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In August 2018, Gazprom was testing four appraisal wells in the Tambeyskoye Zapadnoye discovery in Yamalo-Nenets Autonomous Okrug (Western Siberia). Tambeyskaya Zapadnaya 43, 44, 45 and 124, aimed at refining of a geological model of reservoirs in the Middle Jurassic section, were drilled in 2016-2018. The company started testing of the wells in April-May 2018 and, by September, all wells tested gas and condensate from reservoirs Yu8, Yu7, Yu6 and Yu2. Based on results of its appraisal program which included 3D seismic acquisitions and drilling of wells, Gazprom submitted a new model for the Tambeyskoye Zapadnoye, Tambeyskoye Severnoye and Tasiyskoye discoveries that integrates the discoveries into the single Tambeyskoye field based on the common pool in the Middle Jurassic play. Gazprom estimates that 3P gas reserves of Tambeyskoye may reach 127 Tcf, almost doubling current combined 3P reserves of the discoveries.

In August 2018, Gazprom was testing four appraisal wells in the Tambeyskoye Zapadnoye discovery in Yamalo-Nenets Autonomous Okrug (Western Siberia). Tambeyskaya Zapadnaya 43, 44, 45 and 124, aimed at refining of a geological model of reservoirs in the Middle Jurassic section, were drilled in 2016-2018.

Liberia has formally launched the Liberia Offshore License Round. The round which was initially planned from April 10-October 1, 2020 will now open on April 10, 2020 and run up to February 28, 2021. Nine blocks will be on offer in the Harper Basin, one of the last unexplored and undrilled regions offshore West Africa: LB-25, LB-26, LB-27, LB-28, LB-29, LB-30, LB-31, LB-32, LB-33. Announcing the licensing round, President George M. Weah said that, because of the current corona virus situation, he has instructed the Liberia Petroleum Regulatory Authority (LPRA) that all initial engagement, promotional events, consultations, and business meetings relating to the Liberia Offshore License Round 2020 must be conducted online via the dedicated bid round website or other virtual platforms. There will be no physical meetings during the initial phases of the bid round until this deadly disease is defeated. The round is being launched in parallel with attractive amendments to Liberia's Petroleum Law, following major regulatory changes in October 2019, and the extension of the exploration period, in order to attract international investors. The Liberia License Round, 2020 will be conducted through three main stages: Pre-qualification, Bid Submission, and Bid Evaluation/Award. Beginning April 10, 2020 until 28 February 2021, companies interested in participating in the license round are required to complete and transmit a letter of expression of interest, fill out the pre-qualification form and ultimate beneficial ownership form as indicated in Annex 6 of the Tender Protocol for pre-qualification. Interested applicants can click on the 'Get the Full Story' link to download the Tender Protocol, Model PSC and Pre-qualification Form.  Nine blocks will be on offer in the Harper Basin, one of the last unexplored and undrilled regions offshore West Africa: LB-25, LB-26, LB-27, LB-28, LB-29, LB-30, LB-31, LB-32, LB-33. The new block demarcation is following the petroleum bill update in 2019, with a maximum block size of 3,500 sq kms, and aligning with the longitude and latitude grid. TGS holds a range of multi-client data across the tendered acreage to support the licensing round: 5,961 kms of 2D seismic, gravity and magnetic data 6,167 sq kms of 3D seismic, gravity and magnetic data Data availability: Discover the TGS data library Timetable of Events* *Please note: Due to travel restrictions related to the coronavirus (COVID-19) outbreak, roadshows will now take place via video link over the internet. Geological Insight into the Harper Basin The geological evolution of offshore Liberia is related to the opening of the Atlantic Ocean. The Harper Basin offers significant exploration potential, being the last real frontier basin of West Africa. Several sub-commercial discoveries have proven that the petroleum systems are working offshore Liberia. The Harper Basin has a petroleum system analogous to surrounding basins associated with the recent discoveries in Ghana, Cote d’Ivoire and also the conjugate Guyana. See an example of typical stacked channel systems below and explore the Story Map for more insight and information. Frequently Asked Questions (these will be added to and updated regularly) Q: With the COVID-19 pandemic restricting travel globally, are you still going to host the Bid Round?  A: Yes, we are maintaining the timeline we announced in January this year, though the launch events and London and Houston roadshows are being moved to virtual online only events. Q: Will there be blocks available in the Liberia Basin? A: The bid round is specifically for the Harper Basin, however there is a provision in the Law to allow direct negotiation for blocks in the Liberian Basin. Original article link Source: TGS

Liberia has formally launched the Liberia Offshore License Round. The round which was initially planned from April 10-October 1, 2020 will now open on April 10, 2020 and run up to February 28, 2021. Nine blocks will be on offer in the Harper Basin, one of the last unexplored and undrilled regions offshore West Africa:

ATP 752-P (Barta), Cooper-Eromanga, P&A’ing oil shows, Ensign rig 970. PTD was 2,650m. Santos (op), partners Bengal Egy + Bridgeport.

Chookola 1 (Santos 54,64% op., Bengal Egy. 30,36%, Bridgeport 15%) in ATP 752-P Barta block, P&A, after a review of well logs. Oil shows were encountered at multiple intervals but no pay identified.

Ardent Oil is looking to farm-out part of its interest in licence 11/16 (blocks 5604/27c, 5604/28a, 5604/31b and 5604/32) containing the Jarnsaxa prospect. Mean recoverable prospective resources are estimated at 130 MMbo. The licence was awarded in the 7th Danish Licensing Round in April 2016. The licence is for a six year term split into four phases. Phase 1 (2016-2018) requires data reprocessing and technical studies to be completed followed by a drill or drop decision. Phase 2 (2019) involves drilling one exploration well to evaluate the Pre-Cambrian basement with phase 3 (2020-2021) committing to drill a second exploration well or to relinquish the licence. Phase 4 (2022) will require the second exploration well to be drilled. The data used to define Jarnsaxa consists of the PGS Broadband Geostreamer (323 km sq), Danish Megasurvey (11,180 km sq) and legacy 2D data. Well studies included relevant source rock penetrations and offshore Palaeozoic penetrations from nearby wells. The Jarnsaxa structure is a thrust-fault bounded anticline deformed by later faulting episodes. Pre-Cambrian fractured basement form the reservoir objective. The basement was subject to multiple tectonic phases of contraction, strike-slip and extension. The basement would have likely been exposed subaerially and any leach zone at the basement unconformity would enhance fractured reservoir effectiveness. Late Jurassic Kimmeridge Clay equivalent source rocks in the Tail End Graben charge nearby producing fields and could source Jarnsaxa. The Stork-1 well penetrated the source rock ~5 km from the acreage and is thought to be stratigraphically placed against the fault systems bounding Jarnsaxa. Carboniferous strata from a deep Palaeozoic sediment filled basin to the south could also charge the prospect. Seals from overlying Palaeozoic sediment was penetrated by offset wells and is interpreted to be tight clastic and volcaniclastic sediment. Further seal potential in the typically tight Late Cretaceous pelagic chalk units over lie the Permian clastics. The depth to the crest of the structure is 2,575 m subsea. The main risks consist of fractured basement reservoir and seal effectiveness. Interest in 11/16 is held by Ardent Oil (Denmark) SA (80% + operator) and Danish North Sea Fund (20%). For further information please contact: Peter Browning-Stamp [email protected]

Ardent Oil is looking to farm-out part of its interest in licence 11/16 (blocks 5604/27c, 5604/28a, 5604/31b and 5604/32) containing the Jarnsaxa prospect.

Inpex Browse E&P Pty Ltd, a wholly owned subsidiary of Inpex Corp, was awarded exploration permit WA-533-P, located in the Canning and Roebuck basins, on 19 March 2018.  The permit has been awarded for a period of six years and will expire, or be eligible for renewal, on 18 March 2024. The permit was awarded to Inpex after being offered as block W16-6 in the 2016 Offshore Federal Acreage Re-release during 2017.  Work commitments have been assigned for the validity of the permit, with 5,005 km 2D and 1,035 sq km 3D seismic acquisition as well as geotechnical studies to be undertaken in years 1 – 3, between March 2018 and March 2021.  Further geotechnical studies are then outlined, including play evaluation and maturation of prospects, in years four and five.  In the final current permit year, between March 2023 and March 2024, one exploration well is planned at an estimated cost of AUD 25 million. WA-533-P, which covers an area of 12,439 sq km, was awarded on 19 March 2018.  Inpex Browse E&P Pty Ltd holds 100% interest and operatorship.

Australia, not found

PSCA 52/22, N. Songnan Sag in Qiongdongnan Basin, WD 150m, ops terminated 17 Jan ’18, no results, Kantan 3 SS. Target Miocene–Oligocene clastics.

ST 27-5-1d nfw PSCA 52/22, N. Songnan Sag in Qiongdongnan Basin, WD 150m, ops terminated, no results,

Medco Energi reported in early April 2020 that exploration well Bronang 2, in the South Natuna Block B PSC Extension, West Natuna Sea, was a gas discovery. Operations at the well were likely completed in late March 2020, with results initially unreported. Bronang 2, located in the Area I of the PSC, was likely spudded in mid-February 2020, using Japan Drilling's semi-submersible rig "Hakuryu-5". The well was likely targeting the Middle Miocene Arang Formation and Late Oligocene-Early Miocene Gabus Formation. With the drilling of Bronang 2, the "Hakuryu-5" has completed the drilling contract with Medco. A second exploration well previously planned in the campaign has been likely deferred by Medco in view of the impact of the coronavirus disease 2019 (COVID-19) and the declining global oil price. The first well in the structure, Bronang 1, was plugged and abandoned by Conoco in 1993 with oil and gas shows. Prior to Bronang 2, the last exploration well drilled in the PSC was wildcat Tuna 1 in mid-August 2019. The well was plugged and abandoned as a gas discovery, likely targeting Pliocene sandstones of the Muda Formation. According to sources, well testing indicated biogenic gas with a flow rate of 4 MMcfg/d. The operator will conduct further study by running a series of lab analysis. Tuna 1 is located in the unexplored Area VI of the PSC. The well was spudded around early July 2019 using the “COSLBoss” J/U. The operator reported a cost of approximately USD 11 million for the well. Medco may have also completed the Tuna 2 well in late 2019, to appraise the discovery of Tuna 1. Medco completed a 1,400 sq km 3D seismic survey in the eastern part of the PSC (Areas V, VI and VII) in late 2018. ConocoPhillips, previous operator of the block, drilled one well in 1973 (Sokang 1, small gas discovery), in area VII of the PSC. Medco’s previous exploration well, SW Bawal 1, was completed in early November 2018. The well was drilled using “COSLBoss” J/U and was reported to have flowed gas from the first DST, while the operator continued to stabilize gas flow. Additional tests were likely conducted, however further results have not been reported. SW Bawal 1 is located approximately 10 km southwest of the Bawal field (area I of contract block). The well was spudded in September 2018, possibly targeting the Upper Miocene-Lower Oligocene sandstones of the Gabus Formation. The South Natuna Sea Block ‘B’ PSC is operated by Medco with 75% interest, through two subsidiaries. The other 25% is held by Prime Natuna Energy. The PSC is due to expire in 2028. Background Information The South Natuna Sea Block 'B' PSC was awarded to Conoco on 16 October 1968. A Signature Bonus of USD 7 million was paid with a work programme commitment of USD 14 million in six years. The contract originally covered a huge strip of 103,287 sq km across the Indonesian sector of the South China Sea between latitudes 03° 00' N and 04° 40' N and encompassing large parts of both East and West Natuna basins and the dividing Natuna Arch. The area was subsequently reduced to 14,907 sq km at the time of a contract extension signed on 3 August 1990. Under the terms of the initial contract, Conoco drilled a total of 64 exploration and appraisal wells and some 35 development wells between October 1968 and August 1990. It also shot a total of almost 40,000 line km of reflection seismic, 246 km of refraction seismic and recorded 3,828km of gravity data. The exploration programme resulted in discoveries that were brought onstream as the Udang field (1981), the Kepiting field (1986) and the Ikan Pari field (1989), as well as several oil and/or gas discoveries deemed non-commercial at that time largely due to the lack of a gas market. All of these fields were relatively small, with Udang being the largest with recoverable reserves of 67 MMbo. The three fields were all off production by the mid-1990s. The largest discovery was made in December 1989 at Alu-Alu East 1. That well flowed at the aggregate rate of 12,289 bo/d, 187 bc/d plus 61.57 MMcf/d from Arang and Gabus Formation sandstones. The discovery was delineated in 1990 and quickly brought onstream in early 1993 as the Belida field. The field is believed to contain up to 370 MMbo plus 330 Bcfg recoverable (2P). The PSC was granted a 20-year extension on 3 August 1990 to allow production to continue from the contract area. The extension became effective on 16 October 1998 and lasts until 16 October 2018 and was granted on the basis of payment of a new Signature Bonus of USD 3 million and commitment to a new work programme of USD 30 million in nine years. Two further part relinquishments in 1992 and 1997 have reduced the PSC to 11,162 sq km. Between the award of the extension up to the end of 1997 Conoco drilled a further 16 exploratory and delineation wells, drilled 40 development wells and acquired 4,686km of 2D data and 2,097 sq km of 3D data, including the first 3D shot in the basin in a 207 sq km survey acquired in 1991. Following a Letter of Intent signed in April 1997, on 12 July 1998 a Gas Sales Agreement was initialed between Pertamina and SembCorp Gas Pte Ltd of Singapore. This called for the delivery, under the West Natuna Gas Project, of 325 MMscf/d for 22 years from three adjacent PSCs, Conoco's South Natuna Sea Block 'B' PSC, Gulf's Kakap PSC and Premier's Natuna Sea Block "A" PSC. SembCorp Gas is utilising the gas for power generation and petrochemical projects in Singapore. Delivery is via a 469km, 28" diameter trunkline from West Natuna to Singapore. The project was completed ahead of schedule and gas sales to Singapore commenced in January 2001, well before the planned start date of 15 July 2001. In order to accommodate the lifespan of the Conoco-led project, the three operating companies involved, Conoco, Gulf and Premier were granted extensions to their PSCs, these being announced simultaneous to the signing of the gas supply agreement on 15 January 1999. The Block 'B' PSC was extended to 2028 from its expiry date of 2018. Since the conception of the gas project, ConocoPhillips has focused on delineating many of the earlier "non-commercial" gas or gas/condensate discoveries and increasing its gas reserves in the area through new wildcat drilling. From the start of 1998 to mid-2000, Conoco drilled some 18 exploratory and delineation wells and shot 619km of 2D and 2,710 sq km of 3D data. Seven development wells at Belida were drilled in the corresponding period. During this period, significant new gas discoveries were made at Belut West 2, Kaci 1, Keong 1 and Siput 1, and the earlier Belanak (1975), Belut (1975), Belut North (1974), Buntal (1990), Hiu (1979), Kerisi (1991), Tawes (1988) and Tembang (1981) discoveries were successfully delineated. Field development for the gas project has been the main focus of operations since 2000. Gas produced from the block, through the West Natuna Transportation System, is sold to Singapore, following a 22-year sales contract started in 2001, and to Petronas' Duyong gas facilities, under a 20-year contract since 2002. The latest field onstream in the block was Belut South. Gas production from the field commenced on 26 April 2014 with initial production at around 40 MMcfg/d. Production is tied back to the Belut North field. Total production capacity is around 120 MMcfg/d. The field is also producing LPG to Pertamina. The field development plan was approved in mid-2011. Belut South has recoverable gas (2P) of around 190 Bcf.

