   89,178,480                     51,147,000 DEA, Premier, Sapura ENI, Lukoil                   65.00                      1.50                46,869,235.00 31 Sureste AS-CS-15 401                           3                                      65.00                                      1                                  44,999,532   Pan American ENI, Lukoil                   42.35                      1.00                                         -   32 Sureste G-CS-02 1,027                           2                                      40.49                                    -                                      2,785,392    Total, PEMEX Sapura, Galem                    30.16                      1.00   33 Sureste AS-CS-06 581                           2                                      50.49                                      1                                  45,468,288    Total, PEMEX ENI, Lukoil                   40.35                          -     34 Sureste G-CS-03 734                           2                                      50.49                                      1                                   45,868,140   Total, BP, Pan American Shell, PEMEX                   40.36                          -     35 Sureste G-CS-04 798                           2                                      34.86                                    -                                        2,187,180   Shell, PEMEX Total, BP, Pan American                   30.49                          -       Totals                       11,158                         36                                       9                               425,422,692                  124,045,220               Source: IHS Markit     © 2018 IHS Markit                   CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) – Preliminary, Estimated Company Results Summary until Working Interest Breakdown Officially Reported – 27 March 2018 Company NAWI Est NWI Work Units + Tie-Break Bonus USD Blocks Operator Blocks Partner Number of Bids Individually or in Consortia  PEMEX       2,633.68                                    129,952,044.28                                             4                                             3 11  ENI          404.00                                     74,865,690.50                                              1   4  Lukoil          404.00                                     74,865,690.50                                                1 4  Pan American          643.22                                       60,136,018.20                                              1                                              1 4  DEA           716.43                                       49,181,074.65                                              1                                             2 5  Premier          957.24                                     48,560,360.48                                             2                                              1 5  Sapura           174.24                                     46,307,408.48                                                1 3  Total        1,053.56                                     39,722,007.60                                             3   6  BP          242.22                                       15,136,486.20                                                1 2  Repsol        1,625.00                                        4,449,528.00                                             2   5  CEPSA           943.41                                        2,583,837.36                                               3 3  Capricorn           481.00                                         1,307,088.00                                              1   2  Citla           481.00                                         1,307,088.00                                                1 2  Shell          399.00                                         1,093,590.00                                              1   2  Grand Total       11,158.00                                    549,467,912.25                                            16                                            14   Source: IHS Markit   © 2018 IHS Markit          CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) - Preliminary Results Map – 27 March 2018  

Mexico, Area 28

Nexen has acquired a 25% interest in Frontier Exploration Licences (FEL) 5/18 and 6/18 from ExxonMobil. In return for the interest in the licences, ExxonMobil has taken a 50% interest in FEL 3/18 which contains the Iolar prospect, slated for drilling next year in 2019. It is understood that the deal completed in September 2018. Iolar is planned to be drilled in Q2 2019 with the Stena IceMax drillship. FEL 3/18, previously known as LO16/7, covers an area of approximately 1,300 sq km and is located immediately west of FEL 2/14 where Providence drilled the Druid / Drombeg exploration well in 2017.   Interest in FEL 3/18 is now held by Nexen Petroleum UK Limited (50% + operator) and ExxonMobil Exploration and Production Ireland (offshore south) Limited (50%). Interest in FEL 5/18 and FEL 6/18 is now held by ExxonMobil Exploration and Production Ireland (offshore south) Limited (25% + operator), Equinor UK Ltd (50%) and Nexen petroleum UK Limited (25%).

Nexen has acquired a 25% interest in Frontier Exploration Licences (FEL) 5/18 and 6/18 from ExxonMobil. In return for the interest in the licences, ExxonMobil has taken a 50% interest in FEL 3/18 which contains the Iolar prospect,Interest in FEL 3/18 is now held by Nexen Petroleum UK Limited (50% + operator) and ExxonMobil Exploration and Production Ireland (offshore south) Limited (50%). Interest in FEL 5/18 and FEL 6/18 is now held by ExxonMobil Exploration and Production Ireland (offshore south) Limited (25% + operator), Equinor UK Ltd (50%) and Nexen petroleum UK Limited (25%).

Novatek has won an open auction to acquire a 100% stake in Maretiom Investments Ltd, owner of Geotransgaz, and 100% of Velarion Investments Ltd, owner of Urengoy Gas Co, from Alrosa (ref. DEA 21 Dec ’17). The deal has a price tag of USD 537 MM. Geotransgaz holds the producing Beregovoye field in the Nadym-Taz Province (3.5 Tcfg + 131 MMbc 3P).   Urengoyskaya Gazovaya Kompaniya (UGK) runs the Ust-Yamsoveyskiy licence nearby, 1,657 sq km encompassing the Ust-Yamsoveyskoye gas/cond discovery and part of the Urengoyskoye field (2.7 Tcfg + 69 MMbc 3P).  

Novatek has won an open auction to acquire a 100% stake in Maretiom Investments Ltd, owner of Geotransgaz who holds the producing Beregovoye field in the Nadym-Taz Province (3.5 Tcfg + 131 MMbc 3P).

