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COP's 80% farmin to T/49P from 3D Oil in the Otway Basin off Tasmania (DEA 18 Dec '19) is reportedly compete following NOPTA's approval of the move. Plans include 1,580 sq km of new 3D seismic (3DO carried) and later tentatively an explo well (COP up to USD 30 MM).

Australia (Otway B.) T/49P op. by COP (80%), OTHERS (18%), HIBISCUS (2%) COP's 80% farmin to T/49P from 3D Oil is reportedly compete

28/96/L Ropczyce-Bratkowice-Strzyzów contract, Carpathian Flysch Zone, W. of Rzeszow in S. Poland, TD 2,114m reached, target gas in Sarmatian-Badenian ss, testing began in early Jan '20.

Gnojnica-4K npw 28/96/L Ropczyce-Bratkowice-Strzyzów contract, Carpathian Flysch Zone, W. of Rzeszow in S. Poland, TD 2,114m reached, target gas in Sarmatian-Badenian ss, testing began in early Jan '20.

Woodside Energy Ltd spudded the Ferrand 1 exploration well in WA-404-P, located in the North Carnarvon Basin, on 17 April 2018.  The well was drilled by the “Ensco MS1” S/S and had a planned total depth of 5,200 m.  On 18 June 2018 the well was plugged and abandoned, with the rig leaving the well site. Woodside reported that the Ferrand well was targeting a ‘large’ volume of gas, within an anticlinal trap, which is considered to be over 100 MMboe. The well targeted a structural trap within Triassic units.  Within the region, successful targets have lain within the Upper Jurassic sands of the Jansz and Triassic Mungaroo formations. Ferrand is estimated to cost around AUD 50 million to drill.   The commitment to drill in WA-404-P lies in Term Five and as such the commitment to drill was required by the start of the term in February 2017. There have been no permit suspensions or changes to the original work programme since Woodside renewed the permit on 17 July 2013. Woodside has already submitted an Environmental Plan to the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA). WA-404-P, which covers an area of 1,377 sq km, was awarded on 17 July 2007 and is 100% owned and operated by Woodside Energy Ltd.

Ferrand 1 (Woodside 100%) in WA-404-P block, P&A, results n/a. Well was targeting a ‘large’ volume of gas, within an anticlinal trap, which is considered to be over 100 MMboe. The well targeted a structural trap within Triassic units.

Chetan 1 flow tested approximately 119 bo/d and 0.22 MMcfg/d through a 6mm choke from the Carboniferous Tailegula Formation on 22 October 2019. Chetan 1 was drilled to a TD of 5,218m MD and was suspended for further evaluation on 19 August 2019. PetroChina spudded Chetan 1 on 20 April 2019 to drill to an initial PTD of 4,800m but decided to deepen the well to a revised PTD of 5,500m when Chetan 1 reached the initial PTD on 19 July 2019. The oil and gas exploration well was targeting the Carboniferous Tailegula Formation with the objective of exploring the hydrocarbon potential within the southern Hongche fault belt. Chetan 1 is in the PetroChina operated Shamenzi Block in the Junggar Basin and is geographically located within Xinjiang Province, Kuytun City. <P />

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United Energy signed with Asia Resources to acquire the latter’s assets in Pakistan, namely 10% in Kotri North 2568-21 and 10% in Gambat South 2568-18 in Sindh. The deal is pending govt approval. Kotri North covers 2,472 sq km, held by UE (op), PPL and AROL.  Gambat South is 2,437 sq km held by PPL (op), GHPL and AROL.   Asia Resources also has 10% in the PPL-run Naushahro Firoz 2668-9 block in Sindh, 2,494 sq km. PPL is taking over the 10%.

United Energy signed with Asia Resources to acquire the latter’s assets in Pakistan, namely 10% in Kotri North 2568-21 and 10% in Gambat South 2568-18 in Sindh. The deal is pending govt approval. Kotri North covers 2,472 sq km, held by UE (op), PPL and AROL. Gambat South is 2,437 sq km held by PPL (op), GHPL and AROL. Asia Resources also has 10% in the PPL-run Naushahro Firoz 2668-9 block in Sindh, 2,494 sq km. PPL is taking over the 10%.

Beach Energy Ltd spudded the Glenelg North 1 exploration well in PRL 94, located in the Cooper Eromanga Basin, on 29 February 2020. On 7 March 2020 the well was plugged and abandoned, as a dry hole, after reaching a total depth of 1,911 m. The well is located around 6 km northwest of the producing Callawonga oil field. PRL 94, which covers an area of 97 sq km, was awarded on 6 June 2014. Participants in the permit are Beach Energy Ltd (75% + Operator) and Cooper Energy Ltd (25%).

Glenelg North 1 (Beach op. 75%, Cooper Energy 25%) in PRL 94, P&A dry.

Ascent announces an MoU with Cupet for exclusive rights to 3 additional in its wider international strategy with the acquisition of an MoU on onshore block 9b (Majaguillar + San Anton fields, ref. DEA 14 Apr '20). Involved under the new MoU are blocks 9a (1,000 sq km, 12 (2,750 sq km) + 15 (3,200 sq km) also on the north coast of Cuba. PSC negotiations will take place over the coming 6 months and should result in Ascent holding operatorship. Release here.

Cuba (North Cuban Province) San Anton

Petrobras intends to sell its interest in 8 wholly-owned ANP Round 12 (2013) contracts in the NE Recôncavo Basin onshore, namely REC-T-32_R12, RECT-40_R12, REC-T-50_R12, REC-T-51_R12, REC-T-52_R12, REC-T-60_R12, REC-T-61_R12 and REC-T-70_R12. The acreage is being sold under the company's USD 26.9bn divestment programme to reduce debt. Expressions of interest to veredas@petrobras.com.br by 8 October and qualification documents to veredas@petrobras.com.br by 18 October 2019.

Petrobras intends to sell its interest in 8 wholly-owned ANP Round 12 (2013) contracts in the NE Recôncavo Basin onshore, namely REC-T-32_R12, RECT-40_R12, REC-T-50_R12, REC-T-51_R12, REC-T-52_R12, REC-T-60_R12, REC-T-61_R12 and REC-T-70_R12.

P2128 west of Pegasus, ops terminated of late, significant gas column in the target Westphalian, but at the lower end of expectations, GWC shallower than in nearby Pegasus West, temporarily P&A'd, Noble Hans Deul JU. PTD was >3,000m. Spirit (op), partner HALO.

043/12a-03 (Andromeda N.) expl. (Spirit 55% op, HALO 45%) in P2128, gas discovery in the targeted Carboniferous Westphalian A sst. good quality, porous and permeable, on the north side of the Pegasus West bounding fault. Halo stated the find was at the lower end of its expectations.

According to the Bolivian Ministry of Hydrocarbons and Energy (MHE), Argentinean state company YPF has signed a study agreement with Bolivian state company YPFB in mid-August 2018 to evaluate the potential of the Sauce Mayu block. Initial investment was said to be USD 70 million, which will include the drilling of a well in 2019. A USD 588 million development plan will follow if results are positive. The 458 sq km block is located in the Sub-Andean Zone of Chaco Basin on the Chuquisaca Department, with reportedly a potential of 2.7 Tscf of gas. The Sauce Mayu block is situated around the Repsol-operated Monteagudo field, which has produced a total of 37.3 MMbo, 71.7 Bscf, and 279.9 Mbc from several different reservoirs since it was put on-stream in 1968. It is also adjacent to Total’s Azero block where the operator is planning to drill two exploration wells with assumed target in the Huamapampa Formation. Background Information YPF made its first entry as an operator in Bolivia since the split of Repsol-YPF in 2012 with the signing of an exploration and production service contract for the Charagua block in July 2017.

YPF and YPFB have agreed to jointly evaluate the potential of the gas-prone Sauce Mayu block, 458km² in the Sub-Andean Zone.

Pterovietnam has farmed out an operating stake to SKI in block 16-2 in the Cuu Long Basin, WD 30-55m, both companies now partnering the 2,228-sq km block. The deal was reportedly completed 21 Jul '20. 3D seismic is planned here for late 3Q. Up to 50% had been available since 2017.

Vietnam (Cuu Long B.) Block 16-2 op. by PETROVIET (100%)

North of PL 19-3 field in Bohai Gulf Basin, WD 25m, ops terminated (results n/a) in mid-Feb ‘19, HYSY 923 JU. Target was Tertiary.

North of PL 19-3 field in Bohai Gulf Basin, WD 25m, ops terminated (results n/a) in mid-Feb ‘19, Target was Tertiary.

W-C part of PN-T-137 block P&A dry (no shows report) mid-Sep ‘18. PTD was 2,190m, target Cabeças + Poti fm’s.  were the primary targets.

1-OPEO-JATOBA-PI (Ouro Preto 100%) in PN-T-137 contract block, P&A, dry.

PL 146, Cooper-Eromanga, susp. gas at TD 2,088m on 24 Sep '19. Santos (op), partners Origin + Beach.

Wackett South 1 explo. well (Santos 46,8% Op. Vamgas 2,62%, Origin Egy 28%, Beach Egy 22.5%) in PL 146, Suspended, at TD=2088m, gas disc.

Khalda block, N. Egypt Basin, drilled 3 Jan – Feb '20, TD 4,188m, flowed o&g presumably from the Cenomanian Bahariya target.

Elan 1 nfw. (Khalda 100% = JV between EGPC 50%, Apache 33.5%, Sinopec 16.5%) in Khalda block, TD=4188m, flowed o&g presumably from the Cenomanian Bahariya target.

Santos Ltd spudded the Cocinero 6 oil appraisal well in PL 509, located in the Cooper-Eromanga Basin, in mid-February 2018.  In late February 2018 the well was suspended as a future oil production well, after reaching total depth.  Joint venture partner Beach Energy reported that 1.4 m net oil pay was encountered within the Murta Formation. The well was part of an ongoing appraisal and development programme at the Cocinero field, which was discovered in May 2014.  Cocinero 6 is the first appraisal well in the current programme, following three development wells.  Cocinero 6 was targeting the Murta Formation. PL 509, which covers an area of 40 sq km, was awarded on 5 May 2015.  Participants in the permit are Santos Ltd (25% + Operator), Vamgas Pty Ltd and Santos Petroleum Pty Ltd, both Santos subsidiaries, (5% and 25% respectively) and Beach subsidiaries Delhi Petroleum Pty Ltd (20%) and Lattice Energy Ltd (25%).  

Australia (Cooper - Eromanga B.s) Cocinero

Terra Nova Energy Ltd was seeking to divest its operated 51.4997% interest in exploration licences PEL 112 and PEL 444, located in the Cooper-Eromanga Basin. The company was considering farming-down around 40% interest or fully divesting ownership to interested parties. However, the opportunity is no longer considered valid after Oilex Ltd announced in August 2019 that it is poised to acquire up to 100% interest in the exploration licences after entering into an agreement with joint venture Holloman and a second agreement with Terra Energy. The deals are expected to close by 30 September 2019 which will see Oilex acquire a combined 79.33% with the option to increase to 100% after 12 months. The permits are located in the Western Flank Fairway and Terra Nova reports that there are a number of Namur and Birkhead structural prospects within both permits. In PEL 112 covers an area of 1,000 sq km and was awarded on 17 April 2003. Terra Nova has outlined the Milo, Libby and Drole structural prospects, which combined hold a potential 9 MMb oil in place. Milo is outlined as the primary target, with the largest potential resource and lowest risk. One exploration well is due in 2019. The well will likely target one of these prospects and be positioned from the 2012 Mulka 3D seismic survey, which is located in the north of the permit area. Wolfman 1 well was drilled within the Mulka very area in 2013. It targeted a dip closure in the Namur Sandstone at around 1,200 m depth but was dry at location. Secondary, deeper, targets of the Birkhead and Hutton formations were also dry. PEL 444 covers an area of 1,150 sq km and was also awarded on 13 April 2003. Terra Nova has identified the Maverick mid-Birkhead prospect which is considered as a key exploration target.  It has a potential 1.71 MMbo resource. The Crater and Moraine Namur prospects have also been outlined as potential targets. The prospects in PEL 444 have been identified from the merged Jasmin and Wingman seismic datasets, which Terra Nova has reported as providing high level mapping of the licence. Terra Nova considers there is potential for the Hoplite 1 oil play fairway to extend into PEL 444. One commitment well is due in 2021. The Baikal 1 well was drilled in 2015, located approximately 8 km west of Hoplite 1. The well targeted this the oil play within the mid-Birkhead channel sands but was dry at location. However, the channel sands, which were mapped from seismic, were encountered and now provides qualification to the current exploration model. PEL 112 and PEL 444 are held by Terra Nova Energy Australia Pty Ltd (a Claren Energy subsidiary - 51.4997% + Operator) and Holloman Petroleum Pty Ltd (48.5003%). Companies interested in these opportunities were asked to contact: Chas Lane Tel: +61 417 185 310 Email: chassa@iinet.net.au

Terra Nova Energy Ltd was seeking to divest its operated 51.4997% interest in exploration licences PEL 112 and PEL 444, located in the Cooper-Eromanga Basin.

Beacon has reportedly signed HoA to acquire LLOG's 30.95% in the Shenandoah project in Walker Ridge blocks 51, 52 + 53, thereby increasing Beacon's stake from 15.95% to 46.9%. Remaining partners-to-be: Navitas + Beacon.

United States (Sigsbee Sub-basin (DWGoM B.)) Shenandoah

Shell has acquired 20% in PL811 from DNO as released by the NPD on 30 November 2018. PL811 covers 352 sq km over blocks 7/9, 7/12 and 8/7, and was awarded on 5 February 2016 with a drill decision due in February 2019. DNO acquired its stake when it completed its acquisition of Origo Exploration Holding AS on 29 June 2017. The licence is located N of the Ula Field in the North Sea and contains dry NFW 7/9-1 (1971, Conoco, 2,931m). PL811 partners are Spirit Energy Norway AS (40% + Op), AS Norske Shell (20%), Faroe Petroleum Norge AS (20%) and Aker BP ASA (20%).