Indonesia (Penyu Sub-basin (West Natuna B.)) Belida

Nashpa 3370-10 EL, Potwar Basin, P&A dry in mid-Jul ‘18, CCDC-27 rig. OGDC (op), partners PPL + Govt.

Khanjar 1 (OGDCL 65% op, PPL 30%, GHPL 5%) in Nashpa 3370-10 EL onsh. block, P&A after it failed to flow hc during testing.

In late-July 2020 Union Jack Oil acquired 3% interest in licence PEDL 253 from Montrose Industries. The licence, which is operated by Egdon Resources, covers 95 sq km over two blocks: TF/18a and TF/28a. Mapped within the licence is the Biscathorpe discovery and the South Elkington prospect. Three wells have been drilled in the licence, two of the wells drilled in 1987 and 1975 were dry. The Biscathorpe-2 well was drilled in early-2019 down to 2,133 m, targeting the Dinantian carbonates within the Biscathorpe four-way dip closure. Post-well analysis indicated that the well encountered a 35 m oil column of good quality oil within the Dinantian interval. A sidetrack from Biscathorpe-2 could be drilled in the future to test the Westphalian reservoir, which is interpreted to thicken to the north, and appraise underlying Dinantian carbonate. The licence is west of licence PEDL 339 that is also operated by Egdon Resources and it contains the producing Keddington field. Exploratory drilling is planned on licence PEDL 339 to target either the Keddington South prospect or the Louth prospect. Interest in the licence is held by Egdon Resources UK Ltd (35.8% + operator), Union Jack Oil plc (25%), Humber Oil & Gas Ltd (20%) and Montrose Industries Ltd (19.2%).

(Anglo-Dutch B.) Union Jack Oil acquires 3% in PEDL 253 license from Montrose Industries TF/28a op. by EGDON (36%)

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

Union Jack Oil and Humber O&G have agreed to acquire from Celtique a joint 16,25% in PEDL 201 (Widmerpool Gulf) and 12.5% in PEDL 181 (Humber Basin).

Wintershall spudded a well on the Marisko prospect in PL 847 on 4 December 2018 using the “Transocean Spitsbergen” S/S. 6706/6-2 S lies on the Naglfar Dome, approximately 65 km north of Aasta Hansteen and immediately north of the 2003 gas discovery made by 6706/6-1. 6706/6-2 S has an Upper Cretaceous Nise Formation target and a planned TD of 4,235 m (4,030 m TVD). In the event that a discovery is made and the well is tested, a 7” liner would be run to an extended TD of 4,580 m (4,330 m TVD). There is also potential for a sidetrack (6706/6-2 A) which would have a TD of 4,060 m (4,030 m TVD). Operations are expected to last between 61 (dry hole) and 93 (including a sidetrack and two tests) days. The well was drilled to TD at 3,916 m and on 12 February 2019 it was being abandoned. 6706/6-1 targeted the Nise Formation Hvitveis prospect and was drilled by Esso in PL 264. It reached a TD of 3,451 m in the Paleocene and proved gas in an unnamed Paleocene reservoir. The NPD puts estimated recoverable reserves at 265 Bcfg (December 2016). At that time it was considered non-commercial due to the lack of any infrastructure in the area. However, production from Aasta Hansteen will start up in the second half of 2018 with gas exported through the new Polarled pipeline to Nyhamna. Additional gas volumes proven by the Marisko well could therefore potentially be developed in the future using the Aasta Hansteen facilities. PL 847 is operated by Wintershall Norge AS (40%). Wintershall is partnered by OMV (Norge) AS (20%), Repsol Norge AS (20%), Dyas Norge AS (10%) and Equinor Energy AS (10%).

6706/06-02S (Marisko) (Wintershall 40% op, OMV 20%, Repsol 20%, Dyas 10%, Equinor 10%) in PL 847 block. P&A results n/a, targeted the Nise Fm.

Pertamina is reportedly proposing to operate the Rokan block in Central Sumatra, ready to take over from Chevron and continue to apply enhanced oil recovery. The 6,264-sq km block contract expires in Sep ’21 and is currently run by Chevron 100%:

Pertamina is reportedly proposing to operate the Rokan block in Central Sumatra, ready to take over from Chevron and continue to apply enhanced oil recovery. The 6,264-sq km block contract expires in Sep ’21 and is currently run by Chevron 100%:

Agua Botada block, Malargue - Agrio Fold Belt, Neuquén Basin, reportedly encountered 26-27 API oil, no further specifics for now. PTD was 2,300m, targets Chachao, Lotena + Huitrin fm’s. Roch (op), partner Emesa.

Agua Botada-1001 appr Agua Botada block, Malargue - Agrio Fold Belt, Neuquén Basin, reportedly encountered 26-27 API oil, no further specifics for now. PTD was 2,300m, targets Chachao, Lotena + Huitrin fm’s. Roch (op), partner Emesa.

SW corner of AE-0059-3M-Mezcalapa-09 block, onshore Sureste Basin, reportedly o&g encountered and well considered successful. PTMD was 5,970m (4,836m TVD), target Cretaceous.

(Sureste B.) Terra 101 exploration well operated by PEMEX (100%) in AE-0059-M-Mezcalapa-09 block, TD = 6000 m reported o&g encountered and well considered successful targetting the Cretaceous

Perenco has exercised its pre-emption right on a January Wytch Farm deal between Ithaca and Verus Petroleum (DEA 18 Jan ’18). The latter had agreed to buy Ithaca’s 7.5% in the Wytch Farm field for GBP 53 MM. Involved are PL 089, P 534 + PEDL 328 across Poole Harbour. Partnership will therefore become Perenco (op) 95% + Repsol Sinopec 5%, effective 1 Jul ’17.

United Kingdom, Wytch Farm

Lion Energy offered a farm-in opportunity in the newly awarded East Seram block, located in onshore/offshore Seram island, in late May 2018. The block has been officially awarded to Lion Energy (100% interest and operator) on 2 May 2018, as one of the four Direct Offer blocks offered in the Conventional Oil and Gas Bidding First Round 2018. Upon PSC signing, the block will follow the Gross Split fiscal terms. According to local media reports, official signing of the four blocks is expected in early June 2018. The official contract signing for the East Seram block will require payment of a Signature Bonus of USD 500,000. Firm commitments for the first three years of exploration consist of 500 km 2D seismic acquisition. The 6,500 sq km East Seram block is located in the Seram Basin, a structurally complex area with major structural highs related to the Seram Fold Belt. Historically, oil and gas seeps have also been identified. The basin is estimated to contain approximately 60 MMbo and 2 Tcf of gas. According to Lion Energy, the East Seram block contains several leads with potential carbonate reservoirs in the Jurassic Manusela Formation, analogue to the producing Oseil field and to the Lofin 1ST1 discovery in the adjacent Seram (Non-Bula) PSC. The Manusela reservoirs are estimated to bear significant gas volumes, at depths between 1,500 and 5,000 m. The Lofin discovery is estimated to contain approximately 2 Tcfg from a 1,300-m gas column. The block is also expected to provide shallow oil potential in the offshore extension of the mature Bula Fields play, within Pleistocene sands of the Fufa Formation. Lion Energy holds a 2.5% participating interest in the adjacent block, the Seram (Non-Bula) PSC, operated by CITIC Resources. For further information on this opportunity, interested parties may contact: Tom Soulsby Executive Chairman [email protected] Background Information The East Seram block was offered on 19 February 2018 under the Conventional Oil and Gas Bidding First Round 2018, under the Direct Offer mechanism. The block covers an area of 6,504 sq km, the majority of which onshore in the eastern Seram Island, with a small portion located offshore. The block is surrounding the Seram (Non-Bula) PSC operated by CITIC Resources. Wells located within the block boundary are Wahai 1 (new field wildcat, shelf), Wahai 2 (new field wildcat, onshore), Ceram B 1X (new field wildcat, water depth of 115 m) and Belis 1 (new field wildcat, onshore). Other onshore wells located near the eastern side of the shore area (within the Seram (Non-Bula) PSC) are, Metafoten 1, Salas 2, and Salas Barat 1. These three wells are situated in the Seram (Non-Bula) PSC. On 2 May 2018, Indonesian Ministry of Energy and Mineral Resources announced the winners for four blocks offered in the Conventional Oil and Gas Bidding First Round 2018 under the Direct Offer mechanism. The blocks and respective winners are the following: Citarum (consortium of PT Cogen Nusantara Energi and PT Green World Nusantara), East Ganal (Eni), East Seram (Lion Energy), South East Jambi (consortium of Talisman - a Repsol subsidiary - and MOECO). The official announcement was made during the Opening Ceremony of the 42nd Indonesian Petroleum Association (IPA) Exhibition and Conference in Jakarta. Only one Direct Offer block, East Papua, did not receive any bid.

Lion Energy offered a farm-in opportunity in the newly awarded East Seram block, located in onshore/offshore Seram island, in late May 2018. The block has been officially awarded to Lion Energy (100% interest and operator) on 2 May 2018, as one of the four Direct Offer blocks offered in the Conventional Oil and Gas Bidding First Round 2018.

OGDC assigned a 5% stake to GHPL in the otherwise wholly-owned Tirah 3370-14 EL, 1,946 sq km in the Pishin-Katawaz Basin, Khyber Pakhtunkhwa, retro-effective 21 Mar '14. 2D seismic is presently underway here, 286km planned. Likewise in the Orakzai 3369-1 EL, 4.66% to GHPL. The 1,708-sq km block lies in Potwar. 2D seismic is also underway here, 378km planned.

OGDC assigned a 5% stake to GHPL in the otherwise wholly-owned Tirah 3370-14 EL, 1,946 sq km in the Pishin-Katawaz Basin, Khyber Pakhtunkhwa, retro-effective 21 Mar '14. 2D seismic is presently underway here, 286km planned. Likewise in the Orakzai 3369-1 EL, 4.66% to GHPL. The 1,708-sq km block lies in Potwar. 2D seismic is also underway here, 378km planned.

On 1 July 2019 partner Kosmos announced that the GTA-1 appraisal well, GTA block, deep waters of the MSGBC Basin, found gas. The well intersected 30 m of net gas pay in high quality Albian reservoir. The well reached a total depth of 4,884 m and will be completed as a gas producer for the GTA floating LNG project which is currently under construction. The “Ensco DS-12” rig will now move to drill the Yakaar 2 appraisal well. Available information suggests that BP is batch drilling the three following wells: Orca 1 in clock C-8, Yakaar 2 in Cayar Profond block and GTA-1 in GTA block. The GTA-1 appraisal well was spudded around 14 May 2019 with the “Ensco DS-12” drillship coming from the Yakaar 2 well in Senegal where the top hole section was drilled. As of 14 June, the rig was still operating on the GTA-1 location. As of 4 April 2019, the “Ensco DS-12” had entered Mauritanian waters in preparation for BP’s drilling campaign in Senegal and Mauritania. In late October 2018 industry sources announced that BP contracted the “Ensco DS-12” for two firm wells plus four one well option starting in April 2019 offshore Senegal. This rig has carried out the BP/Kosmos drilling campaign of 2017 when Yakaar was discovered. According to industry sources, the 2019 drilling campaign will include an exploration well in Mauritania (Orca) an appraisal well in Senegal (Yakaar) and an appraisal well in the cross-border GTA block. The latter, GTA-1, will target the eastern part of the Tortue / Ahmeyim field in the GTA block, deep waters of the MSGBC Basin. In April 2015, Kosmos announced that the Tortue 1 new field wildcat well discovered gas. Based on intermediate logging to a depth of 4,630 m, the well has intersected 107 m of net hydrocarbon pay. In the primary Lower Cenomanian objective, a single gas pool, was encountered in three multi-Darcy permeability reservoirs totaling 88 m of net pay within a 160 m gross hydrocarbon bearing interval. In the secondary Upper Cenomanian objective, a 19 m net gas pay interval was intersected within a 150 m gross hydrocarbon bearing interval. In its early May 2015 first quarter operations report, Kosmos gave further details about the Tortue West structure recently drilled with the Tortue 1 well. The porosity of the drilled reservoir portion ranges between 20 and 30% confirming good reservoir properties. The reservoir fluid is considered to be a fairly dry gas with a low condensate to gas ratio. Kosmos later reported that Tortue 1 found additional hydrocarbons in the deeper Albian secondary objective. The well intersected 10 m of net hydrocarbon pay in the Lower Albian section, which is currently interpreted to be gas. Kosmos chief exploration officer, Brian Maxted, commented: “This suggests we have a working hydrocarbon system in both the Albian and Cenomanian sequences. While the Albian was not the primary objective of the Tortue 1 well, the presence of additional hydrocarbons in the Albian further de-risks other prospects in the Greater Tortue Complex which include primary reservoir targets in both the Albian and underlying Aptian.” Participants in the unitized GTA block are BP, Kosmos, Petrosen and SMHPM. The split is believed to be BP (operator) 46%, Kosmos 14%, Kosmos Energy Investments Senegal 30%, SMHPM 5% and Petrosen 5%.