Uganda’s 2nd round is reportedly open, 5 blocks totalling 4,928 sq km:  Avivi (1,028 sq km), Kasurubani (1,285 sq km), Ngaji (1,230 sq km), Omuka (750 sq km) + Turaco (635 sq km) in the Albertine Graben. Promotional meetings are planned in London on 14 October, Houston on 17 October and Dubai on 22 October. Contact: Ikechi Vera Maduako (Schlumberger), email [email protected]. Official map below.

Uganda’s 2nd round is reportedly open, 5 blocks totalling 4,928 sq km: Avivi (1,028 sq km), Kasurubani (1,285 sq km), Ngaji (1,230 sq km), Omuka (750 sq km) + Turaco (635 sq km) in the Albertine Graben. Promotional meetings are planned in London on 14 October, Houston on 17 October and Dubai on 22 October.

In late-April 2018, state company ANCAP officially declared the Uruguay Round 3 offshore bid round void after the deadline passed with no bids received. It was said that Tullow Oil (operator of Area 15 offshore block) and AziLat Petroleum submitted their documentations to qualify as operators before 6 April 2018, although no economic offers were received when the deadline passed on 26 April 2018. ANCAP is reportedly considering modifying the blocks and the terms for the future. The bid round started with a road show presented by representatives of the company and the Uruguayan Ministry of Energy in Houston, Texas in September 2017. There were 17 blocks offered, covering the offshore basins of Pelotas, Rio Salado, and Argentina Basin with areas ranging from 2,500 to 6,500 sq km. Most of the blocks are situated in shelf to deep water with depths ranging from 50 m to 3,500 m, along with few additional blocks located in ultra-deep water over 4,000 m deep. Background Information The announcement for Uruguay Round 3 was originally expected to take place in late-2014 but has been delayed several times, reportedly due to the low oil price situation.  Spectrum concluded a multi-client 3,600 km 2D seismic survey in the ultra-deep water Federal Open area of the Pelotas Basin during November 2014 to January 2015 in preparation for the bid round. This survey complements the multi-client Spectrum Recon 2D survey acquired in the same area in 2013 covering 1,625 km.

Uruguay, Area 15

It was reported in May 2018 that OMV (Pakistan) Exploration has assigned its full 20% interest in the Harnai EL (Sulaiman Foldbelt) onshore concession to Mari Petroleum Company Ltd (MPCL) and it would be effective from 20 June 2015. As a result, the revised equity split in the block is as follows: MPCL 60% (operator) and Pakistan Petroleum Ltd (PPL) 40%. This is a part of OMV’s decision of leaving the country - OMV had announced on 28 February 2018 that it signed an agreement with United Energy Group Ltd (UEG) for selling its upstream business in Pakistan to Dragon Prime Hong Kong Ltd which is a subsidiary of UEG. The sale price was agreed as USD 193 million (EUR 157 million) and the transaction is expected to be completed by the end of 2018 after relevant regulatory approvals. The farm-out process for Harnai block was initiated in early 2017, before the signing of deal with UEG. The Harnai block covers an area of 2,483 sq km and it is located in the Pishin, Ziarat, Sibi and Loralai districts of the Balochistan province.   Background Information Harnai EL was exclusively awarded to Mari Gas Co Ltd (MGCL) on 21 June 2006. MPCL was previously known as Mari Gas Company Ltd (the name was changed with effect from 19 November 2012). Only one well is known to have been drilled on the acreage to date - Chappar Rift 1, which was P&A at a depth of 95 m by Oil India Ltd (OIL) in 1916. The work programme for the initial three-year exploration phase, together with the simultaneously awarded Hanna EL and Sujawal EL, is believed to include G&G studies, 300km geological fieldwork, 300km 2D seismic acquisition, 200 sq km 3D seismic acquisition and the drilling of two exploration wells (with a minimum financial commitment of USD 13.62 million). MGCL assigned a 40% working interest in the block to MND E&P Ltd with effect from 6 April 2007 and only one well is known to have been drilled on the acreage to date - Chappar Rift 1, which was P&A at a depth of 95 m by Oil India Ltd (OIL) in 1916. MGCL subsequently assigned a 20% working interest to OMV (Pakistan) Exploration with effect from 6 December 2008, as a result of which the revised equity split was as follows - Mari Gas Co Ltd (MGCL) (40%, operator), MND E&P Ltd (40%) and OMV (Pakistan) Exploration (20%). MGCL was granted a one-year extension to the second contract year of the license with effect from 21 June 2008. A further one-year extension was granted to the second contract year with effect from 21 June 2009, followed by another 12-month extension effect from 21 June 2010. MGCL was granted an additional 12-month extension to the second contract year of the Harnai EL with effect from 21 June 2011. MGCL changed its name to Mari Petroleum Company Limited (MPCL) with effect from 19 November 2012. Pakistan Petroleum Ltd Europe (PPL Europe) acquired MND Exploration and Production Ltd (MND E&P) on 9 April 2013 as a result the revised equity split was as follows: Mari Petroleum Company Limited (MPCL) (40%, operator), PPL Europe (40%) and OMV (Pakistan) Exploration (20%). Mari Petroleum Company Ltd (MPCL) was granted an additional 24-month extension to the second contract year of the Harnai EL with effect from 21 June 2012. A further 24-month extension was granted to the second contract year of the Harnai EL from 21 June 2014 to 20 June 2016 which was followed by an additional 12-month extension, effective 21 June 2016. The company had planned to conduct a 150 line km 2D seismic acquisition over the block during 2016 but it was subsequently believed to have been dropped as no activity was initiated by June 2017. MPCL was granted an additional 12-month extension to the second contract year of the Harnai EL from 21 June 2017 to 20 June 2018.