Norway, PL 811

On 12 December 2017 Melbana Energy Ltd reported that it has entered into a farm-in option agreement with Total SA and Santos Ltd for Melbana’s 100% owned exploration permit WA-488-P, located in the Bonaparte Basin. The permit contains the Beehive Prospect, which required further seismic before the scheduled drill date by 21 December 2020 to test the structure. Under the agreement, Total and Santos fully funded a 600 sq km 3D seismic survey over the Beehive Prospect in return for an option to acquire an 80% participating interest in the permit (together or individually split). The survey subsequently was undertaken in mid-2018.  Melbana reported on 1 November 2018 that preliminary data products present excellent quality and that final data is set to be received by February 2019. Upon receipt of the data, Total and Santos have six months to proceed with the interest acquisition and commit to funding the Beehive-1 exploration well. Santos reported that it would now be deciding on the option to farm-in to the well portion in 2019 upon receiving the fully processed data. With the seismic option exercised, Melbana will retain 20% interest and be fully carried for the first well, which is likely to target the Beehive Structure. If a commercial discovery is made, Melbana will repay the carried funding from the cash flow post full field development, which, at 20% interest, would equate to approximately USD $8 to $12 million based on a drill cost of USD $40 to $60 million. Melbana reports that the seismic survey planning commenced during 2017 and was estimated to cost around AUD 5 million. With the potential of de-risking of the Beehive Prospect, well planning can commence to determine the preferred surface location. Melbana, previously MEO Australia Ltd, through its wholly owned subsidiary Finniss Offshore Exploration Pty Ltd, launched a farm-out of WA-488-P following its award as part of the 2012 Federal Offshore Acreage Release. Between 10 and 80% interest in the permit was made available with conditions and equity options always dependent upon the completion of seismic reprocessing and assessment of key elements within the permit. In December 2015, Melbana received approval to suspend/extend WA-488-P to facilitate additional seismic reprocessing and seismic inversion of 150 km 2D broadband data to de-risk the Beehive Prospect. After being completed by Q4 2017, Melbana reported that significant data quality improvements had been noted, providing better definition of the reef edge and in the overlying shale seal sequence in the Beehive Structure. The Beehive 1 well will target the shallow, substantial Beehive Prospect in a new play type with global analogues. The primary target is thought to be a Carboniferous Carbonate build up play, which is analogous to the Ungani and Tengiz discoveries. The carbonate platform has been interpreted by Melbana to be approximately 18 km across with a mapped closure around 140 sq km. As a secondary objective the prospect contains an Ordovician Buried Hill play. Prospective recoverable resources have been estimated, with a Best Estimate of 558 MMboe and 305 MMboe for the Carboniferous Carbonate and Ordovician Buried Hill plays respectively.  If a discovery is made, Melbana reports that development plans could include an FPSO or pipeline options to existing infrastructure including Ichthys and Blacktip developments. Melbana entered WA-488-P on 18 February 2014 by means of an Option Agreement with Rex International Holding, for a 30% interest in the block. By 20 October 2014, Melbana had reached a settlement to allow Rex to withdraw from the permit due to the declining industry market and Rex’s move to focus on it key assets in Norway and Oman.

Australia (Petrel Sub-basin (Bonaparte B.)) Blacktip

1st well in PL 827 S, N. of Gnomoria discovery in WD 368m, TD 1,907m (Lista fm), target Balder + Sele sst dry, P&A'd, West Hercules SS to 30/2-5 S (Atlantis) in PL 878. Equinor (op), partner DNO.

Norway (Utsira High (Horda Platform)) Balder 035/10-06 (Gabriel) nfw 1st well in PL 827 S, N. of Gnomoria discovery in WD 368m, TD 1,907m (Lista fm), Balder + Sele sst targets dry, P&A'd, Equinor (op), partner DNO.

8 January 2018, Turkmen authorities report that appraisal/outpost well Minara 3 has tested around 1 MMcm/day of gas (ca. 34 MMscf/d) from the pre-salt Callovian-Oxfordian carbonates. The well’s planned TD is 4,750 m. It is understood that the well is being operated by the Turkmengeologiya national exploration company (TG). Minara occupies the giant Galkynysh field’s north-western sector. A gas pool in the post-salt Shatlyk reservoir (Hauterivian) was discovered here at 2,770 m back in 1964. The Shatlyk pool has been in production since 1970 and is now depleted. A gas accumulation was discovered in the pre-salt section in 2009. Background information In June 2009, exploration well Minara 1 tested a flow of 147.3 MMscf/d (4.3 MM cubic metres per day) from the Callovian-Oxfordian Carbonates play at a depth of 4,030 m. Minara 1 was spudded by Turkmengeologiya on 27 June 2007, with a PTD of 4,750 m in the Upper Jurassic. In Q1 2009, Turkmengeologiya spudded Minara 2 with the same PTD as well 1. The well’s results have not been reported.  

Minara 3 appraisal well by Turkmengeologiya (100%) tested around 34 MMscf/d from the pre-salt Callovian-Oxfordian carbonates. Minara occupies the giant Galkynysh field’s north-western sector

Press of 17 October 2018 reported that the Mozambique Government awarded the contract for the Pande/Temane Area PT5-C to Sasol Petroleum Mozambique Exploration Ltd. Sasol will operate the 3,012 sq km Mozambique Basin block with a 70% interest in partnership with ENH 30%. When the block was preliminarily awarded the group committed to a spend of USD 49 million for the first 4-year period including the acquisition of 1,600 km 2D seismic data and the drilling of two wells.

Mozambique, PT5-C

On 29 March 2018, the consortium of BP with 60% working interest and Statoil with 40%, was granted preliminary awards for the C-M-755 and C-M-793 blocks in the offshore Campos Basin through the ANP Round 15. For the C-M-755 block the consortium offered a bonus of USD 13.1 million and 200 work units. For the C-M-793 block the consortium offered a bonus of USD 13.1 million and 200 work units.    There were no other bids for either of the blocks.  

the consortium of BP with 60% working interest and Statoil with 40%, was granted preliminary awards for the C-M-755 and C-M-793 blocks in the offshore Campos Basin through the ANP Round 15.

Add. DEA 19 Dec ’17 (adds status): SK-408, off Central Luconia Province, Sarawak, P+A dry mid-Dec ’15. Target Middle Miocene Cycle IV / V carbs, 1st of 3 wells planned, Hakuryu 11 JU. Sapura Energy (op), partners Shell + Petronas.

Remujung 1 op. by Sapura Energy (40%, Shell 30%, Petronas 30%) in SK-408 block, P&A, dry. Target Middle Miocene Cycle IV / V carbs

PL 533, ab. 32km NW of Alta discovery in S. Barents, P+A dry at TMD 2,750m, Leiv Eiriksson SS off to Filicudi for abandonment ops. Targets Jurassic Hekkingen + Stø fm’s. Lundin (op), partners Aker BP + DEA.  

7219/12-3 S (Hurri) op. by Lundin (Aker BP %, DEA %) in PL 533 block, 32km NW of Alta discovery, targets Jurassic Hekkingen + Stø fm’s. P+A’ing, results n/a.

On 7 November 2019, Gazprom Flot announced that it completed a new well for Novatek in September 2019. In early August 2019, Novatek-subsidiary Arctic LNG 1 spudded an appraisal well at the offshore extension of the Geofizicheskoye discovery (Western Siberia). Geofizicheskaya 65 with a PTD of 2,750 m, drilled by Gazprom’s Amazon jack-up, was targeting reservoirs of the Tanopchinskaya Formation (Hauterivian-Aptian). Water dept in the location is 12 m. The well was aimed at confirmation of gas pools in the Neocomian section (1,400-2,400 m) through open hole tests and conversion of 3P gas reserves in the main Cenomanian pool into 2P category. The company suspended the well after testing gas flows from reservoirs TP23 and TP12 in the Tanopchinskaya Formation (Neocomian) and from reservoir PK1 (Cenomanian). Geofizicheskoye, discovered in 1975, is located in the Gydan Peninsula and the Ob Estuary (South Kara-Yamal Province). Recoverable 2P reserves of 19 pools distributed from Middle Jurassic to Cenomanian are estimated at 4.8 Tcf of gas, 21 MMbbl of oil and 9 MMbbl of condensate. The Cenomanian pool contains more than 90% of total gas reserves. Gas reserves of the discovery’s offshore portion are estimated at 743 Bcf of 2P and 3.3 Tcf of 3P.

Gazprom Flot announced that it completed a new well for Novatek in September 2019. In early August 2019, Novatek-subsidiary Arctic LNG 1 spudded an appraisal well at the offshore extension of the Geofizicheskoye discovery (Western Siberia). Geofizicheskaya 65 with a PTD of 2,750 m, drilled by Gazprom’s Amazon jack-up, was targeting reservoirs of the Tanopchinskaya Formation (Hauterivian-Aptian). Water dept in the location is 12 m. The well was aimed at confirmation of gas pools in the Neocomian section (1,400-2,400 m) through open hole tests and conversion of 3P gas reserves in the main Cenomanian pool into 2P category. The company suspended the well after testing gas flows from reservoirs TP23 and TP12 in the Tanopchinskaya Formation (Neocomian) and from reservoir PK1 (Cenomanian). Geofizicheskoye, discovered in 1975, is located in the Gydan Peninsula and the Ob Estuary (South Kara-Yamal Province). Recoverable 2P reserves of 19 pools distributed from Middle Jurassic to Cenomanian are estimated at 4.8 Tcf of gas, 21 MMbbl of oil and 9 MMbbl of condensate. The Cenomanian pool contains more than 90% of total gas reserves. Gas reserves of the discovery’s offshore portion are estimated at 743 Bcf of 2P and 3.3 Tcf of 3P.