Senegal, not found

Senex Energy Ltd, through wholly owned subsidiary Victoria Oil Exploration (1977) Pty Ltd, spudded exploration well Voodoo 1 in PRL 146, located in the Cooper-Eromanga Basin, on 25 November 2018.  On 3 December 2018 the well was suspended, after reaching a total depth of 2,252 m, with evaluation continuing in early December 2018. The well was one of several in Senex’s ongoing exploration programme across its Cooper-Eromanga licences. PRL 146, which covers an area of 98 sq km, was awarded on 27 October 2014.  Participants in the permit are Victoria Oil Exploration (1977) Pty Ltd (40% + Operator) Permian Oil Pty Ltd, another Senex subsidiary, (20%), and Beach Energy subsidiaries Impress (Cooper Basin) Pty Ltd (25%) and Springfield Oil and Gas Pty Ltd (15%).

Australia, PRL 146

Sound has received the preliminary results of the resources certification in relation to the TE-5 Horst core volumes on a 250-sq km area of the Tendrara area (23,500 sq km) by RPS Energy Consultants. A mid-case GOIP is 0.65 Tcf, mid-case recoverable 377 Bcf is reported, which will be used for devt planning and funding solutions. Full report here.

Sound has received the preliminary results of the resources certification in relation to the TE-5 Horst core volumes on a 250-sq km zone of the Tendrara area (23,500 sq km) by RPS Energy Consultants. A mid-case GOIP is 0.65 Tcf, mid-case recoverable 377 Bcf is reported, which will be used for devt planning and funding solutions.

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

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

Terra Nova and Holloman are looking to reduce their combined 100% in PEL 112 + 444, total 2,150 sq km in the Cooper-Eromanga. Upwards of 80% is available, and a full sale would imply an Australian exit for both. Currently Terra Nova (op) 51.5%, Holloman 48.5%. Terra Nova contact Istvan Gyorfi, [email protected].

Terra Nova and Holloman are looking to reduce their combined 100% in PEL 112 + 444, total 2,150 sq km in the Cooper-Eromanga. Upwards of 80% is available, and a full sale would imply an Australian exit for both. Currently Terra Nova (op) 51.5%, Holloman 48.5%.

Rusanovskiy licence, Kara Sea, W. Siberian Basin, 13.38 Tcfg 3P reserves derived from Rusanovskaya-6 drilled + tested in 2018, Nanhai 7 SS rig released from location Oct ’18.

Im.V.A.Dinkova (Gazprom 100%) in Rusanovskiy licence, Kara Sea, 13,38 Tcfg 3P reserves derived from Rusanovskaya 6 drilled + tested in 2018.

Citic has agreed to sell a 10% interest in the Seram (Non-Bula) PSC Extension, 1,288 sq km onshore Seram Island, to a yet-unnamed 3rd party for USD 3.8 MM cash. The deal is subject to usual approvals. Partnership to be Citic (op), Kufpec, Gulf Petroleum Investment, Lion Energy + new partner.

Citic has agreed to sell a 10% interest in the Seram (Non-Bula) PSC Extension, to a yet-unnamed 3rd party for US$3,8 MM. Kufpec, Gulf Petroleum Investment, Lion Energy + new partner.

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

Neptune Energy Bonaparte Pty Ltd reduced its interest in the NT/RL1 retention lease, which contains the Petrel discovery, on 2 October 2019. As a result of Neptune Energy divesting some of its share, joint venture participants Santos Ltd, Bonaparte Gas & Oil and Lattice Energy have increased their shares. Santos has also acquired operatorship from Neptune Energy. Neptune Energy has reduced its holding from 60% to 22.41%, and relinquished operatorship to Santos. Santos has made the biggest increase, now holding 54%, up from 19.49%. Bonaparte Gas & Oil and Lattice Energy have increased their holdings to 17.84% and 5.75% respectively. The licence contains the east part of the Petrel discovery, which was made in August 1969. It was reported in 1H 2019 that the joint venture was continuing to evaluate development options for the Petrel gas field, with it being considered as part of a wider development project that may involve the Frigate Deep and Tern discoveries. Neptune entered NT/RL1 in February 2018 by acquiring ENGIE E&P International SA. The deal saw Neptune enter Australia by acquiring 60% interest and operatorship of WA-27-R & WA-40-R (Frigate Deep/Tern fields) and NT/RL1 & WA-06-R (Petrel field). However, on 11 April 2019 Neptune Energy withdrew from WA-27-R and WA-40-R, leaving Santos as sole holder and operator. It has now also reduced its holding in NT/RL1. NT/RL1, which covers an area of 623 sq km, was awarded on 16 May 1994. On 2 October 2019 it underwent an interest change, with participant holding becoming: Santos Ltd (54% + Operator), Neptune Energy Bonaparte Pty Ltd (22.41%), Bonaparte Gas & Oil Pty Ltd (17.84% and Lattice Energy Resources (Bonaparte) Pty Ltd (.75%).

Santos G&O (->54% op) and Lattice Energy (-> acquired 17,84% and 5,75% WI respectively in the NT/RL1 retention lease, which contains the Petrel discovery, from Neptune Energy (->22,41%)

Delek has signed with S.O.A. Energy to acquire a 25% stake in he Ofek New (405) + Yahel New (406) licences, total 742 sq km onshore in the Judea Basin. Resulting partnership will be S.O.A. Energy (new op) 45%, Delek Drilling 25%, Globe Expl (former op) 20% + Capital Point 10%. Explo drilling is planned in Ofek in mid-2019.

Delek has signed with S.O.A. Energy to acquire a 25% stake in he Ofek New (405) + Yahel New (406) licences, total 742 sq km onshore in the Judea Basin. Resulting partnership will be S.O.A. Energy (new op) 45%, Delek Drilling 25%, Globe Expl (former op) 20% + Capital Point 10%. Explo drilling is planned in Ofek in mid-2019.

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

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

On 8 June 2019, it was announced that Turkiye Petrolleri A.O. (TPAO) has been awarded the G17-C2 onshore exploration licence in the Zagros Province towards southeast of the country on 28 May 2019. The licence covers around 147 sq km area and it has been granted for a five-year term with an expiry date of 27 May 2024. TPAO is 100% owner and operator of the licence. TPAO had filed the application for G18-B4 exploration licence on 4 February 2019.

TPAO) has been awarded the G17-C2 onshore exploration licence in the Zagros Province towards southeast of the country

Khipro 2568-6 EL, Lower Indus onshore, compl. gas at TD 3,875m mid-Jan ’18, 7, Hilong rig 9. Target Lower Goru. UE (op), partners Bow Energy + Govt Holdings.

Pakistan (Indus B.) Bago 2 op. by UNITED EN (65.0%, UNITED EN 30.0%, GHPL 5.0%) in Khipro 2568-6 EL block, compl. gas at TD 3,875m

Macallum Group Ltd completed the acquisition of additional interest in exploration permit EP 494, located in the Perth Basin, on 15 June 2018.  Macallum has acquired 50% interest from previous joint venture partner Southern Sky Energy Pty Ltd. EP 494 was awarded solely to Southern Sky Energy on 8 May 2015.  Macallum acquired 50% interest and operatorship in October 2015.  The permit is scheduled to expire, or be renewed, in May 2022. Under the remaining work commitments, 20 km new 2D seismic is required by May 2019, followed by an exploration well scheduled between May 2019 and May 2020.  No wells have been drilled within the permit term to date. EP 494, which covers an area of 2,591 sq km, was awarded on 8 May 2015.  With Southern Sky’s withdrawal complete, Macallum Group Ltd now holds 100% interest and operatorship.

Macallum Group Ltd completed the acquisition of additional interest in exploration permit EP 494, located in the Perth Basin, on 15 June 2018. Macallum has acquired 50% interest from previous joint venture partner Southern Sky Energy Pty Ltd. EP 494 was awarded solely to Southern Sky Energy on 8 May 2015.

On 22 March 2018, the Federal Agency for Subsoil Use held an auction for the Payutskiy block in Krasnoyarsk Kray (Eastern Siberia). Novatek won the contest with the offer of RUB 66 million (USD 1.2 million). The winner of the auction will obtain a 27-year E&P license including a 7-year exploratory stage The Payutskiy block covers 2,323 sq km in the Yenisey-Khatanga Basin and encompasses the Nanadyanskoye discovery with 3P reserves estimated at 207 Bcf of gas. One stratigraphic test (Nanadyanskaya 310) has been drilled in the block. Gas resources (categories D0+D1+D2) of the block are estimated at 1,647 Bcf. The starting price amounted to RUB 60 million (USD 1 million).  

Russia, not found

11 November 2019, Ozlitineftgaz (a Uzbekneftegaz research institute) and Schlumberger Oilfield Eastern Limited have signed a Confidentiality Agreement and a Memorandum of Understanding (MoU). The documents aim at technological cooperation in the field of exploration, development and production optimisation at new and existing fields in Uzbekistan, as well as the co-ordination of projects in line with applicable law. Under the MoU, the parties may, by mutual consent, engage production capacities and process resources, labour and financial resources, own developments, technology and know-how for bilateral projects. In addition, following the talks, the parties agreed on the development of scientific and technological cooperation in the areas of field geology and geophysics, field development, processing and transportation of oil, gas condensate and gas, underground gas storage, technological services for oil and gas companies in Uzbekistan.

Uzbekistan, not found

In early September 2018, the Minister of Mines, Industry and Energy of Equatorial Guinea, H.E. Gabriel Mbaga Obiang, reported that his country was planning to launch a new oil and gas exploration bidding round in January 2019. The oil Minister added that he may refuse extensions of existing permits to oil operators unless they collectively invest a minimum of USD 2 Billion in the country. This strong message is in line with the announcement made in late 2016, when the government warned companies to be active with drilling or to hand back their permits. Obiang’s reaction is certainly linked to stagnant mega-projects like Ophir’s Fortuna FLNG, still a risk since Schlumberger decided to end its participation into OneLNG, due to delayed financing solution. Other oil players in the country include US-giant ExxonMobil, producing almost half of the country’s oil output from its Zafiro field, Kosmos who not only took over Hess’ producing oil assets Ceiba and Okume but also the surrounding exploration blocks. Marathon still dominates the gas production in the country, from its Alba Complex, representing almost 90% of the total country gas output. Noble recently signed Heads of Agreement regarding Alen gas monetization. And Atlas, which is looking for farm-in partners since years, prior exploration drilling in its permits that expired in April 2018. The latest licensing round in Equatorial Guinea ended in early April 2017, when seven companies won six exploration blocks offered during the EG Ronda 2016 Licensing Round. Out of 23 companies expressing interest in the licensing round, 12 submitted official bids. Of those, seven companies proceed to negotiations and ultimately signed Production Sharing Contracts (PSC) around late year 2017.

In early September 2018, the Minister of Mines, Industry and Energy of Equatorial Guinea, H.E. Gabriel Mbaga Obiang, reported that his country was planning to launch a new oil and gas exploration bidding round in January 2019.

Olympus Energy, a subsidiary of the Shahzad International Group, may be seeking partners in its Doukkala Abda reconnaissance licence. The 4,673 sq km licence was awarded to Olympus on 31 May 2016, with the acreage being one of six promoted by ONHYM during early 2016. It is located onshore in the Doukkala Basin and lies to the east of Chevron's offshore Cap Cantin Deep Offshore and Cap Walidia Deep Offshore exploration permits. The Permo-Triassic rift basin contains the prolific Triassic TAGI sandstone play, as well as additional plays in the Palaeozoic. Nine wells have been drilled on the block, with seven encountering hydrocarbons shows. The last was drilled by ONAREP (Dar Oulad Talah 1, 4,444m, P&A dry) in 1987. The last company to hold the acreage was Eni, with a reconnaissance licence, between November 2006 and October 2009. The company acquired a 484km 2D seismic survey. Shahzad operates Doukkala Abda with 75% equity, in partnership with ONHYM (25%, carried). The Pakistani company also holds the HaHa onshore exploration permit via Petroleum Exploration (Pvt) Ltd, located in the Essaouira Basin to the south.

Morocco, Doukkala Abda

Hilcorp secured on 1 Oct ’17  14 tracts issued in June during the Cook Inlet Lease Sale 244. Hillcorp was the sole bidder in the sale, so easily secured the acreage which totals 310 sq km off Alaska’s south-central coast. Block details from GEPS.