Pakistan (Mari-Kandhkot High (Jaisalmer B.)) Mari

PEMEX suspended with results unreported the Cibix 1EXP new-field wildcat (NFW) in the AE-0056-2M-Mezcalapa-06 entitlement during March 2018.  The NFW was spudded on 8 August 2017 but may have been suspended for several months until December 2017.   The well had a proposed total depth (PTD) of 3,955 m and the primary target was the Upper Miocene at two objectives depths, 2,410 m and 2,860 m. On 22 June 2017 the CNH approved a PEMEX request to drill the Cibix 1EXP new-field wildcat (NFW) in the AE-0056-M-Mezcalapa-06 entitlement after receiving approval to modify its work commitments for the block. The Cibix 1EXP has prospective resources of 13 MMboe.  The prospect is located in a fault block associated with a large regional listric fault.  The proposed target is located in one of the small subsidiary fault compartments.  It is located about 3km north of the Navegante field.  The estimated drilling and completion cost for the well is USD 8.4 million. On 21 June 2017 the CNH approved a PEMEX request to modify the exploration plan for the AE-0056-M-Mezcalapa-06 entitlement.  PEMEX proposed modifications to its work commitments that includes the operator drilling the Cibix 1 new-field wildcat (NFW) in the block and re-processing 960 sq km of 3D seismic instead of acquisition of 156 km of 2D seismic and 285 sq km of 3D seismic.  With the modified plan PEMEX will actually decrease its total investment in the block from the original agreed to work commitments from MXN 1,095 million to MXN 920 million but will have an extra well in the plan from one to two.  PEMEX plugged and abandoned dry the Japoka 1 NFW in the block in 2016.  The entitlement will presumably change to the AE-0056-2M-Mezcalapa-06 indicating the second modification to the entitlement once final, formal approvals are granted by SENER. SENER awarded the AE-0056-2M-Mezcalapa-06 Entitlement to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 974.04 sq km.  

PEMEX suspended with results unreported the Cibix 1EXP new-field wildcat (NFW) in the AE-0056-2M-Mezcalapa-06 entitlement during March 2018.

On 29 March 2018, Petrobras with 100% working interest was granted a preliminary award for the POT-M-762 block in the offshore Potiguar Basin through the ANP Round 15. For the POT-M-762 block Petrobras offered a bonus of USD 5.05 million and 110 work units.   There were no other bids for the block.  

Petrobras with 100% working interest was granted a preliminary award for the POT-M-762 block in the offshore Potiguar Basin through the ANP Round 15.

Talos Energy Offshore was officially awarded Viosca Knoll Block VK 867 (G36377) as of 1 November 2018, located in the Louisiana Coastal Basin. The block is expected to expire on 31 October 2031. The block was originally offered as part of OCS Lease Sale 251, which was held on 15 August 2018. The sale garnered 171 bids for 144 tracts in both shallow and deepwater from a total of 29 companies. According to officials, a total of US$ 178,069,406 was received in high bids. Following official award, Talos Energy Offshore is the operator and sole interest-holder (100% WI + Op) in VK 867.

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Ref. DEA 19 Aug ’19, BWE has completed the acquisition from Petrobras of its 70% operating stake in the Maromba heavy oil field (BC-020A, SE Campos Basin shelf, WD 160m). There is also an agreement to take on Chevron’s 30% here. BWE is planning to multiple wells over 3 devt phases. First oil planned 1Q ‘22.

Brazil (East Campos Sub-basin (Campos B.)) Maromba

It was announced on 2 May 2020 that Turkiye Petrolleri A.O. (TPAO) has been awarded the F17-D onshore exploration licence (Thrace Basin) on 21 April 2020 for a period of five-year. The licence, covering an area of 583 sq km, is located towards northwest of the country and TPAO will be 100% owner and operator of the licence. TPAO had submitted the application on 5 December 2019.

Turkey, F17-D

On 7 February 2019, the award of the Szeged DélKelet contract in southeastern Hungary, pre-awarded from the 2018 tender call (Round 6) to Magyar Olaj- es Gazipari Rt (MOL) in late year, was signed off by the Minister of Innovation and Technology and the permit became official. MOL is the sole rightholder of the tract. The 278 sq km Szeged DélKelet area is located within the Nagykunsag, Bihor and Bekes sub-basins, tectonic units of the Pannonian Basin. Background Information The tender call for the Szeged DélKelet block was published in the EU Official Journal on 21 June 2018. The closing date of the tender was 26 September 2018. MOL was selected as the bid winner of the Szeged DélKelet area and the pre-award of the block to MOL was pronounced on 5 December 2018 (the company had 90 days, with a possible extension for further 60 days, to negotiate the contract). The country’s first bid round was pronounced in 2013 and had little success (two awards). Following modifications to the legal and fiscal terms, the tenders conducted in 2014, 2015, 2016 and 2017 attracted significant attention and resulted with the awards of 17 new concessions (awards from the 2017 round were effectuated in January/February 2018). As during the period 2013-17, the opening of the 2018 round was expected in late May/June 2018, with nine areas offered for the hydrocarbon operations and one to two blocks for the hydrothermal energy. In preparation for the licensing rounds, until late 2018, the authorities have earmarked some 35 open areas in the western, central, eastern and northeastern part of the country. As during the period 2013-18, the opening of the next round is expected in late May/June 2019, with some nine areas to be offered for the hydrocarbon operations and one to two blocks for the hydrothermal energy. The tender documents, published in the EU Official Journal, mark the onset of the bid round.