On 8 December 2017, the Comision Nacional de Hidrocarburos (CNH) officially signed the contracts granting official awards for all seven provisional awards from the CNH-RO2-LO2/2016 Bid Round.   The two consortia granted official awards changed the official operator names from the provisional awards.  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-LO2/2016 Bid Round with the preliminary award of seven of the 10 blocks to the high bidders. On 12 July 2017, the Comision Nacional de Hidrocarburos (CNH) held the CNH-RO2-LO2/2016 Bid Round and seven of the 10 blocks were bid on and were provisionally awarded.  There was a total of 12 bids by seven companies individually or in consortia.  Only three of the seven blocks had additional bids.  Total area awarded in the round was 2,919.30 sq km and an estimated USD 168.6 million in work commitments based on the 11 additional wells bid as extra work commitments. The round was dominated by the consortium of Sun God Energia, a subsidiary of Sun God Resources of Canada and partner Jaguar Exploracion offering the maximum additional royalties for five of the six blocks it won.  The consortium won six of the seven blocks it bid on including the most contested block in the round, the Area 7 block which had three bids and a tie.  The Sun God consortium prevailed in the tie-break offering a USD 4.2 million bonus versus the USD 2.9 million offered by second place bidder Newpek and Verdad.  Jaguar Exploracion is based in Monterey and its President is Javier Zambrano, ex Schlumberger, and backed by Grupo Topaz the ex-president of the Alfa Group. The tables below illustrate the Ronda 2.2 Bid Round results including estimated work commitments in USD.  Based on the estimated work commitments Sun God and Jaguar led the round with net area to working interest and USD commitments based on an assumed 50:50 equity split in the consortia. On 5 July 2017, the Comision Nacional de Hidrocarburos (CNH) approved and published the final list of qualified companies and consortia for the CNH-RO2-LO2/2016.  The final list of participating companies includes four individual companies and five consortia, see tables below. On 22 June 2017, the Comision Nacional de Hidrocarburos (CNH) approved and published the final modifications to the bid documents and model contract for the CNH-RO2-LO2/2016.  The CNH also published the provisional list of qualified companies.  There are five companies that qualified individually and four consortia representing nine companies.  The CNH also had to remove Area 10 and Area 11 blocks from the round due to ongoing negotiations with indigenous communities where the blocks are located in the Sureste Basin.  As a result, the Area 12 block is now denominated as Area 10 block. Results - CNH-RO2-LO2/2016 Bid Round – Final Official Awards 8 December 2017 Basin Area-Block Number Contract 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-L02-A1.BG/2017 Iberoamericana de Hidrocaruburos CQ, Exploracion & Produccion de Mexico S.A. de C.V. Iberoamericana de Hidrocaruburos, S.A. de C.V. / Servicios PJP4 de Mexico S.A. de C. V. 360.3 3.91 6,000 $6,000,000 1 $8,200,000 $14,200,000   $14,200,000 12/8/2017 Burgos 4 CNH-RO2-L02-A4.BG/2017 Pantera Exploracion y Produccion 2.2, S.A.P.I. de C.V. Sun God Energia de Mexico, S.A. de C.V. / Jaguar Exploracion Y Produccion De Hidrocarburos, S.A.P.I. de C.V. 440.3 25 8,300 $8,300,000 2 $21,200,000 $29,500,000   $29,500,000 12/8/2017 Burgos 5 CNH-RO2-L02-A5.BG/2017 Pantera Exploracion y Produccion 2.2, S.A.P.I. de C.V. Sun God Energia de Mexico, S.A. de C.V. / Jaguar Exploracion Y Produccion De Hidrocarburos, S.A.P.I. de C.V. 444.6 16.96 9,300 $9,300,000 0 $0 $9,300,000   $9,300,000 12/8/2017 Burgos 7 CNH-RO2-L02-A7.BG/2017 Pantera Exploracion y Produccion 2.2, S.A.P.I. de C.V. Sun God Energia de Mexico, S.A. de C.V. / Jaguar Exploracion Y Produccion De Hidrocarburos, S.A.P.I. de C.V. 445 25 7,800 $7,800,000 2 $20,200,000 $28,000,000 $4,130,000 $32,130,000 12/8/2017 Burgos 8 CNH-RO2-L02-A8.BG/2017 Pantera Exploracion y Produccion 2.2, S.A.P.I. de C.V. Sun God Energia de Mexico, S.A. de C.V. / Jaguar Exploracion Y Produccion De Hidrocarburos, S.A.P.I. de C.V. 416.1 25 4,500 $4,500,000 2 $26,800,000 $31,300,000   $31,300,000 12/8/2017 Burgos 9 CNH-RO2-L02-A9.BG/2017 Pantera Exploracion y Produccion 2.2, S.A.P.I. de C.V. Sun God Energia de Mexico, S.A. de C.V. / Jaguar Exploracion Y Produccion De Hidrocarburos, S.A.P.I. de C.V. 464 25 4,000 $4,000,000 2 $27,600,000 $31,600,000   $31,600,000 12/8/2017 Sureste 10 CNH-RO2-L02-A10.CS/2017 Pantera Exploracion y Produccion 2.2, S.A.P.I. de C.V. Sun God Energia de Mexico, S.A. de C.V. / Jaguar Exploracion Y Produccion De Hidrocarburos, S.A.P.I. de C.V. 349 45 5,900 $5,900,000 2 $18,800,000 $24,700,000   $24,700,000 12/8/2017     Preliminary Results - CNH-RO2-LO2/2016 Bid Round – 12 July 2017 Basin Area Number Area sq km 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 - Consortia CNH – Estimated total State Take % Burgos 1     360.30                 1               3.91 6,000  $       6,000,000          8,200  $      8,200,000                  1  $  8,200,000   Iberoamericana / Servicios PJP4 41.20 Burgos 2     374.60               -     4,000  $       4,000,000          9,900  $      9,900,000    $             -         Burgos 3     447.90               -     7,500  $       7,500,000          8,500  $      8,500,000    $             -         Burgos 4     440.30                 2              25.00 8,300  $       8,300,000        10,600  $     10,600,000                  2  $21,200,000   Sun God Energia / Jaguar 86.10 Burgos 5     444.60                 2              16.96 9,300  $       9,300,000          9,700  $      9,700,000                 -    $             -     Sun God Energia / Jaguar 68.40 Burgos 6     479.00               -     5,100  $       5,100,000        10,600  $     10,600,000    $             -         Burgos 7     445.00                 3              25.00 7,800  $       7,800,000        10,100  $     10,100,000                  2  $20,200,000  $  4,130,000 Sun God Energia / Jaguar 84.10 Burgos 8     416.10                 1              25.00 4,500  $       4,500,000        13,400  $     13,400,000                  2  $26,800,000   Sun God Energia / Jaguar 82.80 Burgos 9     464.00                 1              25.00 4,000  $       4,000,000        13,800  $     13,800,000                  2  $27,600,000   Sun God Energia / Jaguar 83.50 Sureste 10     349.00                 2              45.00 5,900  $       5,900,000          9,400  $      9,400,000                  2  $18,800,000   Sun God Energia / Jaguar 80.50   Company NAWI sq km Net USD Work commitments to WI Sun God Energia           1,279.50  $       77,200,000.00 Jaguar           1,279.50  $       77,200,000.00 Iberoamericana              180.15  $         7,100,000.00 Servicios PJP4              180.15  $         7,100,000.00 Totals           2,919.30  $     168,600,000.00       General Summary – Blocks available - CNH-RO2-LO2/2016 Bid Round and Additional Royalties Min/Max values as published by SHCP on 17 May 2017   Basin Area Number Area sq km CNH Est 3P Prospective Resources MMboe Type Hydrocarbons Number of Fields Included Fields Original Hydrocarbons in Place MMboe RF from Fields Total Work Units Mininum Additional Royalties % Maximum Additional Royalties % Burgos 1               360.30 44.3 Gas & Cond 3 Bragado, Chalupa,Leyenda 4.4 19.2 6,000            2.40        25.00 Burgos 2               374.60 33.9 Gas & Cond 0   0   4,000            2.40        25.00 Burgos 3               447.90 36.7 Gas & Cond 5 Simbad, Conquistador, Alambra, Vigia, Pobladores 7.2 1 7,500            2.40        25.00 Burgos 4               440.30 26.7 Gas & Cond 8 Ecatl, Fiton, Fosil, Granaditas, Ita, Pipila, Rusco, Ternero 19.3 43.8 8,300            2.40        25.00 Burgos 5               444.60 30.5 Gas & Cond 11 Aljibe, Anona, Jabalina, Organdi, Pame, Patriota, Casta, Rio Bravo, Unicornio, Visir, Yac 16.8 16.6 9,300            2.40        25.00 Burgos 6               479.00 50.1 Gas & Cond 2 Pinta, Presita 8.1 4 5,100            2.40        25.00 Burgos 7               445.00 34.4 Gas & Cond 6 Dieciocho de Marzo, Corzos, Galaneno, Guillermo Prieto, Parritas, Villa Cardenas 30.6 54.8 7,800            2.40        25.00 Burgos 8               416.10 59.9 Gas & Cond 0   0   4,500            2.40        25.00 Burgos 9               464.00 40 Gas & Cond 0   0   4,000            2.40        25.00 Sureste 10               349.00 47.3 Oil & Gas 4 Acahual, Acachu, Guiro, Viche 6.8 43.1 5,900            3.90        45.00 Grand Totals 10              4,220.80                             403.80                     39                                93.20           CNH-RO2-LO2/2016 Bid Round – Final List of Qualified Companies and Consortia – 5 July 2017   Count CNH-RO2-LO2/2016 Bid Round - Final Participating Companies - Individual - 4 1 Ecopetrol Global Energy, S.L.U. 2 Gran Tierra Mexico Energy, S. de R.L. de C.V. 3 Iberoamericana de Hidrocaruburos, S.A. de C.V. 4 Perseus Exploracion Terrestre, S.A. de C.V. Count CNH-RO2-LO2/2016 Bid Round - Final Participating Consortia - 5 1 Iberoamericana de Hidrocaruburos, S.A. de C.V. / Newpek Exploracion Y Extraccion, S.A. de C.V. / Verdad Exploration Mexico LLC 2 Iberoamericana de Hidrocaruburos, S.A. de C.V. / Servicios PJP4 de Mexico S.A. de C. V. 3 Newpek Exploracion Y Extraccion, S.A. de C.V. / Verdad Exploration Mexico LLC 4 Sun God Energia de Mexico, S.A. de C.V. / Jaguar Exploracion Y Produccion De Hidrocarburos, S.A.P.I. de C.V. 5 Tecpetrol International S.L.U. / Grupo R Exploracion y Produccion, S.A. de C.V.     Companies List - CNH-RO2-LO2/2016 Bid Round - as of 28 April 2017 Company Companies that have paid Access to the Data Room Companies that have begun the prequalification process Ecopetrol S.A. 1 1 Geo Power Solution, S. de R.L. de C.V. 2 2 Gran Tierra Mexico Energy, S. de R.L. de C.V. 3 3 Iberoamericana de Hidrocaruburos, S.A. de C.V. 4 4 Jaguar Exploracion Y Produccion De Hidrocarburos, S.A.P.I. de C.V. 5 5 Lewis Energy Mexico, S. de R.L. de C.V. 6   Newpek Exploracion Y Extraccion, S.A. de C.V. 7 6 Perseus Exploracion Terrestre, S.A. de C.V. 8 7 Tecpetrol International S.L.U. 9 8 Total E&P Mexico, S.A. de C.V. 10 9  

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.15 op. by TOTAL (60.0%, SHELL 40.0%) to be check.14 op. by ENI SPA (60.0%, CITLA 40.0%) 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.

Duyung PSC, offshore W. Natuna Basin, PTD 1,370m, prospect NE + beneath the main Mako field, en route to PTD 1,370m, top reservoir at 389m, overall 25m sst in the Intra-Muda (only 7.3m in Mako S.-1), gas composition + pressure shared by both wells, to be P&A'd after target deeper Tambak prospect encountered, Asian Endeavour I JU. It follows Tambak-2 which encountered 9.1m net gas pay but testing failed on tech probs (DEA 25 Oct '19). 15% farmin wells for Coro Energy, partners otherwise Conrad (op) + Empyrean.

Tambak-1 appr/expl in Duyung PSC, offshore W. Natuna Basin, PTD 1,370m, prospect NE + beneath the main Mako field, en route to PTD 1,370m, top reservoir at 389m, overall 25m sst in the Intra-Muda (only 7.3m in Mako S.-1), gas composition + pressure shared by both wells, to be P&A'd after target deeper Tambak prospect encountered,

Talon Petroleum is offering significant equity in return for funding a well to test the Skymoos prospect in licence P2363 (blocks 14/29a & 14/30a). The prospect is located to the north of Equinor’s Verbier Discovery and to the east of the Scott and Telford fields. The prospect is defined as a large stratigraphic/structural combination trap. Encounter Oil estimate Skymoos to hold a most likely STOIIP of 269 MMbo with a potential upside of 1,003 MMbo. The company estimate the well to cost GBP 9 million. Talon acquired the previous licence holder Encounter Oil on 15 May 2019 and announced that it had received strong interest from potential partners and is confident in securing partners in the near term. As of November 2019 the opportunity was confirmed to be still available. The turbidite Burns Sands form the primary reservoir objective. The sands were derived from eroded Devonian Sandstones from the Halibut Horst to the north. During the late Volgian the sands were deposited in the Railway Cuttings Graben with maximum thicknesses of 400 feet. The prospect is dip closed to the north, south and west with a maximum closing contour of 8,100 feet and the crest of the structure lies at 7,600 feet. The oil is interpreted to be sourced from the Kimmeridge Clay Formation and Encounter expect a light oil to be present in the prospect with API’s estimated between 30° and 35°.  Licence P2363 was awarded on 1 October 2018 in the 30th Seaward Licensing Round. Two exploration wells have been drilled in the acreage with the first being 14/30a-1 by Total in December 1977 but was dry and abandoned in January 1978. EnCore spudded appraisal well 14/30a-5 on 17 November 2011 targeting the Tudor Rose discovery. On 20 December 2011, the company reported that the well had reached a TD of 1,094m. It encountered an oil column within the target Beauly Formation and the oil water contact was interpreted at 986 m. Hydrocarbon samples were taken, pressure tested and the reservoir was wireline logged. The wellsite analysis of the hydrocarbons sampled indicates a viscosity of 600-800 Cp - this was likely to be too viscous to be commercially exploitable at the time of drilling. The well was plugged and abandoned on 22 December 2011. Interest in P2363 is held solely by Talon Petroleum Ltd (100% + operator). For further information please contact:  Matt Worner – matt@talonpetroleum.com.au 0061 429 522 924

Talon Petroleum is offering significant equity in return for funding a well to test the Skymoos prospect in licence P2363 (blocks 14/29a & 14/30a). The prospect is located to the north of Equinor’s Verbier Discovery and to the east of the Scott and Telford fields

Equinor has acquired a 20% stake from Repsol in Walker Ridge blocks 321, 322, 365 + 366 near its Monument prospect in WR 272 + 316 (due to spud soon, w.o. Pacific Khamsin DS). The move is part of an acreage swap which saw Repsol earlier take 20% in Monument. The farmed-in acreage hosts the Paleogene Mollerussa prospect, now shared by Repsol (op), Ecopetrol + Equinor.

Equinor has acquired a 20% stake from Repsol in Walker Ridge blocks 321, 322, 365 + 366 near its Monument prospect in WR 272 + 316 (due to spud soon, w.o. Pacific Khamsin DS).

KPOGC secured sole rights to the Lakki 3270-9 EL, 2,029 sq km in the Potwar Basin onshore, on 12 Sep ‘18. It lies in the Bannu, Lakki Marwat and Dera Ismail Khan districts of the Khyber Pakhtunkhwa prov.

KPOGC secured sole rights to the Lakki 3270-9 EL (2029km²) onshore block.

Europa announces the conditional acquisition of FEL 3/19, Erris Basin off NW Ireland, from DNO. The 956-sq km permit contains the 1.2 Tcf Edge prospect, adding onto Europa's other regional assets. It is being acquired for a nominal upfront fee and the granting of a 5% net profits interest over future production to DNO. The deal is pending authority approval.

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

Santos QNT Pty Ltd, a subsidiary company of Santos Ltd, was awarded production licence PL 1028, located in the Cooper-Eromanga Basin, on 4 June 2018. The licence was applied for in March 2017 and has now been awarded for a period of 15 years. The licence lies to the south of the Cuisinier producing oil field, which was discovered in May 2008 and has been onstream since June 2010.  The Cuisinier 19 appraisal well, which successfully encountered oil, lies within the PL 1028 area. PL 1028, which covers an area of 12 sq km, was awarded on 4 June 2018.  Participants in the licence are Santos QNT Pty Ltd (54.64% + Operator), Bengal Energy Ltd (30.36%) and Bridgeport (Cooper Basin) Pty Ltd (15%).

Santos QNT Pty Ltd, a subsidiary company of Santos Ltd, was awarded production licence PL 1028, located in the Cooper-Eromanga Basin,

Sava 10 block, Slavonian sub-basin in NE Croatia, Jul-Aug ’19 well to TD 1,270m, tested up to 10.6 MMcfg/d from the Miocene, completed for production.

Berak-1 nfw Sava 10 block, Slavonian sub-basin in NE Croatia, Jul-Aug ’19 well to TD 1,270m, tested up to 10.6 MMcfg/d from the Miocene, completed for production.

PEDL 234, south of Billingshurst in West Sussex, naturally fractured Kimmeridgian Limestone 5 reservoir flowed 10-72 bo/d during 96 hrs of near-continuous rod-pumping. Oil is mixed with returned reactants after an acid-wash programme, oil cut 30%. Testing continues to clean up.

Broadford Bridge 1 op. by UKOG (100%) in PEDL 234, naturally fractured Kimmeridgian Limestone 5 reservoir flowed 10-72 bo/d during 96 hrs of near-continuous rod-pumping. Oil is mixed with returned reactants after an acid-wash programme, oil cut 30%. Testing continues to clean up.

On 11 November 2017, Trident Petroleum signed an Exploration & production agreement with EGPC for the Magawish block, Gulf of Suez. The deal includes a minimum expenditure of USD 2.4 million and a bonus of USD 500,000. The company is committed to drilling four wells in the block. The Magawish block may refer to North Magawish that was pre-awarded to Cherion-Pico in August 2015. On 3 August 2015, Ganope announced that Cheiron Magawish (Cherion-Pico) was awarded the North Magawish (Block 4) concession as a result of the Ganope International Bid Round 2014. The block covers 194 Sq mm and it is located in the Gulf of Suez Basin in water depth up to 57 m. The block already includes 10 wells drilled between 1922 – 2006 by SUCO, SHELL, Amoco, and Lukoil. Prospective resources at the North Magawish block are estimated at a total of 4.21 MMbo. Commitments include a minimum investment of USD 23.5 million and a signing bonus of USD 1 million to drill two exploration wells.