United States, not found

Sino Gas & Energy announced on 31 May 2018 it has entered into a Scheme Implementation Agreement with a wholly owned subsidiary of Lone Star Fund X Acquisitions under which Lone Star proposes to acquire 100% of the issued share capital of Sino Gas by way of a scheme of arrangement. Private equity firm Lone Star will acquire 100% of Sino Gas’ issued share capital in an all cash transaction via a scheme of arrangement, Sino Gas shareholders will receive cash consideration of A$0.25 per Sino Gas share, subject to all applicable conditions being satisfied or waived and the Scheme being implemented. About Lone Star Lone Star is a private equity firm, headquartered in the USA, that invests globally in a range of different assets classes, including the oil and gas industry. Since inception in 1995, Lone Star has organised seventeen private equity funds with aggregate capital commitments totalling over US$70 billion. Funding for this acquisition is being provided by affiliates of Loan Star Fund X (U.S.), L.P. and Loan Star Fund X (Bermuda) L.P., which closed in November 2016 with a US$5.5 billion capital commitment. The Scheme is not subject to any funding condition. About Sino Gas & Energy Holdings Limited Sino Gas & Energy Holdings Limited (“Sino Gas” ASX: SEH) is an Australian energy company focused on developing natural gas assets in China. Sino Gas holds a 49% interest in Sino Gas & Energy Limited (“SGE”), the operator of the Linxing and Sanjiaobei Production Sharing Contracts (PSCs) in the Ordos Basin, China's largest gas producing basin. SGE has been established in Beijing since 2005 and is jointly owned with China New Energy Mining Limited (“CNEML”) via a strategic partnership. SGE’s interest in the Linxing PSC with CUCBM (a CNOOC wholly-owned subsidiary) is 70% and 49% for the Sanjiaobei PSC held with PCCBM (a Petrochina wholly-owned subsidiary). SGE has a 100% working interest during the exploration phase of the PSC, and SGE’s PSC partners are entitled to participate upon Overall Development Plan (ODP) approval up to their PSC working interest by contributing their future share of costs. Sino Gas also holds an option to acquire a 5.25% participating interest from SGE (assuming full SOE partner participation) in the Linxing PSC at ODP by contributing 7.5% of historical back costs to SGE. Upon exercise of the option, Sino Gas will hold the largest net working interest in the Linxing PSC. The PSCs cover an area of approximately 3,000km2 in the Ordos basin in Shanxi, a rapidly developing province. The region has mature field developments with an established pipeline infrastructure to major markets. Natural gas is a key component of clean energy supply in China, with the 13th Five-Year Plan identifying the Ordos basin as a strategic natural gas source.

Sino Gas & Energy announced on 31 May 2018 it has entered into a Scheme Implementation Agreement with a wholly owned subsidiary of Lone Star Fund X Acquisitions under which Lone Star proposes to acquire 100% of the issued share capital of Sino Gas by way of a scheme of arrangement.

Sval Energi has farmed-in to PL 889 by taking a 10% interest in the licence from operator Neptune. Sval will cover 20% of Neptune's costs for the imminent Grind exploration well. In the event of a dry hole this will be capped at NOK 45 million but could increase to NOK 85 million if a discovery is made and the well is sidetracked. Neptune reported in early March 2020 that the deal had been completed on 28 February 2020. Grind exploration well 6507/8-10 S is located approximately 10 km east of Heidrun and 15 km east of Canela and has Jurassic Garn, Ile and Tilje Formation objectives. Planned TD is 2,479 m (2,439 m TVD) and planned duration is up to 67 days (if the sidetrack, which would have a TD of 2,533 m, is drilled). Neptune is expecting to encounter oil similar to that found at Heidrun and the key risk is migration. Interest in PL 889 is now divided between Neptune Energy Norge AS (50% + operator), Equinor Energy AS (20%), Wellesley Petroleum AS (20%) and Sval Energi AS (10%).

Norway (Donna and Halten Terraces (Voring B.)) Heidrun

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

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

Total has sold its entire operated share of Martin Linge Field and Garantiana discovery to Statoil for US$ 1.45 billion, with completion confirmed on 19 March 2018. Under the deal announced on 27 November 2017, Statoil acquired 51% WI and operatorship in Martin Linge PLs 040, 043 & 043 BS, and 40% operated share in PL554, B & C which contains the Garantiana discovery in part blocks 34/5, 6 & 9 (258 sq km). Statoil's equity in the Martin Linge Unit licences has increased from 19% to 70%, and it will become a new participant in PL554, with the transaction to be back-dated to 1 January 2017. Martin Linge field lies at the junction of blocks 29/6, 29/9, 30/4 & 30/7, adjacent to the UK/Norway border in the North Viking Graben. It was discovered by 30/7-6 R (1978, Norsk Hydro, 4,115m) and contains three gas and condensate reservoirs in Brent Group sandstone, and oil in the Eocene Frigg Formation (Fm). Martin Linge has estimated recoverable reserves of 69 MMbo and 910 Tcfg, and is expected to commence production in H1 2019, delayed from its original late 2016 planned start-up, due to a number of issues identified by the Petroleum Safety Authority, and a fatal event at Sumsung's Geoje shipyard in S Korea where the platform topside is being constructed. Its original budget of NOK 28.2 billion (US$ 4.68 billion) is estimated to have been overrun by NOK 10.4 billion (US$ 1.2 billion). The field is being developed with a manned wellhead platform, with the jacket substructure already in place, and the topside awaited from South Korea. Garantiana oil discovery was made on the Tampen Spur by 34/6-2 S (2012, Total, 4,335m), and has estimated recoverable resources of 38-88 MMbo in Early Jurassic Cook Fm. Development concepts for Garantiana are under evaluation. Also on PL554 (2km SW of Garanitana) is the Akkar discovery 34/6-3A (2014, Total, 4,019m), which has 3 MMboe estimated recoverable resources within the Cook Fm. Total farmed into Garantiana PL554 licence in 2011, and the licence group was awarded the accompanying licences PL554B & C which are valid until 2018. Total was reported to be seeking offers for its Martin Linge asset in September 2016. Martin Linge licence partners, via PL040, PL043 & PL043 BS, are Statoil Petroleum AS (70%+ Op) and Petoro AS (30%), whilst PL554, B & C partners are Statoil Petroleum AS (40% + Op), Point Resources AS (30%) and Aker BP ASA (30%).

Total has sold its entire operated share of Martin Linge Field and Garantiana discovery to Statoil for US$ 1.45 billion,Under the deal announced on 27 November 2017, Statoil acquired 51% WI and operatorship in Martin Linge PLs 040, 043 & 043 BS, and 40% operated share in PL554, B & C which contains the Garantiana discovery in part blocks 34/5, 6 & 9 (258 sq km).

Conrad is looking to offload part of its stake in the North X-Ray PSC, since a 1st effort was made in 2014. The block covers 4,014 sq km offshore West Java, commitments fulfilled. Contact: Miltos Xynogalas, [email protected].

Conrad is looking to offload part of its stake in the North X-Ray PSC, since a 1st effort was made in 2014. The block covers 4,014 sq km offshore West Java, commitments fulfilled. Contact: Miltos Xynogalas, [email protected].

PNOC-EC has reportedly taken on a 4.5% interest from UC Malampaya Philippines (UCMP) in Shell-operated SC 38, NW Palawan Basin, for USD 56.5 MM. Partnership now Shell (op) 45%, UCMP 40.5%, PNOC 14.5%. SC 38 contains the producing Malampaya ga-cond field.

PNOC-EC has reportedly taken on a 4.5% interest from UC Malampaya Philippines (UCMP) in Shell-operated SC 38, NW Palawan Basin, for USD 56.5 MM. Partnership now Shell (op) 45%, UCMP 40.5%, PNOC 14.5%. SC 38 contains the producing Malampaya ga-cond field.

On 4 March 2020 the NPD confirmed that Equinor has transferred a 30% interest plus operatorship in PL 828 to Neptune (effective from 31 March 2020). The licence covers most of block 36/4 which lies to the northeast of Neptune's Duva development. A drilling decision for PL 828 is required by May 2020 and it is understood that the Havhest prospect lies within the licence. Duva is currently under development and is expected onstream in late 2020 / early 2021. The field was discovered in 2016 by 36/7-4 which proved a 50 m gas column plus a 60 m oil column in the Lower Cretaceous Agat Formation and tested gas at a rate of 46 MMcf/d through a 76/64” choke. Duva is being developed using a 4-slot template with two horizontal oil producers and a gas producer tied-back to Gjoa. A further oil producer may be added in the future. Estimated recoverable volumes are 88 MMboe (23 MMbbl of oil and condensate, 12 MMbbl of NGL and 296 Bcfg). Following completion of the deal, interest in PL 828 is divided between Neptune Energy Norge AS (40% + operator), Sval Energi through Capricorn Norge AS (40%) and Equinor Energy AS (20%).

Norway (Maloy Slope (Viking Graben Province)) Gjoa

Pursuant to a HoA in Jan ’19, BP and Eni have now signed a 50:50 PSA for block 77, 2,734 sq km in the area of BP’s Khazzan field, central Oman.

Eni SpA and BP plc announced that they had signed an exploration and production sharing agreement (EPSA) with the Ministry of Oil and Gas for Block 77.

As of 10 January 2018 Hilcorp Alaska has been officially awarded six tracts from the Cook Inlet Areawide Oil & Gas Lease Sale (CIA 2017W) held on 21 June 2017 within the Cook Inlet Basin. Hilcorp placed bids totaling UDS 836,501.81 (adjust for total acreage available on a tract by tract basis) on a total of 24,138.12 acres (97.68 sq km) contained in the six blocks. The effective date of the awards is 1 Janaury 2018. The tracts were preliminarily awarded on 21 June 2017 the date of the lease sale. The sale area covered approximately 4 million acres (16,187 sq km) lying between the cities of Houston and Homer in the north and south, respectively, the Chugach and Kenai Mountains in the east, and the Aleutian Range in the west. The sale area was located entirely within the Kenai Peninsula Borough, the Matanuska-Susitna Borough and the Municipality of Anchorage. The area included approximately 815 tracts which range in size from 100 acres (0.4 sq km) to 5,760 acres (23.3 sq km) less those currently under lease. The lease sale was held at 09:00 am local time at Suite 108 of the Atwood Building, 500 W. 7th Avenue, Anchorage, Alaska. The attached table lists the details on the official awards for the CIA 2017W lease sale. Hilcorp Alaska LLC offical awards           Operator ADL Block Name Acreage Sq Km Total Bonus Bid Award Date Lease Sale Hilcorp Alaska LLC ADL 393566 CI-103 5,760.00 23.31 $202,464.00 1/1/2018 Sale CI2017W Hilcorp Alaska LLC ADL 393567 CI-106 5,760.00 23.31 $184,896.00 1/1/2018 Sale CI2017W Hilcorp Alaska LLC ADL 396568 CI-143 5,681.75 22.99 $199,713.51 1/1/2018 Sale CI2017W Hilcorp Alaska LLC ADL 393569 CI-545 1,280.00 5.18 $40,960.00 1/1/2018 Sale CI2017W Hilcorp Alaska LLC ADL 393570 CI-546 1,154.00 4.67 $36,928.00 1/1/2018 Sale CI2017W Hilcorp Alaska LLC ADL 393571 CI-754 4,502.37 18.22 $171,540.30 1/1/2018 Sale CI2017W Totals     24,138.12 97.68 $836,501.81     Source: IHS Markit             © 2018 IHS Markit   The bidding method for all tracts was a cash bonus bid with a minimum bid of USD 25.00 per acre. Royalty rate is fixed at 12.5%. A primary lease term of 10 years is in effect for all tracts (prior years had certain specified tracts which were allowed an Exploration Incentive Credit, at 10 years, with the remaining tracts at 7 years). Annual rental is typically USD 10.00 per acre for the first 7 years and USD 250.00 per acre for the remaining years.  

United States (Cook Inlet Tertiary Province) (It's a petroleum rights. Please summarize by yourself). In IHS database: CI-103 op. by HILCORP AL (100.0%) to be check.CI-106 op. by HILCORP AL (100.0%) to be check.CI-545 op. by HILCORP AL (100.0%) to be check.CI-546 op. by HILCORP AL (100.0%) to be check.CI-143 op. by HILCORP AL (100.0%) to be check.CI-754 op. by HILCORP AL (100.0%) to be check.

Chariot is offering equity in its 1,360-sq km Kenitra block in the Doukkala Basin off Rabat  in WD 200-1,500m, exploration (assumed seismic) planned 1H ’19. Meanwhile LKP-1a nfw is planned 2H ‘19 in the company’s Mohammedia offshore block, WD 400m.  Chariot (op), partner Onhym.

Chariot is offering equity in its 1,360-sq km Kenitra block in the Doukkala Basin off Rabat in WD 200-1,500m, exploration (assumed seismic) planned 1H ’19. Meanwhile LKP-1a nfw is planned 2H ‘19 in the company’s Mohammedia offshore block, WD 400m. Chariot (op), partner Onhym.

Further to DEA 16 Feb ’18, Salta’s planned offer of 15 blocks totalling some 54,000 sq km will be held in 2 tranches. A majority of blocks will be released on 15 May 2018, the remainder to follow tentatively in July. Selected blocks are:  

Salta’s planned offer of 15 blocks totalling some 54,000 sq km will be held in 2 tranches. A majority of blocks will be released on 15 May 2018, the remainder to follow tentatively in July.

Fieldwood Energy was formally awarded Green Canyon Block GC 153 (G36814) on 1 November 2019. GC 153 is located in the Louisiana Coastal Basin and was originally offered as part of OCS Gulf of Mexico Lease Sale 253, which was held on 21 August 2019 and garnered more than US$ 159 million in high bids. Fieldwood accounted for three of these high bids, worth a total of US$ 1.77 million. Fieldwood Energy is the operator and sole interest-holder (100% WI + Op) in GC 153.