MOL (100%) awarded the Szeged DélKelet contract in southeastern Hungary.

On 31 January 2019, the CNH approved the 30% working interest farm-out by operator CNOOC to PC Carigali in the CNH-R01-L04-A4.CPP/2016 contract, Area 4 block.  CNOOC remains the operator with 70% working interest and PC Carigali has 30% working interest.  CNOOC is planning the drilling of at least one commitment well in the block during 2019. On 24 April 2018, the CNH approved the exploration plan submitted by operator CNOOC for the CNH-R01-L04-A4.CPP/2016, Area 4 block that includes the drilling of one commitment well and conducting geological and geophysical (G&G) studies during the four year exploration phase.  The approved exploration plan includes the drilling of sub-salt new-field wildcat (NFW) Xakpun 1EXP provisionally scheduled for 1st quarter 2019.  The proposed total depth (PTD) is 5,500 m with the Wilcox formation being the primary target at approximately 5,000 m.   The prospect underlies a 2,000 m salt canopy in this area of the basin.  The prospective resources for the well have been estimated to be 323 MMboe with an estimated risked reserves to be incorporated of 135 MMboe.  The prospect water depth is 1,528 m which puts its location somewhere in the east central to southeastern area of the block.  Total well cost was estimated to be USD 160 million.  Total investment in the exploration plan was reported by the CNH to be approximately USD 172 million for 79,511 total work units, the well is 74,300 work units. On 10 March 2017, the CNH signed the official award for an exploration and production license contract with China Offshore Oil Corporation (CNOOC) 100% for the CNH-R01-L04-A4.CPP/2016, Area 4 block the company won through the CNH-R01-L04/2015 Bid Round. The official contract name is CNH-R01-L04-A4.CPP/2016. On 5 December 2016 China Offshore Oil Corporation (CNOOC) was granted a preliminary award as the high bidder for Area 4 - Perdido block through the CNH-R01-L04/2015 Bid Round.  The ratification of the preliminary award was approved by the CNH on 7 December 2016.  The company offered a total of 15.01% additional royalties and 1.00 as the additional work investment factor which is equivalent to one commitment well and a total minimum investment commitment of USD 33.61 million which also includes the minimum investment commitment of USD 3.61 million.  There were no additional bids for the block. The Area 4 - Perdido block covers an area of 1,876.70 sq km in the Deep-Water Gulf of Mexico, Perdido area and the minimum work commitments were set in the bid documents of 3,611 work units.

Mexico (Rio Grande Embayment (Gulf Coast B.)) China

Columbus has acquired a 50% interest in the Icacos field (22 bo/d) on the SW Peninsula from Primera O&G who has withdrawn. The field is now run solely by Columbus subsidiary Leni Trinidad Ltd. The deal was struck for USD 0.5 MM.

Columbus has acquired a 50% interest in the Icacos field (22 bo/d) on the SW Peninsula from Primera O&G who has withdrawn. The field is now run solely by Columbus subsidiary Leni Trinidad Ltd. The deal was struck for USD 0.5 MM.

SE part of block 15/06, W. of Kalimba find in WD 780, Congo Fan, TD 1,723m, 20m net oil pay, 37 API, 170-200 MMbbl OIP, potential 5,000 b/d. Ocean Rig Poseidon DS. The find is significant insofar as this part of the block was previously considered mainly gas-prone. Up to 4 new back-to-back explo wells are planned in 15/06 in 2019.

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

HP/HT exploration sidetrack, Shearwater field in P188, 5” liner set to 5,428m MD (5,289 m VD), well now completed, results n/a, Noble Hans Deul JU. Shell (op), partners ExxonMobil + BP.

United Kingdom (Central Graben Province) ? op. by SHELL (28.0%, EXXONMOBIL 44.5%, BP 27.5%) in Shearwater block

Naushahro Firoz 2668-9 EL, Middle Indus onshore, TD 4,705m (Jurassic), susp. after rigless testing during Feb ’19. PPL (op), partner Asia Resource Oil.

Nusrat X-1 (NFW) (PPL 90%, Asia Resources 10%) within the Naushahro Firoz 2668-9 EL onshore concession, well suspended in February 2019, after carrying out testing. To date a result has not been reported.

Joya Mair D&PL, onshore Potwar Basin, TD 2,675m reached in mid-Mar ’18, on stream Aug ’18 albeit testing a small 26 bo/d, co. SCR-1 rig. Targets Cambrian Khewra sst + Permian Tobra, Eocene Chorgali + Sakesar fm’s.