Trident has been awarded Magawish block (194km²).

Talon Petroleum has agreed to acquire EnCounter Oil. Under the terms of the deal Talon will acquire licences P2363 (Skymoos prospect) and P2392 (Rocket prospect) along with the two founders of EnCounter Oil. The Rocket prospect is thought contain prospective resources of 27 MMbo and is a Paleocene Cromarty reservoir target with an overlying Tay Sandstone upside. The acreage borders the Greater Catcher Area development with the Rocket prospect analogous to the Catcher Area discoveries. The Skymoos prospect is thought to contain 107 MMbo of prospective resources. It is located north-east of the Goldeneye field in block 14/30a. It is a structural/stratigraphic closure within the Upper Jurassic Burns sandstone reservoir with additional potential in the underlying Claymore sandstones. It has many similar geological characteristics to Buzzard. Both prospects are available for Farm-out. Following completion of the acquisition Talon Petroleum will hold 100% interest in the acreage.

Talon Petroleum acquired EnCore Oil’s 100% interest in the recently awarded licences P2363 (Moray Firth) and P2392 in Central Graben.

In April 2020 it was reported that Total has an agreement with Sonatrach to build a solar photovoltaic (PV) power plant at the Tin Fouye-Tabankort (TFT) oil/gas/condensate field, Illizi Basin, to power the production facilities and valorize the saved fuel gas through export. It is understood that the plant will have a capacity of 5MW. The TFT field is understood to produce currently around 290 MMcf/d of gas, it is operated by the "Groupement TFT". Participants in Groupement TFT are: Sonatrach with 51%, Total with 26.4% and Repsol with 22.6%. Eni has a similar partnership with Sonatrach at the Bir Rebaa Nord oil/gas field in the Berkine Basin. In March 2017 representatives of Sonatrach and Eni kicked off the construction of the Bir Rebaa photovoltaic (PV) plant which will cover 20 ha and have a capacity of 10 MW. The electricity generated by the plant will power the oil field’s production facilities. This will make available the gas previously used in power generation for a better valorization.

Algeria, Bir Rebaa

Tap has signed a sale agreement with Kensington Energy to dispose of its residual Australian and New Zealand holdings. Involved are 20% in BHP’s WA-72-R (Tallaganda gas find), 15% in Eni’s WA-25-L (Woollybutt field), 5% orri on o+g+c over 66.67% in PMP 38748 (Sidewinder field). Effective date of the sale is 31 Mar ’19.  Tap is still working on exiting WA-34-R (Prometheus + Rubicon fields), completion expected by year-end.

Australia, WA-25-L

Lion has agreed to acquire Gulf Petroleum’s 16.5% stake in the Seram (Non-Bula) PSC, 1,305 sq km on/offshore Seram island, bringing its full interest to 19% via Seram Energy Pte Ltd. The deal is costed at USD 44 MM and will be made retro-effective 1 Nov ‘18. Partners otherwise Citic (op), Petro Indo Mandiri  + GHJ.

Indonesia, Seram (Non-Bula)

In late March 2020, INA-Industrija nafte d.o.o. (INA) received the final award of the Sjeverozapadna Hrvatska 1 (SZH-1) block in northern Croatia. The grant followed a decision of the Government that authorized the Ministry of Energy to sign off the contract. The Sjeverozapadna Hrvatska 1 permit is solely operated by INA. The contract has a three-year exploration term, with an option for a two-year extension. The 1,361 sq km Sjeverozapadna Hrvatska 1 block, located along the border with Hungary and Slovenia, falls within the Mura Sub-basin, tectonic unit of the Pannonian Basin. The contract is the result of the country's third onshore tender call, organised in late 2018/2019. The news on the award was publicised by INA on 30 March 2020. Background Information Croatia’s 2nd onshore bidding round was announced on 31 October 2018 and closed on 28 June 2019. The Croatian Hydrocarbon Agency (CHA) was tendering seven blocks in the northern part of the country: Drava 3 (DR-3), Sava 6 (SA-6), Sava 7 (SA-7), Sava 11 (SA-11), Sava 12 (SA-12), Sjeverozapadna Hrvatska 1 (SZH-1) and Sjeverozapadna Hrvatska 5 (SZH-5). The Government of the Republic of Croatia, acting through Croatian Hydrocarbon Agency, announced on 29 August 2019 that it had pre-awarded the Sjeverozapadna Hrvatska 1 (SZH-1) block in northern Croatia to INA. The pre-award is a prerequisite to opening negotiations for the contract. The signing of the final contract was expected in late 2019/early 2020. The Sjeverozapadna Hrvatska 1 is holding several producing oil and gas fields operated by INA. The first exploration operation - seismic survey - is expected in the second half of 2020.

INA received the final award of the Sjeverozapadna Hrvatska 1 (SZH-1) block in northern Croatia.

Petrobras has issued a teaser offering to sell interests in 15 ANP round 11 + 12 blocks in the Sergipe-Alagoas onshore. Involved are 100% in 8 blocks, 50% (operated) in 3 blocks, 50% (non-operated) in 4 blocks (Nova Petroleo op). Expressions of interest to caetes@petrobras.com.br by 8 Nov '19, qualification docs to caetes@petrobras.com.br by 14 Nov '19. Block details from GEPS.

Petrobras has issued a teaser offering to sell interests in 15 ANP round 11 + 12 blocks in the Sergipe-Alagoas onshore. Involved are 100% in 8 blocks, 50% (operated) in 3 blocks, 50% (non-operated) in 4 blocks (Nova Petroleo op).

East Bahariya Ext.III (Bolt), onshore Abu Ghardiq Basin, TD 3,968m, spudded 12 Nov ’18, abandoned in late Dec ’18, results unreported, EDC-47 land rig. Qarun Petroleum = EGPC, Apache, Dana + Sinopec.

Bolt 122-1 expl (Qarun Petroleum = EGPC, Apache, Dana + Sinopec) East Bahariya Ext.III (Bolt), onshore Abu Ghardiq Basin, TD 3,968m,abandoned in late Dec ’18, results unreported,

The Ministry of Energy and Petroleum is offering 33 open blocks on an open door policy. As of early 2018, the open blocks were:  Basin Names Block Name Block Sqkm Chad Basin~Termit Trough - Chad Basin Aborak 24,760 Chad Basin~Grein-Kafra Trough~Tenere Rift - Chad Basin Achegour 17,012 Iullemmeden Basin~Tahoua Depression (Iullemmeden Basin) Ader 31,174 Chad Basin~Bilma Trough - Chad Basin~Djado Basin Araga 28,196 Iullemmeden Basin~Mantass Depression (Iullemmeden Basin) Azawak 29,085 Iullemmeden Basin~Mantass Depression (Iullemmeden Basin)~Tahoua Depression (Iullemmeden Basin) Dallol 41,248 Chad Basin~Iullemmeden Basin Damagaram 29,680 Chad Basin~Termit Trough - Chad Basin Dibella 1 20,418 Chad Basin~Bodele Sub-basin (Chad Basin) Dibella 2 29,628 Djado Basin~Chad Basin Dissilak 19,924 Djado Basin Djado 1 14,121 Djado Basin Djado 2 12,694 Djado Basin Djado 3 11,288 Djado Basin Djado 4 11,981 Chad Basin~Tenere Rift - Chad Basin~Grein-Kafra Trough Grein 16,010 Chad Basin Homodji 33,118 Tamesna-Talak Depression (Iullemmeden Basin)~Iullemmeden Basin Irhazer 25,758 Djado Basin~Chad Basin Karama 30,347 Chad Basin~Termit Trough - Chad Basin Manga 1 12,258 Chad Basin~Termit Trough - Chad Basin~Ngel Edji Trough - Chad Basin Manga 2 11,712 Termit Trough - Chad Basin R5 2,710 Tihemboka Arch R6 3,055 Chad Basin~Djado Basin~Grein-Kafra Trough~Hoggar Massif Seguedine 22,570 Iullemmeden Basin~Tahoua Depression (Iullemmeden Basin) Tadarast 39,972 Chad Basin~Hoggar Massif Tafassasset 21,965 Iullemmeden Basin~Tamesna-Talak Depression (Iullemmeden Basin)~Tahoua Depression (Iullemmeden Basin)~Air Massif Talak 30,120 Iullemmeden Basin~Tamesna-Talak Depression (Iullemmeden Basin) Tamesna 25,711 Tahoua Depression (Iullemmeden Basin)~Iullemmeden Basin~Nigerian Shield Tarka 43,342 Djado Basin Tchigai 21,160 Iullemmeden Basin~Chad Basin~Nigerian Shield Tegama 32,193 Chad Basin~Termit Trough - Chad Basin~Tefidet Rift - Chad Basin~Tenere Rift - Chad Basin Tenere Ouest 22,367 Iullemmeden Basin~Mantass Depression (Iullemmeden Basin)~Voltaian Basin Tounfalis 37,741 Mantass Depression (Iullemmeden Basin)~Iullemmeden Basin Yaris 30,807 Source, IHS Markit 2018            

Niger, Tenere

In late April 2020, Houston Energy transferred operatorship in the undrilled Green Canyon Block GC 939 to Beacon Energy, via its local subsidiary, BOE Exploration & Production. The block was originally offered as part of OCS Lease Sale 250, held in March 2018 and is sited 10km due south from Chevron's oil and gas Anchor development project. Houston Energy was awarded Green Canyon Block GC 939 (G36308) on 1 June 2018. In December 2018, Houston Energy divested operatorship and the large majority of its 100% WI stake in GC 939 to Murphy Exploration & Production — USA, Red Willow Offshore and Deep Gulf Energy III (Kosmos subsidiary). Equity in GC 939 is presently shared between Houston Energy (52.22222%), Murphy Exploration & Production – USA (20%), Red Willow Offshore (22.77778%) and CL&F Offshore (5%). BOE Exploration & Production (Beacon) now operates the lease.

Houston Energy transferred operatorship in the undrilled Green Canyon Block GC 939 to Beacon Energy, via its local subsidiary, BOE Exploration & Production.

Clark Oil and Gas Pty Ltd is offering a farm-in opportunity in its operated exploration permit ATP 840-P, located in the Taroom Trough, Bowen-Surat Basin. Clark reports that it is looking to initially acquire funding for three wells within the permit, in return for significant equity in the exploration phase. There would also be the opportunity for further participation, in upstream and downstream phases if feasible. Clark reports that the permit, which lies in the central-east part of the Taroom Trough, is prospective for unconventional, basin-centred gas and liquids, with a thick stratigraphic section with multiple reservoir intervals thought present.  There is also the potential for deeper marine shales. It is reported that fracking may be required during the three-well programme. The permit lies close to infrastructure and Clark reports would be well placed to supply the export and East Coast markets, should a development be viable from any discoveries. ATP 840-P, which covers an area of 456 sq km, was awarded on 27 February 2007. The block was originally offered as LR2006-1-2P as part of the 2006 Queensland Government competitive tendering for petroleum exploration under Authorities to Prospect. Clark renewed the permit in 2012 and it is currently due to expire, or be further renewed, in February 2019. Red Sky Energy held interest in the permit between 2010 and 2013 and the two companies had previously been jointly looking to farm-out interest. Clark Oil and Gas is now looking to farm-out significant equity in return for funding three wells. Companies interested in this opportunity should contact: Rod Bresnehan, Chief Operating Officer Email: Rod@clarkoilandgas.com.au Tel: +61 407 961 609 Peter Nichols, Exploration Manager Email: Peter@clarkoilandgas.com.au Tel: +61 438 384 704

Clark Oil and Gas Pty Ltd is offering a farm-in opportunity in its operated exploration permit ATP 840-P, located in the Taroom Trough, Bowen-Surat Basin. Clark reports that it is looking to initially acquire funding for three wells within the permit, in return for significant equity in the exploration phase.

On 29 October 2018, Eni announced that it signed a farm-in agreement with Sonatrach to farm into three exploration blocks in the Berkine Basin, south-eastern Algeria. The blocks are: Sif Fatima II, Zemlet El Arbi and Ourhoud II. Interests will be split as follows: Eni 49% and Sonatrach 51%. The blocks are located in the northern part of the Berkine Basin where Eni operates already oil and gas production from several fields in the Sif Fatima area and the Menzel Ledjmet area. The company recently launched two infrastructure projects to support its development activities: a photovoltaic power plant and a gas pipeline. Under an agreement signed in July 2018, Sonatrach and Eni will aim to create a gas hub in the basin based on the Bir Rebaa Nord and the Menzel Ledjmet Est fields. The idea is to use gas made available from Bir Rebaa Nord (and probably other fields nearby in the future) for export through the Menzel Ledjmet Est gas plant which becomes the center of the hub. Part of the project is the construction of a 180 km gas line which will connect Bir Rebaa Nord and Menzel Ledjmet Est. In March 2017 representatives of Sonatrach and Eni kicked off the construction of the Bir Rebaa photovoltaic (PV) plant at the Bir Rebaa Nord oil field. The plant will cover 20 ha and have a capacity of 10 MW. The electricity generated by the plant will power the oil field’s production facilities. This will make available the gas previously used in power generation for a better valorization. Eni’s announced farm in into the three exploration blocks fits the company’s strategy to develop resources in the Berkine Basin which becomes an important production center. The company estimates that the three exploration blocks, covering together 8,500 sq km, hold reserves of 145 MMb of oil equivalent which should be confirmed through an important exploration program. First production is expected to start by the end of 2020. Eni is currently participating in 32 production permits in the Berkine Basin with a production of 90,000 boe/d net to the company.