Not Found

Wintershall Dea has agreed to sell RDG its interests in several prod. leases throughout the country. The inventory comprises Aitingen (33.33%), Hebertshausen (100%), Landau (66.67%), Lauben/Bedernau (50%), Schwabmuenchen (100%), Suderbruch (100%) + Tannheim/Engelsberg (50%), together accounting for some 1,000 boe/d. Wintershall Dea intends to focus on production from the Emlichheim and Mittelplate oilfields and gas production in the Verden area, N. Germany.

Wintershall Dea is selling its operated participating interests in certain domestic oil concessions to compatriot player RDG. The concessions being sold include Aitingen (in which Wintershall Dea holds a 33.33% interest), Schwabmuenchen (100%), Lauben/Bedernau (50%) and Hebertshausen (100%), all of which are located in Bavaria, southern Germany.Also part of the deal is Wintershall Dea’s 66% interest in the Landau concession in Rhineland-Palatinate, the Tannheim/Engelsberg concession (50%) in Baden-Wurttemberg and the Suderbruch concession (100%) in Lower Saxony.The licences contribute about 1000 boe/d to Wintershall Dea’s production.

The ANP has cleared Petrobras to take on the 25% held by lone partner ONGC Videsh in the 577-sq km BM-BAR-001 contract and the associated discovery evaluation plan (PAD) in the Barreirinhas Basin. The contract has been suspended for many years due to environmental permitting issues (DEA 3 May '19).

Brazil, BM-BAR-001

On 2 February 2018 International Petroleum Corp (IPC) was granted the Amaltheus concession. The expiry date was set on 1 January 2040. The 37 sq km Amaltheus block is located in the Champagne-Ardennes province some 40 km to the south of the town of Reims. It covers part of the former Val-des-Marais exploration permit operated by the company and which was due to expire in 2014. Financial commitments include a rent of EUR 15 per hectare. The concession encompasses the Pierre Morains 1 small oil field discovered in 1986 and which produced some 10,000 bo from the Rhaetian sandstones until the early 1990’s. In 2012 Lundin successfully completed with oil the Amaltheus 1 appraisal of the Pierre Morains 1 field designed to evaluate the lateral southeastern extension of it. The company had estimated the unrisked prospective resources addition at 2 MMboe with a chance of success of 50%. In 2017 Lundin spinned-off its non-Norwegian assets to the newly created company IPC. International Petroleum Corporation (IPC) is sole right holder in the Amaltheus concession.

France (Paris B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Val-des-Marais op. by IPC (100.0%) to be check.Amaltheus op. by IPC (100.0%) to be check.

Beach Energy Ltd spudded the Wirruna 1 exploration well in PRL 130, located in the Cooper-Eromanga Basin, on 25 July 2019.  The well was drilled by the “SLR Rig 185” land rig.  On 4 August 2019 the well was plugged and abandoned, with evaluation ongoing. The well was part of Beach’s ongoing Cooper-Eromanga 2019 exploration and appraisal programme.  Wirruna 1 is located to the south of the Crockery, Haslam and Ralgnal gas fields. PRL 130, which covers an area of 54 sq km, was awarded on 8 October 2014.  Beach Energy Ltd holds 100% interest and operatorship of the permit, with 50% held through wholly owned subsidiary Great Artesian Oil and Gas Pty Ltd.

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

N. part of POT-T-619 block, onshore Potiguar, assumed P&A dry 4 Feb ’18 as no shows report filed. PTD was 620m,  target L. Cret. Alagamar fm.

1-619AB-001-RN (1-GPK-003-RN) op. by Geopark (100%) in POT-T-619 block, P&A, dry.

The previous licence holders in PL 019 F (Repsol 61%, INEOS 34% and KUFPEC 5%) have all withdrawn with effect from 31 January 2020 (reported by the NPD on 6 February 2020). Their interests have been acquired by Aker BP (55%) and DNO (45%) and Aker BP has assumed operatorship. This deal aligns the interests in PL 019 F with PL 065 which lies immediately to the west. PL 019 F (3 sq km of block 2/1 which was split from PL 019 B in December 2018) contains the southeasterly extension of Tambar which lies mostly in PL 065. Tambar was discovered in 1983 by 1/3-3. It is located on the Ula Trend at the eastern margin of the Central Trough, between Gyda and Ula and is a hanging wall trap formed by the extension and minor contraction of a late Jurassic fault array. Tambar has been developed as a tie-back to the Ula Field, some 16 km to the northwest. The development uses a remotely controlled wellhead facility without processing equipment. The field was granted a lifetime extension until 1 January 2022 by the NPD on 8 July 2016. In the original PDO, approved on 15 July 2001, the lifetime of the facility was defined as 15 years, meaning it was due to expire on 15 July 2016. In 2018 two new infill wells, targeting undrained areas in the north and south of the field as part of re-development work, were completed and initial performance exceeded pre-drill expectations. This, plus the implementation of gas lift in three existing wells, will extend the lifetime of the field from 2018 to 2028, with the potential for it to be extended again in the future. The upgrade is targeting reserves of 27 MMboe, producing an additional 4,000-6,000 boe/d, and total investments were forecast at approximately NOK 1.7 billion (USD 205 million). Interest in PL 019 F is now held by Aker BP ASA (55% + operator) and DNO Norge AS (45%).

The previous licence holders in PL 019 F (Repsol 61%, INEOS 34% and KUFPEC 5%) have all withdrawn. Their interests have been acquired by Aker BP (55%) and DNO (45%) and Aker BP has assumed operatorship.

Effective 4 Dec ’17, AP signed for entry into the 2nd extn periods along with 50% area red’s of its SL-03 and SL-04A-10 licences and to modify the related work programmes. SL-03 now expires 23 Apr ‘19 and SL-04A-10  17 Sep ‘19 should the company (operating through 2 subs) commit to 1 well/block by prior to 1 Nov ’18 (Leo + Vega prospects identified). SL-03 drops from 1,930 sq km to 962 sq km, and SL-04A-10 from 1,995 sq km to 995 sq km. Map below prior to area change:

Sierra Leone, SL-04A-10

On 21 November 2019, the Federal Agency for Subsoil Use held an auction for three blocks in Saratov Oblast (Volga-Ural Province). The winning bids were submitted by Wolgodeminoil (Lukoil/Wintershall), LukBelOil and Moscow-registered Ratus-Invest. The Dmitriyevskiy block covers 11.2 sq km in the Volga-Urals Basin. The block encompasses the Dmitriyevskoye field with the remaining reserves estimated at 0.1 MMbbl of oil, 18.9 Bcf of gas and 0.1 MMbbl of condensate in five reservoirs within the Lower-Middle Carboniferous section. The starting price amounted to RUB 36.13 million (USD 0.56 million). Ratus-Invest offered RUB 39.743 million (USD 0.62 million). The winner of the auction will be awarded a 20-year E&P license. The Strepetovskiy block covers 3.1 sq km in the Volga-Urals Basin. The block encompasses the Strepetovskoye oil discovery with the reserves estimated at 0.2 MMbbl in one reservoir within the Middle Devonian section. The starting price amounted to RUB 9.72 million (USD 0.15 million). LukBelOil offered RUB 10.692 million (USD 0.17 million). The winner of the auction will be awarded a 20-year E&P license. The Belokamenyy Severnyy block covers 217.4 sq km in the Volga-Urals Basin. The block encompasses the Belokamennaya Zapadnaya, Beregovaya, Rechnaya, Pravoberezhnaya and a part of Rovenskaya Severnaya structures. Hydrocarbon resources (category D1) of the block are estimated at 24.3 MMbbl of oil, 44.5 Bcf of gas and 0.8 MMbbl of condensate. The starting price amounted to RUB 36.01 million (USD 0.56 million). Wolgodeminoil offered RUB 39.611 million (USD 0.62 million). The winner of the auction will be awarded a 25-year E&P license.

Russia, not found

On 4 August 2020, Ecopetrol reported that the Obiwan 1 new-field wildcat (NFW) in the Hocol operated YD SN 1 Block, in the Lower Magdalena Basin, was plugged and abandoned dry. The NFW spudded in 8 March 2020 and it was completed on 25 June 2020 according to the Agencia Nacional de Hidrocarburos (ANH). The well lies in the northern part of the YD SN 1 Block, about 5 km of the Tolu 1 discovery. The Tolu 1 NFW spudded in 1959 and reached a total depth (TD) of 9,326 ft (2,843 m) and targeted Miocene sandstones of the Tubara Formation. Hocol operates the 80.29 sq km YD SN 1 Block with 100% working interest. The block was officially awarded in August 2014 during the first phase of the Ronda Colombia 2014.

(Lower Magdalena B.) Ecopetrol (100%) reported that the Obiwan 1 nfw in the Hocol operated YD SN 1 Block, was plugged and abandoned dry.

Metgasco Pty Ltd commenced a farm-out process for its two Cooper Basin exploration licences: ATP 2020-P and ATP 2021-P in October 2018. A data room has been opened, and in March 2019 the company reported that it was continuing discussions with interested parties ahead of its development timetable in April 2019. On 22 May 2019, Metgasco announced a Head of Agreement (HoA) has been entered into with Vintage Energy, and subsequently and Farm-out Agreement was announced on 2 July 2019. Vintage is set acquire 50% interest in ATP 2021-P. The agreement is subject to several approvals which are expected to be met by end-July 2019. Metgasco has outlined a number of prospect and leads within the permits, which are surrounded by existing discoveries. The initial work programme will focus on better identifying the leads, completing regional geological evaluation and refining play types. Metgasco plans to drill at least one prospect in 2H 2019. Two conventional gas prospects have been identified in ATP 2021-P which Metgasco have moved to ‘drill-ready’ status after completing sub-surface technical work and seismic interpretation. Gas in place on a risked, high case estimate for both prospects is 111 Bcf. Additional technical work has begun to build on indications of Jurassic, shallow oil plays within the permit area. The Odin Prospect is an anticlinal structure on the western boundary of ATP 2021 with an independent closure at a depth of around 2,300 m. The Strathmount 1 exploration well, which was drilled in 1987, lies within the extent of the prospect. The well encountered 21 m of reservoir sands and 13.7 m of interpreted gas pay. Gas flow testing indicated returned gas to surface but at rates were too small to measure. On the 2016 Snowball 3D seismic data, Metgasco reports that the well appears to have intersected the sands outside of the Toolachee and lower Patchawarra level. Odin has been assigned P50 recoverable resources of 8.7 Bcf. The Vali Prospect is also considered an anticlinal structure at the Toolachee and lower Patchawarra levels with independent closure at a depth of around 2,250 m. Metgasco has reported that the prospect is likely to contain reservoir characteristics similar to that of the nearby Kinta 1 gas discovery. The Kinta 1 well intersected 37 m of interpreted gas pay but did not retuned hydrocarbons to surface. Vali has been assigned P50 recoverable resources of 19 Bcf. In the case that the Vintage Energy farm-in is completed, it is hoped that the Vali Prospect will be drilled at end-2019. In ATP 2020, Metgasco commenced seismic reprocessing during December 2018 to determine if additional seismic data is required over identified oil and gas leads. Metgasco was awarded the permits on 29 May 2018 with 100% interest. The areas, totaling 905 sq km, were applied for as PLR2015-2-16 and PLR2015-2-19, after they were offered in the 2015 Queensland State Acreage Release.  Metgasco was announced as the preferred bidder in late 2016. Awarded for a period of six years, both permits are due to expire on, or be eligible for renewal by, 31 May 2024. The HoA with Vintage Energy includes the terms that Vintage is required to contribute 65% of costs relating to ATP 2021-P, including drilling of the first exploration well (up to AUD 5.3 million) and to also cover 65% of past exploration costs already incurred by Metgasco (AUD 527,800). The initial work programme over the permits focused on better identifying the leads, completing regional geological evaluation and refining play types. To further define existing leads, Vintage will also fund up to AUD 70,000 relating to reprocessing of 2D and 3D seismic data. ATP 2020-P and ATP 2021-P, which cover areas of 534 sq km and 363 sq km respectively, are available for farm-in.  Metgasco holds 100% interest and operatorship of the permits. Subject to a completed farm-in by Vintage Energy, participants in ATP 2021-P will become: Metgasco Ltd (50%) and Vintage Energy Ltd (50%). Companies interested in pursuing this opportunity should contact: Ken Aitken, Metgasco CEO Phone: +61 (0) 2 9923 9100

Metgasco Pty Ltd commenced a farm-out process for its two Cooper Basin exploration licences: ATP 2020-P and ATP 2021-P in October 2018.

Delek is looking to dispose of its remaining 22% in the offshore Tamar gasfield next year, having sold an initial 9.25% into Tamar Petroleum in 2017, later followed by Noble (DEA 30 Jan ’18).

Delek is looking to dispose of its remaining 22% in the offshore Tamar gasfield next year, having sold an initial 9.25% into Tamar Petroleum in 2017, later followed by Noble

PL 1046, Cooper-Eromanga, drilled late Jun – late Jul '20, result unreported. Target assumed Toolachee fm. Santos (op), partner Beach.

(Eromanga B.) Hector SE-1 explo well opearted by SANTOS (70%), BEACH (30%) in PL 1046 block is believed to have been suspended, results unreported

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

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

Novatek announces the acquisition of Severneft-Urengoy from fertilizer group EuroChem.  Severneft-Urengoy operates the gas-cond West (Zapadnyy) Yaroyakhinskiy E+P licence close to Novatek existing infrastructure in the Purovsky district, Nadym-Taz Basin in Yamal-Nenets AO, W. Siberia. It contains 918 MMboe resources and produced 816 MMcum gas + 93 MMt cond in 2016.  www.novatek.ru.