Joya Mair Deep 1 (POL 82,5%, GHPL 17,5%) in Minwal D&PL, on stream albeit testing a small 26 bo/d, targets Cambrian Khewra sst + Permian Tobra, Eocene Chorgali + Sakesar fm’s. TD=2675m.

TransAtlantic secured sole rights to the M44-B2-1 prod. lease effective 6 Jun ’18 for 5 years.  It covers 152 sq km in the Zagros Fold Belt, SE turkey, around the Pinar and Catak oil discoveries.

TransAtlantic secured sole rights to the M44-B2-1 prod. lease effective 6 Jun ’18 for 5 years. It covers 152 sq km in the Zagros Fold Belt, SE turkey, around the Pinar and Catak oil discoveries.

Vermilion Exploration’s recently released second quarter 2019 report states that new-field wildcat Hajdubagos 1 in the Ebes contract in eastern Hungary encountered 5 m thick net reservoir interval that yielded gas at a rate of 1.4 MMcf/d and 55 bbls/d of 60° API condensate during a 12-hour flow test (stabilised flowing wellhead pressure of 590 psi on 0.374” choke). The test was conducted over a gross interval at depth of 1,986-1,996 m within the Upper Miocene Pannonian sandstone succession. Formation water was absent. The well was solely operated by Vermilion. Hajdubagos 1 was likely during March/April 2019. The well is located in the southernmost part of the contract, approximately 100 km east of the capital city of Budapest, within the Bihar sub-basin, tectonic unit of the Pannonian Basin. The well had a planned final depth estimated to be 2,000 m, targeting the Lower Pannonian sandstone series. Hajdubagos 1 was drilled to the final depth of 2,045 m in the turbiditic Algyo Formation. The news on the successful testing of Hajdubagos 1 was disclosed on 29 July 2019. Background Information Hungarian government awarded the 832 sq km Ebes contract in the Hajdú-Bihar political province to Vermilion Energy in mid-February 2015. The award completed the country’s 2014 tender call. The tender call for the prospection, exploration and production of hydrocarbons over six blocks in four geographic areas - Debrecen (split into areas Nadudvar (western) and Ebes (eastern)), Ujleta (953 sq km), Okany (split into eastern and western blocks) - all located in the eastern Hungary - and Nagylengyel Nyugat located in western Hungary was started on 12/13/14 June 2014. The closing date of the tender for the 832 sq km was 30 September 2014.

Hajdúbagos 1 Ebes contract, Bihar sub-basin in E. Hungary, TD 2,045m (Algyö fm), 5m net reservoir between 1,986-1,996m in Pannonian sst tested 1.4 MMcfg/d + 55 b/d of 60 API cond for 12 hrs, WHP 590 psi.

Cairn, through its subsidiary Capricorn, spudded exploration well 6508/1-3 targeting the Lynghaug prospect in PL 758 on 20 June 2019. This was the company’s first operated well in Norway and it was drilled using the “Transocean Arctic” S/S. Its location is 6 km southeast of Norne and 8 km northeast of Skaugumsasen. The well reached TD at 1,687 m in the Lower Jurassic Are Formation. A 170 m section of Are Formation (the primary objective) was encountered with around 50 m of net sandstone interbedded with claystones and coals. The well is a dry hole and was abandoned on 11 July 2019. Prior to drilling, Cairn prognosed potential recoverable reserves of approximately 70 MMboe. If the well had been successful it would have been a play opener for the Nordland Ridge and could have been developed as a tie-back to the Norne FPSO. The 2011 Skaugumsasen oil and gas discovery made by Det norske with exploration well 6508/1-2 lies in the southwesterly part of PL 758. The well encountered an 18 m gas column and a 23 m oil column in the Lower Jurassic Tilje / Are formations and recoverable reserves were estimated at 6 MMboe at the time of discovery. PL 758 is operated by Cairn through Capricorn Norge AS (50%) with Skagen 44 (30%) and Lundin Norway AS (20%) as partners.

6508/01-03 (Lynghaug) (Capricorn op. 50%, Skagen 44 30%, Lundin 20%), 1st well in PL 758, SE of Norne on Nordland Ridge, WD=390m, P&A at TD=1663m, encountered 170m of alternating sst, claystone and coal in the targeted Åre Fm with 50m of very good reservoir quality, but with no hydrocarbons present.

PEMEX plugged and abandoned dry the Pox 101EXP new-field wildcat (NFW) in the AE-0007-2M-Amoca-Yaxche-05 entitlement block during mid-January 2019 after reaching a final total depth of 2,374 m.  The operator plans to drill a side-track the Pox 101AEXP to replace the original wellbore. The NFW was spudded on 17 October 2018. The well had a proposed total depth (PTD) of 6,540 m and the primary targets were the Cretaceous and Jurassic formations. The NFW was expected to traverse a 530 m allochthonous salt canopy at this location to reach the objectives. The well was drilled by the “West Titania” J/U in a water depth of 94 m. The NFW is located in the west central area of the block approximately 6 km east north-east of the 2003 Pox 1 new-field wildcat plugged and abandoned dry after extensive testing in 2009 in the westerly adjoining AE-0005-2M-Amoca-Yaxche-03 entitlement block. The drilling permit for the well was granted on 8 August 2018. The NFW has prospective resources estimated to be 109 MMboe. SENER awarded the AE-0007-2M-Amoca-Yaxche-05 entitlement block to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 232.35 sq km.