Algeria, Bir Rebaa

Santos Ltd reported that it had reached an agreement to farm-in to five Papuan Basin licences, held by Oil Search Ltd and ExxonMobil PNG Ltd, on 9 November 2017.  Santos will be acquiring a 20% interest in exploration licences PPL 395, PPL 464, PPL 487 and PPL 545 and in exploration application APPL 507, which is pending ministerial grant.  The five areas lie between the Hides and P’Nyang gas fields, along a trend that is being explored for additional gas resources.  Santos had previously farmed into PPL 402, in the same area, and reported that its more recent farm-in brings alignment of interests across this trend. Within PPL 402 the Muruk gas discovery was made post-Santos’ farm-in, in mid-2017.  This will be appraised in early 2018. Additional wells are being planned in the additional five blocks, with Blucher 1 being outlined as a potential drill target for 2018, within PPL 395.

Papua New Guinea (Papuan Fold Belt (Papuan B.)) (It's a petroleum rights. Please summarize by yourself). In IHS database: PPL 487 op. by EXXONMOBIL (50.0%, OIL SEAR P 50.0%) to be check.APPL 507 op. by OIL SEAR P (50.0%, EXXONMOBIL 50.0%) to be check.PPL 464 op. by OIL SEAR P (50.0%, EXXONMOBIL 50.0%) to be check.PPL 545 op. by OIL SEAR P (40.0%, EXXONMOBIL 40.0%, JX HOLDG 20.0%) to be check.PPL 402 op. by OIL SEARCH (37.5%, EXXONMOBIL 42.5%, SANTOS 20.0%) to be check.PPL 395 op. by OIL SEAR P (50.0%, EXXONMOBIL 50.0%) to be check.

Faroe Petroleum has agreed to acquire 100% interest in block 30/14a Edinburgh (P255) from Total. In an announcement from Faroe on 16 January 2019 the company stated that it was in the process of equalising interests in cross border blocks 30/14a, 30/14b and Norway blocks 1/6 and 1/9 in which the cross-border Edinburgh prospect is situated. The prospect sits at the south-eastern end of the prolific Josephine Ridge area. It is a large, tilted Mesozoic fault block and covers an area of 40 sq km. The acreage was previously held by Maersk and acquired by Total via the acquisition of the Danish major. The deal is pending completion. Edinburgh is thought to be one of the largest remaining undrilled structures in the Central North Sea. The prospective reservoirs include the Upper Jurassic Ula age-equivalent (Freshney and Fulmar) and Triassic Skagerrak formations. Following completion of the deal and then a subsequent equalling of interests in the block will be held by Faroe Petroleum (45% + operator), Shell (40%) and Spirit Energy (15%).

United Kingdom, P255

End year 2017, Swala Oil and Gas (Tanzania) plc (Swala) confirmed its acquisition of the local subsidiary Surestream Petroleum (Burundi) Ltd, wholly-owned by Surestream Petroleum Limited that operates the Block D. The company entered into an agreement with Surestream in September 2016. Block D is under a state of Force Majeure since September 2016. The company will decide in the next few months if the political situation improves sufficiently to withdraw the state of Force Majeure, in which case Swala will start looking for partners to share the cost of the exploration commitments. The 866 sq km licence is located in the Tanganyika Graben (EARS, West Branch) on the Lake Tanganyika. Geological interpretations for Block D indicate the presence of shallow fault block plays with basal sands charged from a deep kitchen in the west (the Kigoma kitchen). Oil seepages both onshore and on the surface of the lake prove the presence of hydrocarbons, although none of the two exploratory wells drilled in Burundi to date (Ruzizi 1 and Buring 1) has hit any oil column so far. The Lake Tanganyika lies on the western branch of the East African Rift System. It extends north-south for over 670 km, averages 50 km in width and covers 32,000 sq km, with a mean and maximum depth of 570 m and 1,470 m, respectively. The western strand lies in the Democratic Republic of Congo (DRC) and Zambia, while the eastern strand stretches from Burundi to Tanzania. In the northern part of the lake, the thickest sedimentary column is expected on the DRC side. The basin in Burundi is believed to be the strongest analogue to the Albertine Basin in Uganda and consists of several half grabens with Neogene-aged rift sediments.

Swala O&G confirmed its acquisition of the local subsidiary Surestream Petroleum, concerning is Block D under a state of Force Majeure since September 2016.

OMV GSB Ltd, a wholly owned subsidiary of OMV AG, spudded the Tawhaki 1 exploration well in PEP 50119, located in the Great South Basin, on 7 January 2020. The well was drilled to a total depth of 2,980 m by the COSL Drilling Europe AS owned "COSL Prospector" rig. On 20 February 2020 joint venture partner Beach Energy Ltd reported that the well was to be plugged and abandoned after failing to encounter hydrocarbons. Reports suggest that drilling remained temporarily suspended in early February 2020 following the accidental activation of the blow-out preventor (BOP), resulting in the drill pipe being sheared, in late January 2020. The Environmental Protection Authority (EPA) was informed and no volumes of harmful substances released into the environment exceeded that permitted by the marine discharge consents. Following the temporary suspension of drilling, operations resumed in early to mid-February 2020. The commitment well was the second of a multi-well exploration campaign being undertaken by OMV in the Taranaki and Great South basins. The "COSL Prospector" rig was contracted to drill the well which arrived on location on 2 January 2020 after drilling Gladstone 1 in the Taranaki Basin. The well was planned to be drilled to a total depth of 2,977 m with the last casing point at 2,558 m. The Tawhaki prospect lies in the eastern portion of the permit in a water depth of approximately 1,300 m. Here, a thick package of Cretaceous and Paleocene marine shales seal Cretaceous sands draped over a basement high. The prospect had a mapped closure of up to 470 sq km with recoverable resources of up to 1 Bbbl of oil. OMV reported that potential oil charge had been modelled from Cretaceous syn-rift coals and that the Tawhaki prospect is thought to be analogous to the Utsira High in the North Sea, which includes the Ivar Aasen, Johan Sverdrup and Ragnarock fields. These contain potential recoverable reserves of approximately 3,000 MMboe. The final consents for marine discharge were granted by the Environmental Protection Authority (EPA) on 16 December 2019. The first consents were granted on 11 September 2019. OMV had previously been offering equity via farm-in to PEP 50119. Beach Energy Ltd announced on 19 December 2019 that it had reached an agreement with OMV to farm-in to the permit. The deal would see Beach acquire 30% interest in the permit from OMV by funding 30% of the well costs. PEP 50119 covers an area of 16,760 sq km in deep water and was awarded on 11 July 2007. On completion of the farm-in deal, participants in the permit will be OMV New Zealand Ltd. (52.93% plus operatorship), Beach Energy Ltd (30%) and Mitsui E&P Australia Pty Ltd (17.07%).

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

Glauca 1 & 2 op. by Parex (100%) in VMM-11 block, wells were drilled and both wells found oil bearing reservoir in Esmeraldas Fm. Testing of the wells required an effective cleanout of sand from wellbore. After cleaning out the sand in Glauca 2 wellbore, over a 50 hour test, the well produced 314 bo/d of 15,3°API oil with no reported water production.

Glauca 1 & 2 op. by Parex (100%) in VMM-11 block, wells were drilled and both wells found oil bearing reservoir in Esmeraldas Fm. Testing of the wells required an effective cleanout of sand from wellbore. After cleaning out the sand in Glauca 2 wellbore, over a 50 hour test, the well produced 314 bo/d of 15,3°API oil with no reported water production.

Key has agreed to farm-out a 50% non-operating interest in L7 (Mount Horner oilfield), 145 sq km onshore Perth Basin, to Triangle Energy, who will fund 3D seismic + 2 explo wells capped at US$3 MM.  A workover programme is also planned next year, after which Triangle will have an option on operatorship.

Australia, L 7

Lundin is to acquire a 10% stake from Wintershall Dea in PL 894, home to the 2018 Balderbrå find for which devt is no longer considered to be commercial (ref. disappointing appraisal, DEA 26 Feb ’20). Upon govt approval, partnership to become Wintershall Dea (op), Equinor, Petoro + Lundin.

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).

Skye Alba Pty Ltd has become sole holder of WA-498-P after taking over the interests of Santos and JX Nippon O&G (75:25), effective 14 Dec ‘18.  The 81-sq km block lies in the N. Carnarvon Basin.

Skye Alba Pty Ltd has become sole holder of WA-498-P after taking over the interests of Santos and JX Nippon O&G (75:25), effective 14 Dec ‘18. The 81-sq km block lies in the N. Carnarvon Basin.

On 8 November 2018, the Federal Agency for Subsoil Use held an auction for the Leskinskiy block in Krasnoyarsk Kray (Eastern Siberia). Gazprom Neft-Aero Bryansk won the contest with the offer of RUB 504.9 million (USD 7.6 million). The winner of the auction will obtain a 27-year E&P license including a 7-year exploratory stage. The Leskinskiy block covers 3,027 sq km in the Yenisey-Khatanga Basin with some extension into the South Kara-Yamal Province. Seismic coverage amounts to 288 km. No wells have been drilled in the block. Hydrocarbon resources (category D2) of the block are estimated at 73 MMbbl of oil and 3.9 Tcf of gas. The starting price amounted to RUB 27 million (USD 0.4 million).

Russia Gazprom Neft wins Leskinskiy license in Krasnoyarsk

As of December 2018, it is understood that Serica Energy plc (Serica) is still looking to farm out a stake in its PEL 0047 (Blocks 2512A, 2513A&B and 2612A (part)). The licence covers roughly 17,400 sq km in the Lüderitz Basin. Water depth ranges from approximately 200 m to 3,000 m. The interests in the permit are shared between Serica’s wholly-owned subsidiary Serica Energy Namibia B.V., operator with 85%, the National Petroleum Corporation of Namibia (Pty) Ltd (NAMCOR) 10% and Indigenous Energy (Pty) Ltd 5%. The company is looking for a joint venture partner to earn a material percentage of its 85% working interst in the licence in exchange for a commitment to fund one well between 2019 and 2021. Operatorship is available to suitably qualified parties. In late 2018, Serica is understood to have received an extension to the first renewal period extending the validity of the licence to end December 2019. To date the company has identified four prospects, the most advanced being Prospect B. The prospect comprises a very large Lower Cretaceous carbonate platform with a P50 gross resource potential of 622 million barrels of oil. The Barremian structural closure with an aerial closure of 700 sq km and relief of 300 m has morphological similarities to known carbonate reservoirs worldwide. Oil may be sourced from the regionally proven late Barremian to early Aptian post-rift “Kudu Shale”, which is modelled as mature within the licence or from deeper syn-rift lacustrine shales. Prospect and Lead list  Prospect   Level P90 P50 Mean P10 Unit Prospect B Barremian 102 693 1928 4509 MMbo Aptian 17 171 729 1632 MMbo Prospect F Aptian 118 318 398 777 MMbo Prospect D Aptian 19 139 423 980 MMbo Channel Lead A Aptian 5 41 143 327 MMbo Source: IHS           © 2015 IHS   Serica announced on 1 October 2012 the completion of a 4,180 sq km 3D seismic survey in the south-eastern part of its licence. Conducted by Polarcus Seismic Ltd with the “Polarcus Nadia” vessel, the seismic programme started on 10 May 2012. The objective was to fully delineate a large four-way dip closed structure (Prospect B), identify potential pinch-out prospects and find hydrocarbon indicators. The data indicates the presence of significant channel sand features with associated strong seismic amplitudes. The survey was initially expected to be completed in three months but weather conditions disrupted the schedule. The full cost was met by BP. For futher information contact: graham.pritchardl@serica-energy.com Background Information On 3 November 2011, Serica confirmed the award of exploration rights over Blocks 2512A, 2513A&B and 2612A (part). The official signature of the petroleum agreement was announced on 4 January 2012. During the initial exploration period, which would last four years, 3D seismic data would be acquired and the existing 2D seismic data reprocessed. The interests in the permit were shared between Serica’s wholly-owned subsidiary Serica Energy Namibia B.V., operator with 85%, NAMCOR 10% and Indigenous Energy (Pty) Ltd 5%. Serica announced on 25 June 2012 that the Minister of Mines and Energy in Namibia had approved the assignment by Serica of a 30% interest in Blocks 2512A, 2513A&B and 2612A (part) to BP. Under the terms of the farm-in announced on 15 March 2012, BP agreed to a 30% interest in deepwater central Lüderitz Basin in return for the full cost of a 4,180 sq km 3D seismic survey across the licence. The interests were shared between Serica Energy Namibia B.V., operator with 55%, BP’s subsidiary Exploration (Lüderitz Basin) Ltd 30%, NAMCOR 10% (carried) and Indigenous Energy (Pty) Ltd (IEPL) 5% (carried). On 20 December 2013, Serica announced that BP had decided not to exercise an option to increase its interest in the Luderitz Basin licence. The option which expired at the end of 2013, required BP to drill one well within the licence prior to year end 2015. Under the terms of the agreement BP re-assigned its 30% interest to Serica, effective as of end 2013. Serica operates the licence through its wholly-owned subsidiary Serica Energy Namibia B.V. with and 85% interest, partners NAMCOR and Indigenous Energy (Pty) Ltd will hold 10% and 5% interests respectively.

Serica Energy plc (Serica) is still looking to farm out a stake in its PEL 0047 (Blocks 2512A, 2513A&B and 2612A (part)). The licence covers roughly 17,400 sq km in the Lüderitz Basin. Water depth ranges from approximately 200 m to 3,000 m.

Further to DEA 31 Aug ’18 (discovery): Ruche EAA (Dussafu Marine) block, WD 117m, TD 3,400m (Dentale), logged 15m oil pay in the Gamba fm + 25m stacked in the Dentale, sidetrack drilled 800m NW and encountered 34m pay in the Gamba + Dentale, well now suspended and assessment of potential to follow. Borr Norve JU. BWE (op), partner Panoro.