Russia, not found

Aker BP spudded Nidhogg exploration well 6506/5-1 S in the Skarv area, to the west of the Victoria discovery, on 30 January 2020 using the “Deepsea Nordkapp” S/S. Nidhogg is located in PL 1008 which was awarded in March 2019 under APA 2018. The well’s objective was the Upper Cretaceous Lysing Formation (prognosed at 3,051 m TVD) and potential recoverable resources are 37-96 MMboe (gas condensate was expected). TD was reached at 3,225 m (3,198 m TVD) and then a technical sidetrack (T2 – which had a TD of 3,077 m / 3,050 m TVD and was drilled between 10-12 March 2020) was carried out for coring purposes. On 21 March 2020 Aker BP confirmed it had abandoned the well, results are expected to be announced shortly. PL 1008 lies to the west of Aker BP’s Aerfugl field where development is progressing towards a 2020 onstream date. Aerfugl will be a phased development using a total of six subsea wells tied-back to the Skarv FPSO. Phase I includes three producers in the southern part of the field and Phase II covers the northern part of the field plus a well on Snadd Outer (PL 212 E). Aerfugl has estimated recoverable reserves of 975-1,653 Bcfg plus 31-48 MMbc in an Upper Cretaceous Lysing Formation reservoir and a 15 year life. PL 1008 is operated by Aker BP ASA, holding a 60% interest. Wellesley Petroleum AS holds the remaining 40%.

6506/05-01 S (Nidhogg) nfw. (Aker BP 60% op, Wellesley 40% ) in PL 1008 block, Skarv area near Ærfugl, WD=442m, P&A at TMD=3225 m (3198m TVD), results n/a, Target Lysing Fm gas-cond.

Oil and Gas Development Company Ltd (OGDCL) has assigned 2.5% working interest in the Gwadar 2561-1 EL (Makran-Balochistan Flysch Belt) onshore exploration licence to Government Holdings (Pvt) Ltd (GHPL) with effect from 20 December 2017. As a result the new equity split is as follows: OGDCL 97.5% (operator) and GHPL 2.5%. The Gwadar block covers an area of 2,407 sq km and it is located in the Kech and Gwadar districts of Balochistan province. OGDCL was exclusively awarded this block with the signing of Petroleum Concession Agreement (PCA) on 21 March 2014.  

Oil and Gas Development Company Ltd (OGDCL) has assigned 2.5% working interest in the Gwadar 2561-1 EL (Makran-Balochistan Flysch Belt) onshore exploration licence to Government Holdings (Pvt) Ltd (GHPL)

Melbana Energy Ltd reported on 15 July 2019 that it was intending to make a takeover offer for Metgasco Ltd.  Under the offer the company plans to acquire 100% of the ordinary shares in Metgasco, by offering shareholders four fully paid Melbana shares for every one Metgasco share. Melbana reported that the offer has an implied value of AUD 0.04 per share, which is a 48% premium on the closing price of Metgasco shares on 12 July 2019 and a 35% premium on the five day weighted average.  For the takeover to be successful Melbana must receive an acceptance of 50.1% from shareholders.

Melbana Energy Ltd reported on 15 July 2019 that it was intending to make a takeover offer for Metgasco Ltd. Under the offer the company plans to acquire 100% of the ordinary shares in Metgasco, by offering shareholders four fully paid Melbana shares for every one Metgasco share. Melbana reported that the offer has an implied value of AUD 0.04 per share, which is a 48% premium on the closing price of Metgasco shares on 12 July 2019 and a 35% premium on the five day weighted average. For the takeover to be successful Melbana must receive an acceptance of 50.1% from shareholders.

JZ 19-1-1 was completed around 22 March 2020 without result reported. CNOOC – Tianjin spudded a new-field wildcat (NFW), JZ 19-1-1, in Bohai offshore, Bohai Gulf Basin on 18 February 2020. The well is located in Jinzhou 09 block in the west Liaodong Bay in a water depth of approximately 26 m. It is assumed to be targeting the Archean basement granite and Lower Tertiary clastic play based on reservoirs revealed in the adjacent fields. “Zhongyouhai 6” J/U is used for the drilling operation. Background Information There are two fields nearby on production in the east and northeast of the well. Jinzhou 25-1S, discovered in August 2002 with main reservoir in the Archean Series and second reservoir in the Oli-Eocene Shahejie 2 Member. It was brought onstream in December 2009 and producing 32 Mb/d of oil, about 69 MMcf/d of gas and about 639 b/d of condensate in 2018. Jinzhou 25-1, discovered in July 1985, but without commercial value until 2007 when CNOOC came back to drill JZ 25-1-2 and 3 wells after further studies on the discoveries made in the adjacent structures. Oil and gas mainly accumulated in the Eocene Shahejie 3 Member, secondly in the Oli-Eocene Shahejie 2 Member and thirdly in the Jurassic Series. The field was brought onstream in March 2011. The production was still ramping up in 2018 with oil production at a rate of over 19 Mb/d, gas production at a rate of 12 MMcf/d and condensate at a rate of 107 b/d. Latest discovery made in the area is Jingzhou 25-1W-1 in 2016, located in the north of the well, with no further exploration activity since. Several wells drilled in the surrounding area in the last few years are not satisfied: In 2013, SZ 30-2-1 completed as a dry hole. In 2004, JZ 31-2E-1 completed as a dry hole. In 1988, JZ 25-2-1 completed with oil show. In 1988, SZ 30-3-1 completed as a dry hole. In 1986, JZ 19-2-1 completed as a dry hole. Liaodong Bay is part of Bohai offshore, next to Liaohe Depression onshore in the north and Bozhong Depression offshore in the south. CNOOC has more than 10 fields on production in this area, including the second largest field in Bohai offshore - Suizhong 36-1. The existing fields have main reservoirs in the Tertiary sandstones with a few ones in the pre-Tertiary Basement.

JZ 19-1-1 was completed around 22 March 2020 without result reported. CNOOC – Tianjin spudded a new-field wildcat (NFW), JZ 19-1-1, in Bohai offshore, Bohai Gulf Basin

In Q3 2018, Agiba Petroleum completed its Meleiha 57 Deepening deeper-pool test (DPT) as an oil producer. The well encountered a new oil pool in the Early Cretaceous Alam El Bueib (AEB) Formation, below the producing Cretaceous Bahariya Formation of the Meleiha Field. It was drilled on the Meleiha development lease of the Meleiha PSC, located in the Shushan Basin. The well was spudded on 7 June 2018, reaching 2,804m TD (2,564m TVD) in the AEB interval. Operations were carried out by the Egyptian Drilling Company #64 rig. The original wellbore, the Meleiha 57 development well, was drilled in 2016. Meleiha 57 Deepening was one of two DPTs drilled on the Meleiha Field, with Meleiha 55 Deepening also encountering oil in the AEB horizon. Equity in the Agiba consortium is split between Eni (38%), Lukoil (12%) and EGPC (50%, carried). <P />

Agiba Petroleum completed its Meleiha 57 Deepening deeper-pool test (DPT) as an oil producer. The well encountered a new oil pool in the Early Cretaceous Alam El Bueib (AEB) Formation, below the producing Cretaceous Bahariya Formation of the Meleiha Field.

On 15 October 2018 Equinor returned to PL 615 to spud an exploration well on the Intrepid Eagle prospect. 7324/3-1 was drilled using the “West Hercules” S/S and is located approximately 13 km west of the 2014 Atlantis gas discovery. The well has made a new gas discovery in the upper part of the Triassic Snadd Formation. A 30 m gas column was present (net 20 m reservoir) with a GWC at 1,492 m. Estimated recoverable reserves are 350 – 700 Bcf gas. Gas was also proven in a lower part of the Snadd Formation – the same reservoir as Atlantis – but the sandstone was tight and so a total gas column height could not be established. Reserves for this reservoir are estimated at 35 – 140 Bcfg. The secondary objective in the Jurassic Sto Formation contained 15 m of water-wet sandstone. TD was reached at 1,709 m in the Snadd Formation and the well was abandoned on 21 November 2018. The Intrepid Eagle drilling plan prognosed the Sto Formation reservoir at 901 m (22 m thick with a porosity of 20% and a permeability of 150 mD), the upper Snadd Formation reservoir at 1,525 m (40 m thick, 21% porosity, 200 mD permeability) and the lower at 1,680 m (30 m thick, 18% porosity, 15 mD permeability). 7325/1-1 targeted the Atlantis prospect and proved 55 m net of sandstone in the Snadd Formation with a 10 m gas column. A 10 m sandstone section with hydrocarbon shows was present in the Middle Triassic Kobbe Formation (the main objective) and the Lower Triassic Havert Formation also contained sand but with poor reservoir properties. Reserve volumes were estimated at 18-70 Bcfg. Interest in PL 615 is divided between Equinor Energy AS (55% + operator), OMV (Norge) AS (25%) and Petoro AS (20%).

7324/03-01 (Intrepid Eagle) (Equinor 55% op, OMV 25%, Petoro 20%) in PL 615, small gas disc, W. of Atlantis discovery, 30m gas column in the upper part of the Snadd target, of which 20m moderate-poor reservoir quality, GWC at 1492m 350-700 Bcf recoverable. The lower part of the Snadd is also host to some gas, poor-moderate tight reservoir, 35-140 Bcf recoverable. 15m of aquiferous reservoir was encountered in the Stø fm. Profitability is currently unclear. WD=452m, TD=1678m.

Pandion has acquired Aker BP’s 30% interest in PL 842 with effect from 14 June 2019 (confirmed by the NPD on 26 June 2019). The licence is located northeast of Norne and covers parts of blocks 6608/10, 11 and 12. An exploration well targeting the Godalen prospect is due to be drilled in PL 842 in July 2019. The deal was originally announced by Pandion on 31 December 2018. The Godalen well will target potential recoverable reserves of 90 MMboe in the Upper Jurassic Rogn Formation, and if it is successful a tie-back to Norne will be considered. TD is planned at around 1,700 m and the well should be in operation for around 30 days. Following completion of the deal interest in PL 842 is held by Cairn through Capricorn Norge AS (40% + operator), Skaggen44 AS (30%) and Pandion Energy AS (30%).

Pandion has acquired Aker BP’s 30% interest in PL 842

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

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

In April 2018, Novatek updated on its activities at the Salmanovskoye (Utrenneye) discovery in Yamalo-Nenets Autonomous Okrug (Western Siberia). In 2014-2017, Novatek-subsidiary Arctic SPG2 drilled six appraisal wells that resulted at extension of the discovery’s productive area and increase of its reserves. As the end of 2017, the company estimated 3P reserves of the discovery at 54.8 Tcf of gas and 475 MMbbl of condensate and oil. Novatek considers Salmanovskoye as the feedstock for the planned LNG plant with three trains with combined capacities of 20 million tons per year. The first train is scheduled for production in 2023. Salmanovskoye, discovered in 1979, is located in the South Kara-Yamal Province in the Gydan Peninsula with a minor extension to the Ob estuary. About 60 identified hydrocarbon accumulations are distributed within the 2,100 m sedimentary section aging from Valanginian to Cenomanian.

Russia (South Kara - Yamal Province (West Siberian B.)) Salmanovskoye

On or about 5 June 2020, the semisubmersible Seadrill "Sevan Louisiana" left its location in the southwestern corner of the Mississippi Canyon (MC) protraction area of the deepwater central Gulf of Mexico, where it completed drilling well MC 881 1S0B1 (API 608174142001) for operator Walter Oil & Gas. The original hole, MC 881 1S0B0 (API 608174142000), was spudded on 23 February 2020 with a surface location in MC 882 (G35989) and bottom hole location in MC 881 (G35988). Bypass operations began on 17 April 2020 at a depth of 5,331 ft (1,625 m). Walter has not reported results. The Bureau of Ocean Energy Management (BOEM) on 24 February 2020 approved the drilling application submitted by Walter on 5 November 2019. The approved location corresponds to well "A" in the company's exploration plan N-10071, submitted on 13 June 2019 and approved by the BOEM on 9 October 2019. The plan described two locations, "A" and "B". The well sits in water depth of 2,234 ft (681 m) some 73 mi (117 km) south of the onshore support base at Port Fourchon, Louisiana. The prospect is about 7 mi (11 km) east of the Eni-operated Morpeth-Klamath field, which produced over 24 MMbo and 24 Bcfg from Pliocene-aged reservoirs before ceasing production in August 2018. Based on the exploration plan, Walter estimates it will take 382 days to drill, complete and test the well, and install a subsea tree. Walter acquired MC 881 and 882 with sole uncontested bids for a combined USD 2.1 million at Sale 247 in March 2017. Background Information Exxon drilled a well in MC 881 in 1990. Well MC 881 1S0B0 (API 608174038700) targeted the Pleistocene interval but came up dry. The well was drilled under lease G07967.

(Deep Water Gulf of Mexico B.) Mississippi Canyon 881 001S0B0 op. by OXY (75%), OPUBCO (16%), HI PRO (9%) in MC 881 block, TD = 3105.6 m, WD = 598.6 m deviated into MC 881, E. of Eni's Morpeth-Klamath field in WD=681m, ops terminated, no further details are available.

Glencore has reportedly put its oilfields in Chad up for sale. It is unclear whether the offer is only for the fields (Mangara + Badila) or whether all the company’s permits are on the table.  These are: Chari East / Doseo (22,057 sq km), DOB (Mangala) / DOI (Badila) (3,108 sq km), Badila (38 sq km), FOH / NDonambo (839 sq km), Kibea (124 sq km), Mangara (60 sq km).