Pox 101EXP (NFW) (Pemex 100%) in AE-0007-2M-Amoca-Yaxche-05 entitlement block, The well had a proposed total depth (PTD) of 6540 m and the primary targets were the Cretaceous and Jurassic formations. P&A dry.

Effective today, Strike acquired a 50% interest + operatorship from Warrego Energy in EP 469, 224 sq km onshore Perth Basin, for AUD 600,000 + funding an explo/appr well (presumably) in the West Erregulla / West Erregulla field area within 24 months, capped at AUD 11 MM. A joint operating agreement will now be set up.

Strike acquired a 50% interest + operatorship from Warrego Energy in EP 469, 224 sq km onshore Perth Basin, for AUD 600,000

On 25 June 2020 Stuart Petroleum Pty Ltd a wholly owned subsidiary of Senex Energy Ltd, was awarded petroleum retention lease PRL 246, located in the Cooper-Eromanga Basin. The permit has been awarded for a period of five years and is scheduled to expire or be eligible for renewal on 24 June 2025. The permit is one of two awarded to Stuart Petroleum on this date, with PRL 245 also granted. PRL 246 covers an area of 51.6 sq km and will expire on 24 June 2025. Stuart Petroleum Pty Ltd holds 100% interest and operatorship in the permit.

Australia (Chinchilla-Goondiwindi Slope (Bowen - Surat Bsns)) Will

2nd of 2 wells planned in SK-408 off Central Luconia, Sarawak, P&A results n/a (assumed disappointing as 44-day plan cut short to 30 days) on 2 Apr '20, PV Drilling VI JU. Target Middle Miocene Cycle IV/V carbs. SapuraOMV (op), partners Shell + Petronas.

Remayong-1 nfw 2nd of 2 wells planned in SK-408 off Central Luconia, Sarawak, P&A results n/a (assumed disappointing as 44-day plan cut short to 30 days) on 2 Apr '20, PV Drilling VI JU. Target Middle Miocene Cycle IV/V carbs. SapuraOMV (op), partners Shell + Petronas.

Bucsa block, Hajdú–Bihar sub-basin in E. Hungary, drilled 18-28 Jan ’18, TD 1,300m, suspended prior to testing on 31 Jan. Target Szolnok fm, Rotary Lyb 42 rig. 

Hungary (Pannonian B.) Tiszaszentimre 1 op. by MOL (100.0%) in Bucsa (Karcag) block

By early November 2017, Khalda Petroleum had concluded drilling operations in its Qasr South East 1X NFW. The well was drilled on the Qasr development lease of the Khalda Offset PSC, located in the Shushan Basin. It was spudded in Q3 2017 and drilled to a TD of 2,834m. Operations were carried out using the Egyptian Drilling Company #67 rig. The well was targeting a Cretaceous prospect to the SE of the Qasr gas & condensate field. Equity in the Khalda Petroleum consortium is split between Apache (33.5%), Sinopec (17.5%) and EGPC (50%, carried).

Egypt, Khalda Offset (Dev)

Murphy has farmed into Atwater Valley block 23 containing the King Cake prospect, slated for drilling in 3Q ‘18. Murphy will own a 35% stake and operatorship, partners Stone Energy, Ridgewood Energy, Red Willow Offshore and sundries.

Murphy (->35%+op, Stone Energy 13,85%, Ridgewood Energy 21,25%, Red Willow 8,61%, ILX 21,25%,) has farmed into G35015 OCS Lease (AT block 23) containing the King Cake prospect.