Gabon (South Gabon Sub-basin (Gabon Coastal B.)) Gamba

Navitas Petroleum, holding 53% working interest in the LLOG-operated Shenandoah project in the northwest quadrant  of the Walker Ridge (WR) protraction area in the deepwater central Gulf of Mexico, announced on 28 July 2020 that Beacon Offshore Energy (part of Blackstone Group) signed a preliminary agreement to acquire LOG's 30.95% stake in the project. This would increase Beacon's working interest from the current 15.95% to 46.9%. There was no mention whether Navitas or Beacon would assume operatorship. Earlier this month, a USD 250 million contract was awarded to Transocean for drilling and completing services at Shenandoah using the "Deepwater Atlas" drillship which is still under construction. In the 15 July 2020 announcement, Transocean indicated a Final Investment Decision (FID) for the project is expected by 31 March 2021. The development will include initial production from four wells (out of a total of eight), manufacturing and installation of subsea facilities, pipelines and a designated production platform. The platform will have a production capacity of over 70,000 boe/d and will be based on a regional-hub production model which LLOG successfully implemented at the Delta House and Who Dat fields. First oil for the field, which is estimated to hold 281 MMboe, is expected in 2023, but could be delayed. The Shenandoah unit covers blocks WR 51 (G31938), WR 52 (G25232) and the northern half of WR 53 (G28148). The field, discovered by Anadarko in 2009, consists of Paleogene-aged reservoirs and sits in about 5,600 ft (1707 m) of water, approximately 171 mi (276 km) southwest of the onshore support base at Port Fourchon, Louisiana.

United States (North Slope B.) 250 op. by NTH SLOPE (100%)

On 7 February 2018, the Federal Agency for Subsoil Use held an auction for the Roshchinskiy block in Bashkortostan Republic (Volga-Ural Province). Bashneft won the contest with the offer of RUB 41.736 million (USD 0.72 million). The winner will obtain a 25-year E&P license. The Roshchinskiy block covers 22 sq km and encompasses the small Roshchinskoye oil field with 3P reserves about 2 MMbbl and the Zimanovskiy prospect with oil resources estimated at 2 MMbbl. Oil resources (category D1) are estimated at 1 MMbbl. The starting price amounted to RUB 37.95 million (USD 0.65 million).  

Bashneft secured the Roshchinskiy block, 22 sq km around the small Roshchinskoye oilfield in the Bashkortostan Republic.

Egdon has picked up a further 20% from Terrain Energy in PEDL 005, 50 sq km mostly onshore in Lincolnshire (E. Midlands). The acreage contains the Louth prospect which Egdon hoped to farm-down before drilling later in 2020 or 2021. Egdon (op), partners Terrain + Union Jack Oil.

Egdon Resources (->85% op, Union Jack 15%) has completed the acquisition of a further 20% interest from Terrain Energy in PEDL 005 (block TF38b – Louth).

As of 6 May 2019, Tullow Oil subsidiary Tullow Peru LTD has received approval for a 35% working interest farmin of the Karoon Gas Australia offshore block Z-38 located off the northern coast of Peru in the Tumbres Basin, known regionally to the north as the Progresso Basin. Karoon Energy advised on 6 May 2019 that the transfer to Tullow Oil of a 35% interest in the 4,875 sq km license will be made in return for the 43.75% funding of the cost of the first exploration well, capped at USD 27.5 million and beyond which the company will pay its 35% share. In addition, the farminee will pay USD 2 million and a share of block costs incurred on and after 9 January 2018 at completion, as well as a USD 7 million in the case of a commercial discovery. Karoon will retain a 40% operating interest in Block Z-38, with partner Pitkin Petroleum holding 25%. The acreage lies in 300 to 3,000 m water depths and contains several leads and prospects, including notably Marina, which is expected to be drilled early in 2020. The prospect has a gross unrisked oil resource potential of 256 MMbbl, with the rest of the block possibly holding over 1 Bbbl. According to the company, the new acreage contains a number of attractive leads and prospects which include the Marina and Bonito prospect which together have the potential to hold close to 2-billion barrels of oil according to news reports. The Z-38 license is already covered by high quality 3D seismic and includes the Marina prospect which is a potential candidate for drilling in 2019. The block had been in force-majeure from 2014 through late 2018 as Karoon was not able to secure a drilling rig, the Tullow deal may resolve the situation as the company is probably in a better position to acquire a rig giving the group 22 months to drill a required two wells. Vietnam American Exploration Co LLC (Pitkin Petroleum) filed an application on the 4,885.06 sq km in January 2006 followed by the official award of the block on 8 June 2008. In January 2008 Karoon Gas Australia acquired a 20% working interest. Karoon Gas then acquired an additional 20% working interest in September 2009 bringing the working interest to Vietnam American Exploration 25% and Karoon Gas to 75%. Once the terms of the farm-out are met Tullow will then have 35%, Karoon Gas 40% and Vietnam American Exploration 25%.

Tullow Peru LTD has received approval for a 35% working interest farmin of the Karoon Gas Australia offshore block Z-38 located off the northern coast of Peru in the Tumbres Basin, known regionally to the north as the Progresso Basin.

As of 2020 Sudapet was willing to farm-out some of its 5% stake in Block 6, Muglad Basin. The block is operated through the Petro-Energy Operating Co, a joint venture between the CNPC (95%) and Sudapet (5%). The block hosts the producing Abu Gabra, Fula NE, Fula Fula N, Hadida, Jake, Jake S, Keyi, Moga and Sufian fields.

(Muglad b.) Block 6 operated by CNPC (95%), SUDAPET (5%), Sudapet was willing to farm-out some of its 5% stake. The block is operated through the Petro-Energy Operating Co, a joint venture between the CNPC (95%) and Sudapet (5%). The block hosts the producing Abu Gabra, Fula NE, Fula Fula N, Hadida, Jake, Jake S, Keyi, Moga and Sufian fields.

AGC Profond block, deepwaters MSGBC Basin, tentatively planned 2H ’19. It is recalled CNOOCI is looking for a partner in the 6,688-sq km permit to share the well costs, data room open, share negotiable. The block is home to 6 prospects, amongst which Wolverine (Barremian) + Civet (Albian). Contact: Robert.Hughes@nexencnoocltd.com.

AGC Profond block, deepwaters MSGBC Basin, tentatively planned 2H ’19. It is recalled CNOOCI is looking for a partner in the 6,688-sq km permit to share the well costs, data room open, share negotiable.

Source has acquired a further 10% in PL 878 from Equinor effective 31 Mar '20. PL 878 lies over part-blocks 30/2 + 30/3 N. Oseberg, 361 sq km. NFW 30/2-5 (Atlantis) is planned here this summer, PTD 4,381m, West Hercules SS. Equinor (op), partners Source + Wellesley.

Norway (Oseberg Fault Block (Horda Platform)) Oseberg

Europa Oil and Gas plc is offering interested parties to farm-in to Licence Option (LO) 16/22. Europa has interpreted good quality 2D seismic data which was acquired in 1998. The presence of structures of a significant size and multiple leads in both pre-rift and syn-rift hydrocarbon plays have been mapped in water depths ranging from 800 to 2,000 m. Europa is currently focused on maturing the leads to a drillable prospect status by utilising the historic 2D seismic data and wealth of high quality technical work previously carried out by major oil companies. Gross mean unrisked indicative resources are estimated to be in the range of 300 to 600 MMboe. A farm-in partner is being sought with whom to drill an exploration well. LO 16/22 is located in the Padraig basin which is a remnant Jurassic basin on the eastern margin of the Rockall Trough. The most relevant analogue for the Padraig is the conjugate margin play offshore Newfoundland in the Flemish Pass basin which was opened up Equinor’s play-making Bay du Nord oil discovery. Geochemical analysis of the oil extracted from drop cores in LO 16/22 have identified bisnorhopane biomarkers that indicate the presence of oil mature Jurassic (Kimmeridgian) source rocks. This geochemical study has proved the existence of a working hydrocarbon system and provides evidence that the Jurassic syn-rift stratigraphy is present and endorses the potential for a Flemish Pass style syn-rift play. Furthermore, the study suggests that the Padraig petroleum system shares the same source rocks as the Dooish oil discovery in the Rockall basin and the West of Shetland oil fields (Schiehalion, Clare and Lancaster) rather than the Porcupine basin source rock. LO 16/22 was awarded to Europa in July 2016 after a successful application in the 2015 Atlantic Margin Licensing Round. Europa were the most successful company in the round acquiring five new licences. LO 16/22 expires in June 2019 where Europa will decide to covert the licence into a Frontier Exploration Licence (FEL). Interest in LO 16/22 is held solely by Europa Oil and Gas Ltd. Murray Johnson Email: murray.johnson@europaoil.com

Ireland, not found

Shell has agreed to sell its 22.2222% interest in the Bongkot field and adjoining acreage* to PTTEP for USD 750 million. The deal is expected to complete 2Q ‘18, subject to usual conditions.  PTTEP is already optr of the assets, and its stake will increase to 66.6667%, Total holding the balance. * Blocks B15 (1,305 sq km), 16-17 (1,926 sq km) + G12/48 (32 sq km). PTTEP’s stake in Bongkot will increase to 66.6667%, with the remaining 33.3333% owned by Total. PTTEP is the current operator of Bongkot.  It is recalled in October last, Shell and Kufpec agreed to cancel the SPA which had been reached for a similar deal.

PTTEP (-> 66,6667%) is acquiring 22.2222% interest in the Bongkot field and in blocks 15, 16, 17 and G12/48 from Shell (->0%, Total 33,3333%)

Greater Tortue area, cross-border GTA block, WD 2,500m, TD 4,884m, ab. 30m Albian net gas pay encountered, Ensco DS 12 now off to drill Yakaar-2 appr across the border in Senegal, next well planned Orca-1 back in Mauritania in 3Q. Participants in the unitised GTA block are BP, Kosmos, Petrosen + SMHPM.

Greater Tortue Ahmeyim-1 (GTA) expl / devt (BP, Kosmos, Petrosen + SMHPM) Greater Tortue area, cross-border GTA block, WD=2500m, TD=4884m, ab. 30m Albian net gas pay encountered.

Equinor (previously Statoil) is farming down 20% in PL167 to Spirit Energy, awaiting regulatory approval as of 8 June 2018. The licence contains the Verdandi and Lille Prinsen discoveries. Recoverable resource estimates are 4 to 11 MMboe in Palaeocene Heimdal Formation at Verdandi, and 15 to 35 MMboe at Lille Prinsen, likely in Triassic sands. Potential upside has been identified within thin stringer sands of the Eocene Grid Formation in both discoveries. Lille Prinsen is located 2km S of Verdandi on the Utsira High, and the licence is located 4km NE of Ivar Aasen oil field which came online in December 2016, 5km SE from Hanz oil field which is being developed in the second phase of Ivar Aasen, and 8km NW of Johan Sverdrupp which will be brought into production in Q4 2019. PL167 was awarded in March 1991 in the 13th Licensing Round and originally covered 209 sq km on block 16/1, later reduced to 40.96 sq km in March 2000, and then to its current 21.36 sq km in January 2007. Pending completion of the Equinor-Spirit transaction, PL167 licensees are Equinor ASA (80% + Op) and Lundin Norway AS (20%).<P />

Equinor (previously Statoil) is farming down 20% in PL167 to Spirit Energy,

SW part of CNH-R02-L01-A10.CS/2017 / Area 10, Sureste Basin off Tabasco, WD 354m, drilled + susp. 20 Oct '19 – early Feb '20, Valaris 8505 SS. PTMD was 4,563m (4,421m TVD), targets Pliocene + Miocene, Eni (op), partner Lukoil.

Saasken 1EXP nfw. (Eni 80%, Lukoil 20%) in CNH-R02-L01-A10.CS/2017 contract, Area 10, suspended with results unreported during early-February 2020 at an unreported final TD, PTMD was 4 563m (4 421m TVD), targets Pliocene + Miocene.

On 20 February 2018, the award of the Orség contract in southwestern Hungary, pre-awarded to Magyar Olaj- es Gazipari Rt (MOL) in November 2017, was signed off by the Minister for National Development and thus became official. The 669 sq km Orség area is located in the Zala and Vas political provinces, within the Pannonian Basin. Background Information On 13 June 2017, acting on behalf of the Hungarian State and in cooperation with the Hungarian Office for Mining and Geology, the Minister for National Development published an invitation to tender for a concession over the Orség area. The tender closed on 25 September 2017. On 17 November 2017, following recommendation of the tender committee from the Hungarian Office for Mining and Geology, MOL was selected as the winner of the bid round for the prosection, exploration and production of hydrocarbons in the Orség area. The company had two months (plus additional two months extension) to negotiate the final contract.

Hungary, not found

SE part of Laguna de Los Capones permit within the wider Fracción C licence, onshore Austral Basin, TD 1,820m (Tobifera), suspending w/gas shows for possible testing and/or sidetrack, Petreven H-205 rig. Target gas in Springhill + Tobifera. Next well planned El Molino Sur, Fraccio´n C block south of above.  CGC (op), partner Echo Egy.

ELA-1 expl SE part of Laguna de Los Capones permit within the wider Fracción C licence, onshore Austral Basin, TD 1,820m (Tobifera), suspending w/gas shows for possible testing and/or sidetrack, Petreven H-205 rig. Target gas in Springhill + Tobifera. Next well planned El Molino Sur, Fraccio´n C block south of above. CGC (op), partner Echo Egy.

Location between LF 7-2 and LF 13-2 fields, Lufeng Sag, PRMB, WD 120m, ops terminated mid-Jun ’19, Nanhai 5 SS. Target Miocene Zhujiang fm.

Lufeng 7-10-1d (LF7-10-1d) nfw Location between LF 7-2 and LF 13-2 fields, Lufeng Sag, Lufeng Sag, PRMB, WD 120m, ops terminated mid-Jun ’19 Target Miocene Zhujiang fm. Results n/a.

Questerre has completed the acquisition of Utica shale assets from partner Repsol. These comprise 16 tracts 3,000-odd sq km in the Saint Lawrence Lowlands of Quebec, at a cost of CAD 16.1 MM to Questerre.