Glencore has reportedly put its oilfields in Chad up for sale. It is unclear whether the offer is only for the fields (Mangara + Badila) or whether all the company’s permits are on the table. These are: Chari East / Doseo (22,057 sq km), DOB (Mangala) / DOI (Badila) (3,108 sq km), Badila (38 sq km), FOH / NDonambo (839 sq km), Kibea (124 sq km), Mangara (60 sq km).

Further to DEA 19 Oct ’17, the authorities now confirm the award to Kosmos and 20% partner GEPetrol of blocks EG-21, S and W. The relevant Official map extract below shows these units circled, and substantially boost Kosmos’ position in the country when coupled to the Hess interest takeovers (see relevant entry). Ratification of contracts is normally scheduled 15 Dec ‘17. Of note, EG-21 was offered in EG Ronda 2016, but not listed as assigned to any of the winners. Blocks S + W were not part of the round, and according to our records assigned to PanAtlantic and CNOOC respectively until late 2016 and mid-2017 when they expired.  

Equatorial Guinea, not found

Pursuant to RAK’s 1st licensing round, PGNiG signed with RAK Gas and the RAK Petroleum Authority for E&P rights to on/offshore block 5, 619 sq km as per the official map below. 2+2+2 years explo, 30 years prod:

UAE, not found

On 28 September 2018, the consortium of ExxonMobil and QPI was granted a preliminary award for the Tita block through the 5th PSC Pre-Salt Bid Round after being the high bidder for the block.  The consortium paid a fixed bonus of USD 781.25 million at USD 1.00 to BRL 4.00 exchange rate and has a first exploration period financial guarantee of USD 62.50 million to cover the cost of the one well drilling commitment.  The consortium offered a state take of 23.49% and won the block over the one other bid for the block by Shell with 50% and Ecopetrol with 50% who bid 11.65% state take.  ExxonMobil is operator and has 64% working interest and partner QPI has 36% working interest in the PSC contract. The PSC contract has a seven year exploration period.  The local content is 18% for the exploration phase and 25% to 40% for the development and production phases.

On 28 September 2018, the consortium of ExxonMobil and QPI was granted a preliminary award for the Tita block through the 5th PSC Pre-Salt Bid Round after being the high bidder for the block.

It was announced on 29 December 2019 that Protech Enerji has been awarded the M45-C exploration licence (Zagros Province) on 17 December 2019 for a period of five-year. The licence, covering an area of 492 sq km, is located towards southeast of the country and Protech Enerji will be 100% owner and operator of the licence.

Protech Enerji has been awarded the M45-C exploration licence (Zagros Province)

Add. DEA 21 Mar ’19: South East Madura block off E. Java, TD 2,222m, susp o&g 9 Apr ‘19, gas tested earlier this year, gas kick also in late 2018. Main target assumed Ngrayong sst.

ENC-2 appr South East Madura block off E. Java, TD 2,222m, susp o&g 9 Apr ‘19, gas tested earlier this year, gas kick also in late 2018. Main target assumed Ngrayong sst.

A review of Putu and Pikka drilling results has led Oil Search to exercise a USD 450 MM option with Armstrong Energy to take the latter’s remaining 25.5% interest in the Pikka unit, 37.5% in Horseshoe, 37.5% in the Hue Shale leases and 25.5% in various sundry explo areas totalling 789 sq km on the North Slope. Oil Search also has agreed with Repsol to align interests in shared assets, implying a reduction from 75% to 51% in the Horseshoe unit and retention of 51% in Pikka. In exchange Repsol will assign Oil Search 51% in leases obtained in 2017 east of the Horseshoe area while retaining operatorship.  Explo + appraisal drilling is planned in the Horseshoe and East Pikka areas, where FID on phase 1 devt is expected mid-2020. Block id’s from GEPS. Oil Search will also embark on a sale of some interests in Alaska, with the intention of retaining ab. 35% in its core areas.

A review of Putu and Pikka drilling results has led Oil Search to exercise a USD 450 MM option with Armstrong Energy to take the latter’s remaining 25.5% interest in the Pikka unit, 37.5% in Horseshoe, 37.5% in the Hue Shale leases and 25.5% in various sundry explo areas totalling 789 sq km on the North Slope. Oil Search also has agreed with Repsol to align interests in shared assets, implying a reduction from 75% to 51% in the Horseshoe unit and retention of 51% in Pikka. In exchange Repsol will assign Oil Search 51% in leases obtained in 2017 east of the Horseshoe area while retaining operatorship. Explo + appraisal drilling is planned in the Horseshoe and East Pikka areas, where FID on phase 1 devt is expected mid-2020. Block id’s from GEPS. Oil Search will also embark on a sale of some interests in Alaska, with the intention of retaining ab. 35% in its core areas.

Rawson Oil & Gas Ltd completed the farm-out of additional interest in exploration licence PEL 155, located in the onshore Otway Basin, to Vintage Oil & Gas Ltd on 28 May 2018.  Under the terms of the agreement, Vintage has acquired an additional 25% interest in the licence, taking its total holding to 50%. The change of interest was subject to regulatory approvals. The companies entered the farm-in agreement on 29 March 2018. The operator reported that the joint venture had been successful in applying for a PACE (Plan for Accelerating Exploration) gas grant from the South Australian government, receiving AUD 4.95 million after executing the PACE Funding Deed. The funds will cover approximately 50% of the cost of the planned Nangwarry 1 well. Rawson previously announced on 16 November 2017 that it had executed a farm-in agreement with Vintage which saw the latter company earn 25% interest in the licence for a payment of AUD 100,000.  Execution of the agreement formalised the joint venture, with the option for Vintage to acquire an additional 25% by assisting with the funding of the Nangwarry 1 exploration well on a 50:50 basis with Rawson. The initial, binding, heads of agreement for Vintage Oil and Gas to acquire interest was entered into on 27 July 2017.  On 3 August 2017 Rawson reported that it and Vintage Energy had applied for a PACE Gas grant from the South Australian government in relation to PEL 155.   The Nangwarry prospect is located in the northwest of the licence area.  The prospect is outlined by Rawson as a three-way dip closed, fault-trapped reservoir within the Pretty Hills Formation.  The prospect has been further defined by the 34 sq. km Nangwarry 3D seismic survey, acquired in February 2008, and is thought to be analogous to the proximal Katnook, Haselgrove and Ladbroke Grove gas/condensate fields which have all produced from the Pretty Hill Formation. There are also additional leads within PEL 155 that could form future targets. PEL 155, which covers an area of 226 sq km, was awarded on 30 June 2003. Interest in the permit now stands at Rawson subsidiary Otway Energy Pty Ltd (50% + Operator) and Vintage Oil & Gas (50%).

Rawson Oil & Gas Ltd completed the farm-out of additional interest in exploration licence PEL 155, located in the onshore Otway Basin, to Vintage Oil & Gas Ltd on 28 May 2018. Under the terms of the agreement, Vintage has acquired an additional 25% interest in the licence, taking its total holding to 50%.

HitecVision-owned NEO Energy has agreed to purchase 10 producing North Sea fields from Total, after previous joint venture (JV) partner Petrogas withdrew from the proposed deal. HitecVision announced on 20 May 2020 that it has renegotiated the transaction terms to reflect current market conditions, with the deal expected to close in Q3 2020 subject to regulatory approval. The Petrogas NEO 50/50 JV had originally agreed to buy the 10 fields for US$ 635 million, as announced on 10 July 2019. The assets have 2019 production of ~23,000 boe/d, adds reserves of 51 MMboe to NEO Energy, which includes operatorship of Quad 15 and Flyndre areas with an FPSO and over 80 employees and contractors. NEO Energy will acquire operated interest in seven fields from Total: 100% in Dumbarton (AKA Donan - P1041 15/20a), Balloch & Lochranza (P1041 - 15/20a) and Drumtochty (P2131 - 15/25c), 65.94% in Flyndre (P079 & P255 - 30/13a & 14a), 66.67% in Affleck (P255 - 30/19a) and 60.6% in Cawdor (P079 & P255 - 30/13a & 14a). The company will also gain equity in three CNOOC-operated fields - 31.56% in GoldenEagle (P928 & P300 - 20/1 & 14/26a), 5.16% in Scott and 2.36% in Telford (P185 - 15/22). Total acquired the assets when it bought Maersk Olie & Gas A/S (Maersk Oil) in March 2018. HitecVision UK assets are held in subsidiary NEO Energy (previously Verus Petroleum until November 2019) which holds interest in 13 licences (3 Op) over 16 part blocks with production of 15,550 boe/d from multiple fields. In Norway, Eni Norge and HitecVision subsidiary Point Resources merged to form VÃ¥r Energy in 2018. HitecVision also holds equity in Norwegian mature asset operator CapeOmega.<P />

HitecVision-owned NEO Energy has agreed to purchase 10 producing North Sea fields from Total, after previous joint venture (JV) partner Petrogas withdrew from the proposed deal. HitecVision announced on 20 May 2020 that it has renegotiated the transaction terms to reflect current market conditions.

The ANP has approved the 36.5% interest acquisition by Exxon Mobil and the 3% acquisition by Petrogal from Equinor in the BM-S-008 contract, Carcará discovery evaluation area, Santos Basin. Although the farmout is complex it represents an alignment of equity across the 2 blocks that together make up the Carcará find. As a result, both Equinor and ExxonMobil will have a 36.5% interest in BM-S-008 and 40% in Norte de Carcará. Galp will have 17% in BM-S-008 and 20% in Norte de Carcará. Equinor operates the unitised field devt.

The ANP has approved the 36.5% interest acquisition by Exxon Mobil and the 3% acquisition by Petrogal from Equinor in the BM-S-008 contract, Carcará discovery evaluation area, Santos Basin.

On 26 February 2019, the Federal Agency for Subsoil Use held An auction was held 26 Feb ’19 for 5 blocks in the Chechnya Republic (North Caucasus), local Chechenneftekhimprom winnng 3 under 25-year contracts: - Benoyskiy Zapadnyy, 26 sq km in the Terek-Caspian Basin. Chechenneftekhimprom offered the starting price of USD 20,000 and won. - Dzhalkinskiy Severnyy, 44 sq km in the same basin, contains the Dzhalkinskoye Severnoye oilfield. Chechenneftekhimprom offered the starting price of USD 10,000 and won. - Khankalskiy, 26 sq km in the same basin, contains the Khankalskoye oilfield. Starting price USD 190,000, Chechenneftekhimprom offered USD 200,000. Blocks shunned were Groznenskiy Zapadnyy + Shelkovskoy.

Russia, not found

Pacific O&G (op) and partners Bukit + NZOG are each looking to farm-down their interests in the Kisaran & MNK Kisaran PSCs, total 2,180 sq km in N. Sumatra. Operatorship and 100% are available, the conventional contract valid to 2031 and the unconventional to 2045. Map extract below courtesy contact [email protected]:

Pacific O&G (op) and partners Bukit + NZOG are each looking to farm-down their interests in the Kisaran & MNK Kisaran PSCs, total 2,180 sq km in N. Sumatra.

On 7 November 2018, Wintershall with 100% working interest was granted official awards for the POT-M-857, POT-M-863, and POT-M-865 blocks in the offshore Potiguar Basin through the ANP Round 15. On 29 March 2018, Wintershall with 100% working interest was granted preliminary awards for the three blocks. For the POT-M-857 block Wintershall offered a bonus of USD 17.31 million and 294 work units which won the block.  There was one other bid for the block by the consortium of Petrobras, Petrogal, and Shell who bid USD 4.37 million bonus and 264 work units. For the POT-M-863 block Wintershall offered a bonus of USD 7.42 million and 265 work units which won the block.  There was one other bid for the block by the consortium of Petrobras, and Shell who bid USD 3.29 million bonus and 250 work units. For the POT-M-865 block Wintershall offered a bonus of USD 4.95 million and 218 work units which won the block.  There was one other bid for the block by the consortium of Petrobras, and Shell who bid USD 4.38 million bonus and 176 work units.

Wintershall with 100% working interest was granted official awards for the POT-M-857, POT-M-863, and POT-M-865 blocks in the offshore Potiguar Basin through the ANP Round 15.

On 21 November 2018, the Council of Ministers met and agreed on the draft agreement to award the XXVIII (understood to include both XXVIIIA and XXVIIIA) exploration licence to Societe Nationale des Petroles du Congo (SNPC). As is the norm SNPC was awarded the licence but only holds a 15 % interest, Perenco Exploration & Production Congo Ltd (Perenco) operates the area with an 85% stake. The licence was awarded for a period of two years and in non-renewable. Perenco’s bid was opened on 29 March 2017. The 280 sq km area sits atop the shelf within the Lower Congo Basin. It plays host to the 1992 Likoufou Marine 1 oil and gas discovery, the 1992 Likoufou Sud Marine 1 oil and gas discovery, the 1991 Nongo Nord Marine 1 oil and gas discovery and the 1980 Nongo Marine 1 oil discovery. Likoufou Marine 1 is estimated to hold some 30 MMbo and 5,000 MMscf gas. Likoufou Sud Marine 1 is estimated to hold some 1.2 MMbo and 1050 MMscf gas, Nongo Nord Marine 1 is estimated to hold some 6.6 MMbo and 50 MMscf gas and Nongo Marine 1 is estimated to hold less than 1 MMbo.

Perenco (85% op, SNPC 15%) was awarded new PSCs for Marine XXVIII exploration licence.