Bahamas Petroleum Company has announced that, in its efforts to expand the Company's portfolio options, it has been awarded the AREA OFF-1 petroleum licence offshore Uruguay. Highlights BPC has been awarded the OFF-1 licence, offshore Uruguay OFF-1 contains a management estimated resource potential of up to 1 billion barrels of oil equivalent (BBOE), based on current mapping from multiple exploration plays and leads in relatively shallow waters with significant running room The OFF-1 licence play system is directly analogous to the prolific Cretaceous turbidite discoveries currently being evaluated/developed offshore Guyana and Suriname OFF-1 has an initial 4-year exploration period, with a work obligation limited to reprocessing and reinterpretation of selected historical 2D seismic data - there is no drilling obligation, and the licence includes staged no-cost exit points at BPC's sole election OFF-1 is thus comparable to the 'low cost option' represented by BPC's licences in The Bahamas when they were first awarded - a modest work commitment over 4 years that secures a sizeable, technically high quality, frontier play, with regional seismic available and exciting exploration upside Uruguay is a stable, well-regulated operating environment with an attractive, internationally comparable fiscal regime BPC believes that OFF-1 has the capacity to generate similar value uplift to the Company's existing licences in The Bahamas, where the Company's primary focus remains commencement of exploration drilling on Perseverance-1, expected to spud in late 2020 / early 2021, and targeting recoverable P50 oil resources 0.77 billion barrels, with an upside of 1.44 billion barrels Offshore areas map for Open Uruguay Round (Source: ANCAP)Simon Potter, Chief Executive Officer of Bahamas Petroleum Company, said: 'The scale of the opportunity that our planned drilling campaign in The Bahamas may unlock for us, at the end of 2020, means that our personnel are and will remain entirely focussed on their efforts to deliver the Perseverance-1 exploration well successfully.   However, the current period of introspection in our industry is presenting nimble, forward-thinking companies such as ourselves with compelling opportunities to expand our portfolio and achieve countercyclical growth. The recently-closed Open Licencing round in Uruguay presented exactly such an opportunity for us where, for very low cost, we have been able to secure an exploration licence of an extremely high-calibre that, even as recently as a few months ago, we most likely would have been outbid on by much larger players.   We are especially pleased to have been awarded OFF-1 given that the licence represents a similarly underappreciated opportunity to that secured by the Company in 2007 in The Bahamas - a licence in a region with extensive existing seismic of various vintages, but largely underexplored, and requiring the application of more modern, state of the art seismic imaging technology and techniques to understand the full extent of the petroleum resource.   We are confident that over the next four years we can bring to bear our expertise, gained in The Bahamas over the past decade, on OFF-1 so as to more fully evaluate the licence's potential, in the hope that in the longer-term we can create an opportunity of equal value and industry interest to what we have thus far accomplished in The Bahamas.' Click here for full announcement Source: Bahamas Petroleum

BPC (Bahamas Petroleum Co.) announces the award of offshore block OFF-1 for 4+3+3 years explo, commitments seismic reprocessing + reinterpretation of vintage 2D seismic. OFF-1 was on offer in the country's open round and covers ab. 15,000 sq km in WD 20-1,000m. BPC's rationale is owed to perceived similarities between the area and the Guyana - Suriname basins. BPC will hold a100% interest in the licence, however, ANCAP has the right to back-in for up to a 20% participating interest in each commercial field that is developed.

Vegas is offering up to 35% of its 100% in the East Lagia block, 2,991 sq km in the Sinai. Plans include 550km of 2D seismic starting in November, pending mine clearance.  Contact: Loukas Tripelopoulos, email [email protected], or Zebra Data, email [email protected].

Vegas is offering up to 35% of its 100% in the East Lagia block, 2,991 sq km in the Sinai. Plans include 550km of 2D seismic starting in November, pending mine clearance. Contact: Loukas Tripelopoulos, email [email protected], or Zebra Data, email [email protected].

Vista has agreed to farmin to Jaguar E&P assets with a 50% stake and operatorship. Involved are Rounds 2.2 and 2.3 blocks CS-01 (CNH-RO2-L03-CS-01/2017), 95 sq km in the Sureste Basin, and B-10,  347 sq km. It also gets 50% in TM-01 (CNH-RO2-L03-TM-01/2017) 72 sq km in the Tampico-Misantla Basin, where Jaguar however retains operatorship.

Vista O&G, has farmed (50%+op.) into three blocks (CS-01, B-10 & TM-01) in Sureste & Tampico Basin, won by Jaguar E&P (->50%) in the country's onshore bidding Rounds 2.2 and 2.3.

According to local reports in July 2018, state company ENAP has taken over operatorship and 99% interest of the Caupolican and Brotula blocks from the original operator, Greymouth Petroleum’s subsidiary PetroMagallanes, who is keeping the remaining 1% stake. Caupolican (2,481 sq km) and Brotula (100 sq km) are situated in the Magallanes Basin and directly across from each other on the Strait of Magellan. Both blocks were awarded to PetroMagallanes in July 2008. In Caupolican, the last well drilled by the company was Caupolican 2 NFW, which was suspended with unspecified hydrocarbon shows in October 2015. Meanwhile in Brotula block, Brotula TA-2 NFW was completed as a gas producer in July 2014. Background Information Caupolican and Brotula are located next to two of ENAP’s most active blocks in the country. Caupolican is adjacent to the Arenal block, while Brotula is situated next to Dorado-Riquelme block. Arenal block is the state company’s best producer of unconventional gas in Chile, followed by Dorado-Riquelme. USGS study from 2016 estimated the potential resources of the Zona Glauconitica Formation in both areas to be over 8 Tscf.

ENAP has taken over operatorship and 99% interest of the Caupolican and Brotula blocks from the original operator, PetroMagallanes (->1%).