Questerre Energy announced that it has closed the acquisition of Utica shale gas-prone assets in the Saint Lawrence Lowlands from Repsol, consisting of exploration rights to 753,000 net acres (3,047 sq km). According to Questerre, an independent resources assessment has placed the area's contingent and prospective gas resources at 3.9 Tcf and 21.3 Tcf, respectively

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

Andalas Energy and Power PLC announced on 21 September 2018 that through its subsidiary, Resolute Oil and Gas (UK) Ltd, it has entered into an agreement with Corallian Energy Limited to acquire an 8% interest in licence P1918 which contains the Colter prospect and onshore licences PEDL 330 and 345. In return for its 8% interest, Andalas is funding 10.67% of the well costs up to a maximum of GBP 8 million. The deal is subject to regulatory approval. Corallian is planning to drill an appraisal well on the 98/11-2 (Colter) discovery in licence P1918. The discovery was made by BP in 1986 where 41.9° API was recovered on test from a 10.5 m oil column. Through the merging and reprocessing of 3D seismic Corallian has mapped 100 m of vertical relief up-dip of 98/11-2. The appraisal well is planned to spud in Q4 2018 and the well requires a Jack-up rig for operations. Well costs are in the region of GBP 7 million. Licence P1918 was initially awarded to Infrastrata from the 26th Seaward Licensing Round prior to Corallian taking the acreage. The company reprocessed 156 km of 2D seismic and 33.5 sq km of 3D seismic over the licence. It is thought that Colter could hold mean prospective resources of 22 MMbo (recoverable). Interest in P1918 following completion of two deals will be held by Corallian Energy Limited (34% + operator), Corfe Energy Limited (40%), United Oil and Gas Plc (10%), Andalas Energy and Power PLC (8%),  and Baron Oil Plc (8%).

Andalas subsidiary Resolute O&G has agreed with Corallian Energy to acquire an 8% interest in the latter’s coastal offshore P1918 (Colter prospect), along with PEDL 330 + 345, total 65 sq km off the Dorset coast. Andalas will fund 10.67% of the Colter well (scheduled 4Q ’18) up to GBP 8 MM and 8% beyond. P1918 is otherwise held by Corallian (op), partners Baron Oil, Corfe Egy + United O&G

Shell has acquired DNO’s 20% interest in PL 811 under a deal reported by the NPD on 9 December 2018. The transfer is effective from 30 November 2018. PL 811 covers an area of 352 sq km over parts of blocks 7/9, 7/12 and 8/7. DNO picked up the licence as part of its acquisition of Origo Exploration Holding AS on 29 June 2017 (announced on 4 May 2017). DNO’s acquisition of Origo in 2017 marked the company’s return to the NCS after a six year absence. DNO took Origo’s seven NCS licences (plus four in the UK), together with all licence commitments and obligations with effect from 31 March 2017, its management and staff and the office in Stavanger. The new company was named DNO Norge AS. Origo announced in February 2017 that it was looking for new investors or buyers for either its assets or the entire company after its major investors Riverstone and GNRI were investing elsewhere.   Interest in PL 811 is divided between Spirit Energy Norway AS (40%), A/S Norske Shell (20%), Aker BP ASA (20%), Faroe Petroleum Norge AS (20%).

Norway, PL 811

PL 248 C, 10km W. of Fram field, WD 363m, TD 3,882m, P&A with primary (Brent group, Cook fm) and secondary (Starfjord group) targets aquiferous, also found 15m of effective reservoir rocks in Heather fm sands, oil proven, but no oil/water contact encountered, minor discovery that is considered non-commercial for now. Deepsea Bergen SS. Equinor (op), partners Petoro + Wellesley.

035/11-22 S (Bergand) (Equinor 30% + Op, Wellesley Petrol. 30%, Petoro 40%) in PL 248 C block, near the Fram field - P&A, minor oil discovery. Brent Group with a thickness of about 190m, of which 90m of effective reservoir rocks with moderate reservoir quality. The thickness of the Cook Fm is about 70m, of which 50m of effective reservoir rocks with poor to moderate reservoir quality. Both primary targets are aquiferous. The secondary exploration target, in the Statfjord group, has a thickness of about 130m, of which 60m of aquiferous reservoir rocks with poor reservoir quality.

PRL 130, Cooper-Eromanga, 10-day well P&A on 4 Aug ’19, SLR rig 185.

Wirruna 1 nfw in PRL 130, P&A, with results awaited.

On 26 September 2018 the new TFT concession contract signed between Repsol, Total, Sonatrach and Alnaft was officially approved by the council of ministers. On 11 June 2018 Total reported that it signed a new concession contract with Sonatrach, Repsol and Alnaft on the Tin Fouye Tabankort (TFT) field, Illizi Basin, south-east of Algeria. The new contract will become effective upon the approval by the Algerian authorities and replace the existing one which is due to expire in 2019. It will allow to continue production at the field for another 25 years. Interests in the new concession are: Sonatrach 51%, Total 26.4% and Repsol 22.6%. The partners will carry out drilling and investments required to develop additional reserves estimated at more than 250 million barrels of oil equivalent including around 1 Tcf of dry gas. These investments of around 324 million USD will allow to maintain the production of the field which is currently over 80,000 b/d of oil equivalent for six years. It is planned to drill 11 new production wells. The new concession is a result of a framework agreement signed last year. In April 2017 Sonatrach and Total signed a framework agreement strengthening the existing partnership between the two companies. The agreement was signed by Sonatrach’s CEO Abdelmoumen Ould Kaddour and Total’s CEO Patrick Pouyanne. It established a new contractual framework for the Timimoun gas development, enabled continued joint operations on the TFT gas-condensate field, provided for the joint development of a new project and arranged a settlement of outstanding differences between the two companies. Background information The TFT field is a giant gas and oil field and is considered as one of the largest hydrodynamic trap in the world. The field was discovered in February 1961, with new-field wildcat Tin Fouye 1. The two main reservoirs are the Upper Ordovician Gara Louki Formation (oil & gas) at a depth of 1,400 - 1,500m and in the Lower Emsian F6 Sandstone Unit (oil) at 750m. The main Gara Louki reservoir has been subdivided into two superimposed geological units which are in vertical pressure communication. The upper unit has a coarser facies and extends over the whole of the reservoir with a constant thickness of between 10 and 20m from west to east. The lower unit is more laterally discontinuous with rapid lateral facies changes and displaying much poorer reservoir characteristics. Gross reservoir thickness of the Gara Louki Formation varies from 0 - 59m. Oil production started in 1961 from the F6 sandstone reservoir, but output went into a gradual decline. Water injection began in 1980 in the Ordovician reservoir. On 28 January 1995, Sonatrach, Total and Repsol announced that they had signed a 20 year production-sharing contract for the development of the gas, condensate and LPG reserves of the TFT field. Commercial gas production started in March 1999.

Algeria Repsol SA, TOTAL SA sign a new concession contract for the Tin Fouye Tabankort field

Phoenix Global subsidiary Petrolera El Trebol (PETSA) started in September 2018 a Vaca Muerta drilling program with the Mata Mora x-1001(h) horizontal deeper pool wildcat in the northwestern corner of the Mata Mora license, Neuquen Basin. The well tested at an average rate of 152 bo/d during 21 days in October. It was spud in late September and completed in mid October with 5,290m PTD/MD. The previous operator, YPF, spud the Mata Mora x-1 NFW in 2011 which discovered oil and gas also from Vaca Muerta and the Mata Mora Oeste x-1 appraisal which also tested oil and gas from the same formation. Phoenix Global Resources on 19 September 2018, signed a deal with Integra Oil & Gas (IOG) to pay a total of US$ 21.62 million by October 2018, for waiving its rights to participate in the 220 sq km Mata Mora, 117.9 sq km Corralera Sur and 105.5 sq km Corralera Noreste blocks. In April 2018 Phoenix obtained a 90% interest and operatorship on both contracts. Phoenix committed to spud two horizontal wells to the Vaca Muerta in the block. PETSA was also awarded four blocks with unconventional potential in the GyP "Neuquen Exploratory Plan" bid round. <P /><P />

Argentina, Mata Mora

Further to DEA 26 Jun '20, OMV has also been declared winner of a tender for offshore block III, 3,468 sq km on the Black Sea shelf. The April offer was re-scheduled to 22 June on account of COVID-19, and also featured adjacent block II, 5,282 sq km which OMV also won. Russian press map below.

(Black Sea) OMV has also been declared winner of a tender for offshore block III, 3,468 sq km on the Black Sea shelf.

Premier has signed to take 20% stakes in the Mubadala-operated Andaman I and South Andaman blocks in the little-explored N. Sumatra Basin, offshore Aceh. Of note, the UK player operates the nearby Andaman II block.

Premier confirmed it had signed an agreement with operator Mubadala to earn a 20% interest in South Andaman and Andaman I blocks PSC split PSC.

Effective 26 Nov '19 Wintershall Dea picked-up Gas-Union's 15% in P1239 (blocks 44/23f & 44/18d), P1733 (44/19f), P1902 (44/23c), P1903 (44/24c & 44/23d) + P2115 (44/23g), total 227 sq km. WD now runs the licences with a 64.5% interest, remaining partners Gazprom + XTO (Exxon).

Wintershall has acquired Gas-Union's 15% interest in the following licences - P1239, P1733, P1902, P1903 & P2115.

CaribX (UK) Limited announced on 28 January 2020 its plans for an exploration well during 2021-2022 in the Main Cape Block, located in the Mosquitia Basin. The last offshore well drilled in Honduras was the Castana 1 (TD 3,812m) drilled by Texaco and abandoned dry in 1980 in the Tela Basin (Caribbean Sea). Earlier, Union Oil's 1973 offshore wildcat Main Cape 1, located in the Mosquitia Basin, had oil shows in the interval 2,711 - 2,817m in Eocene Mosquitia Formation carbonates. The well was not appraised. The interest holders are the operator AziLat Petroleum Ltd with 45% and CaribX with the remaining 55%. CaribX increased its interest in the Main Cape Block, from 15% to 55% - subject to governmental approval. During 2019, 50% of the 33,950 sq km offshore block was relinquished. As of July 2017, AziLat acquired 80% interest in the Main Cape Block (former Patuca and Mosquitia) from Shell. The block was secured by BG Group in 2013, with the Production Sharing Contract (PSC) approved by the Honduras Congress in May.

CaribX (UK) has increased its interest in the Main Cape Block, from 15% to 55% (AziLat Petroleum Ltd ->45%).

Zaratex opened in August a dataroom for its Lhokseumawe PSC on/offshore N. Sumatra, the company seeking to dilute its 100% stake in the 1,206-sq km block since late last year.

Zaratex opened in August a dataroom for its Lhokseumawe PSC on/offshore N. Sumatra, the company seeking to dilute its 100% stake in the 1,206-sq km block since late last year.

Exxon signed up the PSCs for undrilled offshore blocks V, W and ND 10 on 12 Mar ’18, partner Petronas 50%. Commitments include acquisition and reprocessing of new 3D seismic + 1 well in each block within 3 years. Frontier blocks V (2,900 sq km) + W (4,600 sq km) straddle the Baram Delta + NW Sabah Trough ultradeepwaters. ND 10 lies in the NW Sabah Platform (Dangerous Ground) WD

Exxon signed up the PSCs for undrilled offshore blocks V, W and ND 10 on 12 Mar ’18, partner Petronas 50%. Commitments include acquisition and reprocessing of new 3D seismic + 1 well in each block within 3 years. Frontier blocks V (2,900 sq km) + W (4,600 sq km) straddle the Baram Delta + NW Sabah Trough ultradeepwaters. ND 10 lies in the NW Sabah Platform (Dangerous Ground) WD

On 20 February 2018, the award of the Somogybükkösd contract in southwestern Hungary, pre-awarded to Magyar Olaj- es Gazipari Rt (MOL) in November 2017, was signed off by the Minister for National Development and thus became official. The 1,088 sq km Somogybükkösd area is located in the Somogy and Zala political provinces, within the Pannonian Basin. Background Information On 13 June 2017, acting on behalf of the Hungarian State and in cooperation with the Hungarian Office for Mining and Geology, the Minister for National Development published an invitation to tender for a concession over the Somogybükkösd area. The tender closed on 25 September 2017. On 17 November 2017, following recommendation of the tender committee from the Hungarian Office for Mining and Geology, MOL was selected as the winner of the bid round for the prosection, exploration and production of hydrocarbons in the Somogybükkösd area. The company had two months (plus additional two months extension) to negotiate the final contract.

Hungary, not found

APLNG was awarded gas production licence PL 1084, 18 sq km of coal seam gas exploration tenure in the Bowen-Surat Basin, on 11 Mar '20 over former ATP 2046-P and previously PLR2018-1-2 in the 2018 QLD acreage release. It contains the 1983 Xyloleum gas discovery. APLNG (op), partner Armour Egy. Mar & release here.

APLNG (Australia Pacific LNG Pty Ltd) was awarded production licence PL 1084.

Aker BP has assigned 20% from its 60% operated stake in PL1005 to Shell, effective 30 June 2020. PL1005 covers 1,775 sq km of blocks 6404/9 & 12, 6405/4, 7 & 10 in the Norwegian Sea More Basin. It was awarded in APA 2018 on 1 March 2019 and has a drill decision due on 1 March 2021. The acreage contains the Ellida oil discovery well 6405/7-1 (2003, Statoil 4,300m), which found a 52m oil column in low quality Late Cretaceous Nise Formation reservoir, and a flow test indicated poor production properties from the well. Shell operates PL832, adjacent to the S of PL1005. Revised PL1005 partners are Aker BP ASA (40% + Op), VÃ¥r Energi AS (40%) and AS Norske Shell (20%).

Norway (More B.), PL 1005 operated by AKER BP. Aker BP has assigned 20% from its 60% operated stake in PL1005 to Shell. Revised PL1005 partners are Aker BP ASA (40% + Op), VÃ¥r Energi AS (40%) and AS Norske Shell (20%).

The drillship Valaris "Relentless" departed the location of well GC 166 SS1S0B0 (API 608114073700) at the Dothraki prospect for operator EnVen Energy Ventures on or about 13 April 2020. The operator did not disclose the results of the well. The drillship arrived on location in the northeast quadrant of the Green Canyon (GC) protraction area in the deepwater central Gulf of Mexico on 10 March 2020 to begin drilling the well. The Bureau of Ocean Energy Management (BOEM) on 19 February 2020 approved the drilling application submitted on 1 November 2019. This location corresponds to well "A" in the company's exploration plan N-10076, submitted on 8 July 2019 and approved by the BOEM on 23 October 2019. The well sits in water depth of 2,129 ft (649 m) some 88 mi (142 km) south of the onshore support base at Port Fourchon, Louisiana. The prospect targets an Upper Miocene-aged amplitude anomaly and lies about 7 mi (11 km) north of the Eni-operated Allegheny field, which has produced over 49 MMbo and 95 Bcfg through the end of January 2020. Plan N-10076 proposes drilling four wells using a dynamically positioned semisubmersible or a drillship in water depths ranging from 2129 – 2324 ft (649 – 708 m). The bottom hole locations for all four wells are in GC 166. It is expected to take 120 days to drill, complete and install a subsea tree for each well. The plan calls for drilling operations at the first well to begin on 1 December 2019. In a May 2019 presentation to investors, EnVen described Dothraki as a 750-acre (3 sq km) Upper Miocene-aged amplitude in a suprasalt mini-basin, analogous to the Fieldwood-operated Big Bend field in MC 698 (G28022) which has produced over 20 MMbo and 10 Bcfg through the end of September 2019. A multi-well development will be required in the success case, with a planned tie-back to the EnVen-operated Prince TLP 13 mi (21 km) to the north in EW 1003 (G13091). At Sale 235 in March 2015, a partnership of Ridgewood (47.5%), Red Willow (47.5%) and Houston Energy (5%) submitted a bid of USD 5.166 million for GC 166. There was one competing bid submitted by Fieldwood Energy of USD 710,100. EnVen farmed into the block in January 2019 and currently operates the lease with 33.5% working interest. The remaining interest is distributed between Ridgewood (33.5%), Red Willow (30%) and Houston Energy (3%). Background Information Exxon drilled four wells on the block between 1985 – 1989, targeting the Pliocene interval. None were producers. All four are located to the northwest of EnVen's planned wells.

EnVen Energy Ventures LLC Central Gulf – [Dothraki Prospect] – {GC 166 SS1S0B0} – Drilling concludes at Miocene prospect. The operator did not disclose the results of the well.

Eni has made an oil discovery in its South West Meleiha A 2X ST1 (SWM A 2X ST1) NFW, located on the South West Meleiha PSC in the Faghur Basin. The well encountered 18m of 32deg API oil in its primary target the Carboniferous Desouqy Formation, which tested at 2,300 bo/d and 0.4 MMcfg/d. SWM A 2X ST1 also encountered hydrocarbons in the Cretaceous Alam El Bueib 3D sandstones. The well was spudded on 21 December 2017 and drilled to a TD of 5,090m. Operations were carried out using the Egyptian Drilling Company #41 rig. SWM A 2X ST1 is a re-drill of the SWM 2X NFW, which was junked in early December 2017. SWM 2X was originally spudded on 18 November 2017 and had a PTD of 2,750m. The company's first well on the licence, Mandees Central 1X, was P&A dry in February 2017 (TD 4,829m). The discovery is the first made by Eni in the Palaeozoic in the Basin. The company was awarded the PSC for the block in January 2015, following the EGPC International 2013 Bid Round. Eni operates South West Meleiha with 100% equity.

Egypt, Meleiha (Dev)

Fire Creek has been awarded rights to a 725-sq km block in the Corozal Basin, according to an official Feb '20 map. The PSC lies in NW Belize adjacent to Princess Petroleum acreage, but further details n/a.

Belize, Princess Petroleum

In November 2019, the ANP nominated three blocks for inclusion in the ANP Production Sharing Round 7 for the pre-salt polygon planned for 2020. The offered blocks are Agata, Esmeralda and Agua Marinha and they have been assessed to have to have a cumulative estimated oil in place of 9.38 billion barrels, according to an ANP technical note. In comparison the five blocks from ANP Production Sharing Round 6, Bumerangue, Cruzeiro do Sul, Aram, Norte de Brava and Sudoeste de Sagitario had an average estimated oil in place of 42 billion barrels. The Agata Block is in the central-eastern part of the Santos Basin, in water depths over 2,000m. It is northeast of BP's Pau Brasil Block and southwest of Chevron's Saturno Block and east of the Petrobras Jupiter Field on BM-S-24. It is still in an ultra-deepwater frontier area of the pre-salt play lacking well control data. Drilling in newly acquired blocks near Agata will begin in 2020 and could provide well data to de-risk the commercial potential of the block. It has two mapped structures called Agata and Agata C and the chance of geological success from drilling the structures is estimated at 21% and 23%, respectively. The average oil in place estimated for the Agata structures was 3.19 Bbo. The Esmeralda Block is in the southwest Santos Basin with water depths from 2,000 to 2,500m. The block is about 50 km southwest of the Equinor's developing Carcara Field on Block BM-S-8 and south of the Aram Block recently claimed by Petrobras in Production Sharing Round 6. A successful pre-salt well was drilled on the block in 2009 by Petrobras but it was ultimately plugged and abandoned and later the block was relinquished. Other exploratory wells are more than 40km away, making it difficult to estimate the size of the pre-salt carbonate reservoirs. The Esmeralda Block has two prospects identified called Esmeralda and Tupa, which are projected to have a 24% and 16% chance of geological success, respectively. The oil in place estimate of the two structures is 5.51 Bbo. The aqua Marinha is in the central ??Campos Basin in a water depth of about 2,000m. It is east of the Petrobras Espadarte Field and south of the Caratinga and Marlim Sul fields and north of the C-M-539 Block which holds the Equinor developing prospects of Gavea, Seat and Pao de Acucar. Three possible pre-salt structures were identified with chances of geological success of 47%, 31% and 47% and a combined oil in place estimated to be 680 MMbo. The ANP has also nominated four blocks for ANP Production Sharing Round 8 planned for 2021. These blocks are the Tupinamba, Jade and Ametista blocks in the Santos Basin and the Turmalina Block in the Campos Basin.

In November 2019, the ANP nominated three blocks for inclusion in the ANP Production Sharing Round 7 for the pre-salt polygon planned for 2020. The offered blocks are Agata, Esmeralda and Agua Marinha and they have been assessed to have to have a cumulative estimated oil in place of 9.38 billion barrels, according to an ANP technical note. In comparison the five blocks from ANP Production Sharing Round 6, Bumerangue, Cruzeiro do Sul, Aram, Norte de Brava and Sudoeste de Sagitario had an average estimated oil in place of 42 billion barrels. The Agata Block is in the central-eastern part of the Santos Basin, in water depths over 2,000m.

PTTEP reported in late July 2018 that it is seeking potential partners in Block M-11, located between the Moattama Basin and the Andaman Sea Basin. The company intends to share the exploration risk in the block, which is located immediately south of the Zawtika Development and production area. Block M-11 is located primarily in deep water, with a maximum depth of approximately 2,000 m. PTTEP is preparing for an exploration drilling campaign that will include one or two wells in Block M-11, where no discoveries have been made to date. The campaign will also include up to twelve appraisal wells in Block M-09, with the goal of identifying further reserves upside for the Zawtika gas project. PTTEP has contracted the “Noble Clyde Boudreaux” S/S for the campaign, which is expected to commence in Q3 2018. The previous exploration activity in Block M-11 was a 3D seismic survey acquired in 2016 using the “Polarcus Asima” vessel. The planned area for the survey was approximately 1,500 sq km. PTTEP also drilled one well in the block, Manizawta 1, in 2013. The primary target, Miocene carbonates, was dry, however possible gas shows were encountered in the shallower Pliocene sandstone section. PTTEP holds 100% operating interest in Block M-11. The company also operates the Zawtika Development and Production Area (80% interest), partnering with MOGE (20%). Background Information Block M-11 was awarded to PTTEP (100%) in 2005. In 2012, Total and JX Nippon farmed into the block for 40% and 15% interests respectively. Following the drilling of wildcat Manizawta 1 in 2013, the partners withdrew from the block, leaving PTTEP as sole interest holder. PTTEP plugged and abandoned new-field wildcat Manizawta 1 on 4 November 2013. The well was drilled to TD at around 3,550 m. The well was spudded on 21 September 2013 by Vantage Drilling’s drillship “Tungsten Explorer”. The prospect is located in the deeper section of the block at around 1,000 m of water depth. Manizawta 1 is approximately 47 km west of wildcat M-11A/1 drilled by Esso Burma in 1976. The potential geological targets in this area are Oligocene-Miocene carbonate rocks, basin floor fan deposits and shallow marine to deltaic sandstone beds within the Middle and Upper Miocene intervals. PTTEP reported that the Zawtika Project commenced gas production for the domestic market on 14 March 2014, with initial sales rate of 40 MMscfg/d and planned peak of 100 MMcfg/d. Domestic gas is used for power generation. Gas export to Thailand commenced on 5 August 2014. Production gradually ramped up to the daily contract quantity of 240 MMscfg/d as stipulated in the Gas Sales Agreement with buyer PTT. Due to the highly faulted structures, numerous platforms and wells are required to develop the Zawtika and nearby fields. The initial phase of the Zawtika project (Phase 1A) consisted of three wellhead platforms (ZWP1, ZWP2 and ZWP3, located in the Shwepyihtay, Kakonna and Zawtika fields respectively) and one integrated central processing/living quarter’s platform (ZPQ). Further development phases will be necessary in order to maintain the stipulated production plateau.

PTTEP reported in late July 2018 that it is seeking potential partners in Block M-11, located between the Moattama Basin and the Andaman Sea Basin. The company intends to share the exploration risk in the block, which is located immediately south of the Zawtika Development and production area. Block M-11 is located primarily in deep water, with a maximum depth of approximately 2,000 m.

EP 469, onshore Perth Basin, so far 10.2m net reservoir in the Wagina sst, 5m more drilled since last report, total now 79m total gas column, reservoir pressure >6,800 psi. PTD 5,200m, main target Kingia High Cliff sst yet to be intersected. Strike (op), partner Warrego Egy.

West Erregulla-2 expl block EP 469, onshore Perth Basin, so far 10.2m net reservoir in the Wagina sst, 5m more drilled since last report, total now 79m total gas column, reservoir pressure >6,800 psi. PTD 5,200m, main target Kingia High Cliff sst yet to be intersected. Strike (op), partner Warrego Egy

On 13 August 2019, Total spudded the Richat 1 new field wildcat well in block C-9, deep waters of the MSGBC Basin, central offshore Mauritania. The well is located in the central part of the block in around 2,500 m of water. Operations were finished around 26 September 2019. No results were released. In mid-July 2019 it was reported that Total exercised its option to use the “Pacific Santa Ana” drillship to drill a well in block C-9. The company was to drill the Richat prospect. In early March 2019 industry sources suggested that Total will drill its well in block C-9, deep waters of the MSGBC Basin, central offshore Mauritania with the “Pacific Santa Ana” drillship. The well will be drilled around mid-2019 once the rig comes up from Senegal where it starts work for Total in April. It is not yet known which prospect Total will drill in block C-9. At this stage, the rig slot is an option and probably depends on Total finding a partner to share the drilling risk. In late March 2018 it appeared that Total was planning an exploration well in block C-9. The company was looking for a rig to start drilling in the fourth quarter of 2018. In addition to one firm well, there were to be options for two additional wells. Block C-9 was awarded to Total in 2012, it covers 10,250 sq km and is undrilled. The company completed two 3D seismic surveys over the acreage, one in 2013 and the other in 2017. Total targets Upper Cretaceous turbidite sand channels on the continental slope / basin floor which have been prolific for Kosmos further south with the Tortue, Teranga Marsouin and Yakaar discoveries in Mauritania and Senegal. Recent drilling closer to C-9 also by Kosmos was unsuccessful with the Hippocampe and Lamantin wells in the C-8 and C-12 blocks, respectively, coming up dry. The sands which Total targets in C-9 are related to the Nouakchott river system while the sands containing Tortue and Yakaar/Teranga are related to the Senegal river system. Since it took operatorship of the C-18 block in 2017, Total increased its footprint in the M.S.G.B.C. basin in general and in Mauritania in particular. The company operates now five deep water blocks in the country: C-7, C-9, C-15, C-18 and C-31. The C-18 acquisition joins C-9 and C-7 to constitute a large continuous acreage position totaling over 30,000 sq km. Participants in block C-9 are: Total, operator with 90% and SMHPM with 10%.

TOTAL SA finished Richat 1 well in in block C-9 deep waters of the MSGBC Basin, central offshore Mauritania. The well is located in the central part of the block in around 2,500 m of water. Operations were finished around 26 September 2019. No results were released.

Lukoil has signed with ADNOC for a 5% interest in the offshore Ghasha concession comprising the Hail, Ghasha + Dalma ultra-sour gas-cond devt projects as well as the Nasr, SARB and Mubarraz fields. ADNOC’s planning foresees a startup in the middle of the next decade, fields plateau’ing at min. 1.5 Bcuft/d + 120,000 boe/d oil + condensate (gross). ADNOC is now partnered here by Eni 25%, Wintershall Dea 10%, OMV 5%, Lukoil 5%.

Lukoil acquired a 5% WI in the offsh. sour gas Ghasha Concession (ADNOC ->55% op, ENI 25%, Wintershall 10%, OMV 5%).

As of 1 July 2019, Alliance Exploration is looking for a partner to drill a well on state lease ADL 392104 located in the Guitar Unit onshore North Slope of Alaska. The well will be targeting identified plays in the Kuparuk “C” and the Ivishak formations, the main pay in the Kuparuk River and Prudhoe Bay fields respectively. The Guitar Unit includes leases ADL 392104 issued on 12 December 2010, ADL 391544 and ADL 391545 both issued 1 July 2010. The company plans to drill a vertical hole to test the Ivishak Formation and then sidetrack for a lateral well to test an anomaly in the Kuparuk “C” Formation. Alliance does not plan to set up a data room but does have information available including 3D seismic covering the entire area.

Alliance Exploration is looking for a partner to drill a well on state lease ADL 392104 located in the Guitar Unit onshore North Slope of Alaska. The well will be targeting identified plays in the Kuparuk “C” and the Ivishak formations, the main pay in the Kuparuk River and Prudhoe Bay fields respectively.