KazMunayGaz and Lukoil have signed a Joint Operations Agreement and a Finance Agreement with regard to the Zhenis offshore project. The agreements were signed in Moscow on 30 November 2018. They set out the terms and conditions for both companies to implement the project. Signing these documents opens the way for the participants to negotiatiate a final exploration and production contract with the Ministry of Energy of Kazakhstan. KazMunayGaz and Lukoil signed an agreement on principles on the Zhenis offshore project in June this year. Zhenis is situated at the southern margin of the Kazakh Caspian sector, on the border with Turkmenistan. Currently there are no discoveries in this block. Background Information In April 2018, Energy Minister Mr. Bozumbayev announced that KazMunayGaz (KMG) and Lukoil were negotiating two offshore Caspian E&P blocks, Zhenis and I-R-2. Earlier this year Lukoil’s President Mr. Alekperov said the company was looking at offshore blocks in Kazakhstan in light of the new subsurface and tax legislation which makes investment in the country’s E&P projects more attractive. Both blocks are located in the Mangyshlak-Central Caspian Basin. I-R-2 lies west of the Tsentralnoye discovery that is shared by Russia and Kazakhstan. The Russian part in the Tsentralnoye development is represented by Lukoil and Gazprom. The field’s 3P recoverable reserves are estimated at 664 MMbbl of oil, 1.7 Tcf of gas (mainly gas-cap) and 20 MMbbl of condensate. There are no discoveries in I-R-2. Kazakhstan does not hold offshore bidding rounds, and several blocks off Kazakhstan are available for direct negotiations with the government/national oil company KMG. Kazakhstan legislation stipulates that KMG must have at least 50% interest in offshore projects. Lukoil has been negotiating new projects in Kazakhstan for the last several years, however, none have been finalised due to unattractive economics. Lukoil has been involved in Kazakhstan’s E&P for a long period of time, both on- and offshore. However, its previous exploration projects in the country’s Caspian sector have been unsuccessful. The company has drilled dry wells in the Tyub-Karagan and Atash blocks, and has had to relinquish the Zhambay block due to unavailability of a drilling rig capable of operating in the block’s super-shallow waters at that time. All these blocks were in the Northern Caspian. The company has made several important oil and gas/condensate discoveries in the Russian sector of the Caspian.

KazMunayGaz, Lukoil sign agreement on Zhenis offshore block

Mandala has acquired an additional 6% in the Lemang PSC (Akatara field), 2,470 sq km in S. Sumatra, from Endeco*, a deal approved by Migas in June. Partners now Mandala (op) 90%, Hexindo Gemilang Jaya (Eneco sub) 10%. * ex-Ramba Energy

Mandala (->90% op, Hexindo Gemilang Jaya 10%) acquired an additional 6% in the Lemang PSC (Akatara field), 2470km², from Endeco.

As of 26 March 2020, PetroChina had completed a 28 stage fracture stimulation programme targeting the First Member of the Qingshankou Formation at Yingyeyou 1 after having commenced the operations on 16 March 2020. The shale oil exploration well was drilled in 2019 to a TD of 4,306m MD (PTD 4,500m) with the objective of exploring the Type II shale oil (combination of shale and tight sand type reservoir) potential of the Songliao Basin. Yingyeyou 1 is in the PetroChina operated Gulong Block in the Songliao Basin.

PetroChina had completed a 28 stage fracture stimulation programme targeting the First Member of the Qingshankou Formation at Yingyeyou 1 after having commenced the operations on 16 March 2020. The shale oil exploration well was drilled in 2019 to a TD of 4,306m MD (PTD 4,500m) with the objective of exploring the Type II shale oil (combination of shale and tight sand type reservoir) potential of the Songliao Basin. Yingyeyou 1 is in the PetroChina operated Gulong Block in the Songliao Basin.

The government of Guinea Bissau is promoting open exploration acreage through state company Petroguin. The licensing authority is the Ministry of Natural Resources but contracts are negotiated on behalf of the state by Petroguin. Petroguin will hold a stake in every permit. The government intends to have a competitive bidding process for acreage awards but no formal bid rounds are organized. Interested parties should contact Petroguin: Caixa Postal 387 Bissau Director of Marketing and Business Development: Celedonio Placido Vieira Tel: +245 966 63 80 60 Email: [email protected] The available open blocks as of April 2020 are listed in the table below. Five blocks are available. There was no change in the list compared to the previous one. Total open acreage amounts to 25,330 sq km, of which two thirds (17,080 sq km) is onshore and the rest (8,250 sq km) is offshore deep water. Open blocks       Block Name Area (sq km) Situation Block Basin Block 2 Onshore 4,993 onshore Bove-Senegal Basins (Senegal M.S.G.B.C. Basin) Block 4 Onshore 4,820 onshore Bove Basin Block 5 Onshore 7,265 onshore Bove Basin Block 5C 2,468 offshore Senegal (M.S.G.B.C.) Basin Block 6C 5,783 offshore Senegal (M.S.G.B.C.) Basin

he government of Guinea Bissau is promoting open exploration acreage through state company Petroguin. The licensing authority is the Ministry of Natural Resources but contracts are negotiated on behalf of the state by Petroguin.

In late April 2018 NIS published the production figures for the Q1 2018 period. The natural gas production during Q1 2018 increased by 5.3% compared to Q4 2017 to 45,298 Mcf/d (the original production figures given by the company for the Q1 2018 period amounted to 104 thousand toe). Daily output in Q1 2018 averaged 45,298 Mcf/d of gas, which was 1% down compared to Q1 2017. Since the beginning of 2013 LPG (Liquefied petroleum gas) production is included in the oil and condensate production figures. The major gas producing fields are Medja, Martonos, Itebej, Torda Plitko and Milosevo. Remaining recoverable reserves (proven and probable) were estimated on 1 January 2017 at about 658 Bcf of gas.

Serbia (Banat Sub-basin (Pannonian B.)) Torda Plitko