On 4 May 2020, Petrobras published a teaser to sell its 35% operating working interest in the BCAM-040 contract, Manati production concession in the offshore Camamu-Almada Basin. The Manati field is currently producing from six wells and one fixed platform PMNT-1. Gas and condensate are transported through a 126 km, 24-inches pipeline to the Estacao Geofisico Vandemir Ferreira (EVF). The sale includes the platform, export pipeline, EVF and all field facilities. The concession expires in November 2029. Interested parties, that meet eligibility requirements, should address queries to J.P. Morgan at [email protected] up to 22 May 2020. The BCAM-040 contract, Manati Block (with 75.72 sq km), is operated by Petrobras with 35% working interest, and non-operating partners Enauta, with 45% working interest, Geopark, with 10% working interest, and Brasoil with the remaining 10% working interest. The Manati gas and condensate field was discovered in October of 2000 with the 1-BAS-128-BAS (1-BRSA-14-BAS) new-field wildcat (NFW) that spudded in August of 2000. The NFW reached a total depth (TD) of 1,828 m and targeted Jurassic sandstones of the Sergi Formation. A total of 11 wells have been drilled, including the discovery well, 1 exploration well, 3 appraisal wells and 6 development wells. The ANP estimates for original gas-in-place (OGIP) are 1,417 Bcf as of 31 December 2019, and operator recoverable 2P reserves estimates are 1,024 Bcf as of 31 December 2013, giving a 72% recovery factor. As of end of 2019, cumulative production in the Manati field was 854.5 Bcfg and 2.3 Mbc.

Brazil, BCAM-040

Summer 2018 well in N. part of Cheremshanskoye field area in Ledovy licence 67, west of the Ob river in the Tomsk Oblast, 19.26 MMbbl of C1 + C2 reserves (gross) in Jurassic reservoirs, potential for reserves to double in future taking in a full potential for Jurassic intvs within the 46-sq km structure, and addit. explo potential in the overlying Cretaceous section is under study. Petroneft (op), partner Arawak Energy.

Cheremshanskoye C-4 appr Summer 2018 well in N. part of Cheremshanskoye field area in Ledovy licence 67, west of the Ob river in the Tomsk Oblast, 19.26 MMbbl of C1 + C2 reserves (gross) in Jurassic reservoirs, potential for reserves to double in future taking in a full potential for Jurassic intvs within the 46-sq km structure, and addit. explo potential in the overlying Cretaceous section is under study. Petroneft (op), partner Arawak Energy.

Talos has acquired a 25% interest to Hokchi’s otherwise wholly-owned CNH-R03-L01-AS-CS-15/2018 contract, pursuant to the CHN approval on 12 April.  Talos and Hokchi had agreed last October to exchange 25% in two Sureste PSCs, namely the above CNH-R03-L01-AS-CS-15/2018 and the adjoining Talos-operated CNH-R01-L01-A2/2015.

Mexico, CNH-R01-L01-A2/2015

Terra Nova is looking to dilute its 51.5% interest in PEL 112 + 444, total 2,255 sq km in the Cooper-Eromanga. Both contain a number of prospects. Terra Nova (op), partner Holloman Petroleum. Contact: [email protected].

Terra Nova is looking to dilute its 51.5% interest in PEL 112 + 444, total 2,255 sq km in the Cooper-Eromanga. Both contain a number of prospects. Terra Nova (op), partner Holloman Petroleum. Contact: [email protected].

Further to DEA 27 Feb ’19, Block Energy has completed its takeover of a 100% working interest in the 37-sq km West Rustavi / block XIf PSC in the Kura Basin. The company is implementing a drilling programme and is testing its historic gas discoveries.

Block Energy has completed its takeover of a 100% working interest in the 37-sq km West Rustavi / block XIf PSC in the Kura Basin. The company is implementing a drilling programme and is testing its historic gas discoveries.

Eneco Energy (formerly Ramba Energy) announced the completion of a previously agreed farm-in deal with Mandala Energy in the Lemang PSC, located in onshore South Sumatra, in July 2019, whereby Mandala acquired an additional 6% participating interest in the block. The deal received approval from SKK Migas on 10 June 2019. Pursuant to this transaction, rightholders in the Lemang PSC are Mandala Energy (90%, operator) and Hexindo Gemilang Jaya (a majority-owned subsidiary of Eneco) (10%). Mandala exercised the option to acquire the additional 6% interest on 1 October 2018. The option was part of the original farm-out deal signed in September 2017, by which Mandala initially acquired a 15% interest from Hexindo. It is understood that Mandala also acquired a 34% interest from previous partner Eastwin Energy in late 2018. Mandala took over operations in the block from Hexindo in May 2017. The block contains the Akatara field, which came onstream in November 2016. As of late 2018, the field was producing over 1,000 bo/d. The operator is planning to conduct further development activities, such as artificial lift, to increase production to 2,000 bo/d. Likewise, negotiations are ongoing to commercialize gas from the field, targeting a supply of 25 MMcfg/d to PT PGN. Background Information The Lemang PSC was officially awarded on 18 January 2007 to PT Hexindo Gelimang Jaya (a majority-owned subsidiary of Ramba Energy) (59%) and PT Indelberg Indonesia (41%). Firm commitments included 500 km 2D seismic acquisition, 500 sq km 3D seismic acquisition and drilling of four wells. The 2D seismic acquisition commitment was fulfilled in early June 2012 with the completion of a 550 km 2D seismic survey. This survey commenced in late September 2011 and was conducted by Quest Geophysical Asia. Ramba Energy completed the acquisition of 41% participating interest in the PSC from Indelberg in November 2010. In late 2011, a new joint operating agreement was reached by which Eastwin Global Investments entered the block with a 49% interest, and the remaining 51% stakes were consolidated into Hexindo. In late April 2014, Ramba Energy announced that it has commenced a process to farm-out its stake in the PSC. In October 2015, Ramba and Mandala Energy signed a farm-out agreement by which Mandala earned a 35% interest in the block for a total investment of up to USD 179.6 million. The deal was completed in February 2016. Along with the farm-out to Mandala, Hexindo acquired a 15% interest from the other PSC partner Eastwin Global Investment such that the net effect of the agreement resulted in Mandala, Hexindo and Eastwin holding 35%, 31% and 34% stake respectively in the block. Akatara field development First oil production from the Akatara field in the Lemang PSC was achieved on 16 November 2016. The milestone was reached following to the issuance of the necessary forestry lease permit by Indonesian Ministry of Forestry and Environment. Initial production was expected to reach 500 bo/d from the Akatara 2 well. The operator plans to increase output with additional production from other existing wells and from new development wells drilled from 2017 onwards. The development plan for the block includes the recompletion of exploration wells Selong 1, Akatara 1 and Akatara 2, followed by eight new development wells and two step-out wells. Production was initially achieved through temporary facilities (Early Production Facilities). In this early stage, oil is transported by truck to the Tempino field and from there is pipelined to the Plaju refinery. In a later phase, the operator plans to install permanent facilities, possibly with a higher production capacity. A new pipeline is also planned to be built, in order to connect the block directly with the Plaju refinery. The block is expected to produce up to 4,000 bo/d during the early production phase. Commercial gas production is expected to commence at a later stage. According to local media, quoting the operator in late February 2017, the block could potentially produce approximately 10,000 bo/d by 2022 if further development activities are conducted.

Indonesia Mandala Energy Ltd, Ramba Energy Ltd Lemang PSC - Additional 6% farm-in by Mandala, completed

On 3 October 2018 Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd had signed a Heads of Agreement with Rathlin Energy (UK) Ltd (wholly owned subsidiary of Connaught Oil and Gas Ltd) on a proposed farm-in for a 16.667% interest each in PEDL 183. On 5 November 2018 in an update from Union Jack Oil, the company confirmed that it has now signed a farm-in agreement for the deal. The licence is located in East Yorkshire and contains the West Newton A-1 gas discovery. There are also plans to drill the West Newton B appraisal well in Q1 2019. The deal is subject to regulatory approval. West Newton B will be located approximately 1.5 km south of the 2013 West Newton well. It is planned to target three potential Permian reservoirs in the Brotheran, Kirkham Abbey and Cadeby formations. The well has a planned TD of 2,000 m to the base of the Permian section. It was initially planned to be drilled with the KCA Deutag T-61 rig. In November 2017 Rathlin confirmed that it still plans to drill the well and in December the company stated that it is currently out to assess and determine rig availability. Drilling is planned to take 6 - 12 weeks where the company is not planning to test any shale horizons (TD likely to be 1,000 m above the Bowland Shale) estimated to be deeper than its Permian targets. It is hoped that the well will determine the commerciality of the discovery. In an update from the company on 17 June 2015 it confirmed that East Riding of Yorkshire Council has granted planning permission for the well. On 26 November 2015 Rathlin announced that it was pleased that the planning committee has unanimously approved the planning application for an extension at West Newton A. Following the well encountering gas the company can move forward with investigating the commerciality of the discovery within the Permian Kirkham Abbey Formation. On 26 July 2016 the OGA confirmed that the Environment Agency has granted a permit for the drilling of the well. In 2013 Rathlin Energy drilled with West Newton 1 (A) well. The well was drilled to a TD of 3,150 m into the Dinantian Carbonate section in the Carboniferous and was tested. The well was located north of West Newton and east of Marton in the parish of Aldbrough, East Riding Yorkshire. It had a primary target based from 2D mapping and is a Permian aged Caedby Carbonate reef. The source rock potential is present within the Permian basinal sediments, the Westphalian coal measures and the Bowland shale sequence. PEDL 183 was awarded in the 13th Onshore Licensing Round and covers an area of 913 sq km. Interest in the licence following the deal will be held by Rathin Energy (66.666% + operator), Humber Oil and Gas (16.667%) and Union Jack Oil Plc (16.667%).

Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd had signed a Heads of Agreement with Rathlin Energy (UK) Ltd (wholly owned subsidiary of Connaught Oil and Gas Ltd) on a proposed farm-in for a 16.667% interest each in PEDL 183

Partner Echo Energy reported on 9 July 2018 it had finished the successful drilling of the fourth back-to-back exploratory well of its campaign on the Santa Cruz I Fraccion D Block, Austral Basin. The Canadon Salto x-2001d reached 1,511 TD recording a column of over 60m of gas and light oil shows in the Upper Tobifera pyroclastic series identified by existing 2D seismic data and interpreted from logging. Over 168,000 ppm and full distribution of C1 to C5 hydrocarbons were encountered with reference to background gas levels less than 2,500 ppm outside the zone of interest. The log evaluation showed 30m of potential net pay over the 1,272-1,304m section. Final production casing is being run before completion and testing, which will be soon conducted using the Quintana 01 rig. The PTD was 1,514m and the drilling rig was the Petreven H-2015. The well targets 19 Bcfg gross best case contingent resources from a recent assessment in addition to further 18.7 Bcfg gross best case for prospective resources as indicated by Echo in a press release. Eduardo Eurnekian's CGC operates and holds 50% interest and Echo 50% interest in this block.

Canadon Salto x-2001d reached 1,511 TD recording a column of over 60m of gas and light oil shows in the Upper Tobifera pyroclastic series identified by existing 2D seismic data and interpreted from logging. CGC operates and holds 50% interest and Echo 50% interest in this block.

KazMunayGaz and Socar signed an MoU on future collaboration in the petroleum industry, involving exploration in the Caspian Sea, a study of geological data, logistics + trading.  The 1st move will be the transfer to Baku and upgrade of KMG’s Satti JU for subsequent use in the Caspan Azeri sector.

Kazakhstan, not found

Mari secured sole rights to the Aqeeq D&PL over the 2017 Aqeeq-1 gas-cond discovery in the Lower Indus Basin. It was excised from Sujawal 2467-11 EL over 4.13 sq km and is retro-effective 11 Sep '17.

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

On 7 December 2017 the US Bureau of Land Management (BLM) announced seven tracts were preliminarily awarded as a result of the NPR-A 2017 oil & gas lease sale to be held in the National Petroleum Reserve-Alaska (NPR-A). ConocoPhillips Alaska and partner Anadarko were the lone bidders in the sale partnering on the seven tracts. The tracts are located in the low potential area south of the company’s current acreage position in the Northeast NPR-A some 38 mi (61 km) from the company’s 2016 Willow oil discovery. ConocoPhillips paid a total of USD 1.16-million on 79,911.29 acres contained in the seven tracts. The per acre bid average for the leases was USD 14.51. ConocoPhillips will operate the leases with a 78% working interest while partner Anadarko will hold the remaining 22% working interest. The lack of interest in the sale was likely due to a majority of the acreage on trend with recent discoveries was not included in the sale, these tracts were removed from future sales by the previous US president in 2013. The current administration will have to review the previous order removing the leases and conduct the necessary environmental reviews before the lands can be included in future sales. A table showing the awarded blocks details has been provided below. NPRA Sale 2017 Preliminary Awards             Operator Name Area Contract Bonus USD Acres Per Ac Bid Sq km Sale Award Date ConocoPhillips Alaska Inc NE NPR-A L-079 $170,242.00 11,347.06 15.00 45.92 NPRA Sale 2017 06-Dec-2017 ConocoPhillips Alaska Inc NE NPR-A L-080 $170,572.00 11,369.30 15.00 46.01 NPRA Sale 2017 06-Dec-2017 ConocoPhillips Alaska Inc NE NPR-A L-081 $170,182.00 11,347.06 15.00 45.92 NPRA Sale 2017 06-Dec-2017 ConocoPhillips Alaska Inc NE NPR-A L-083 $150,494.00 11,347.06 13.26 45.92 NPRA Sale 2017 06-Dec-2017 ConocoPhillips Alaska Inc NE NPR-A L-108 $172,760.00 11,507.68 15.01 46.57 NPRA Sale 2017 06-Dec-2017 ConocoPhillips Alaska Inc NE NPR-A L-110 $152,707.00 11,507.68 13.27 46.57 NPRA Sale 2017 06-Dec-2017 ConocoPhillips Alaska Inc NE NPR-A L-111 $172,400.00 11,485.44 15.01 46.48 NPRA Sale 2017 06-Dec-2017 Totals     $1,159,357.00 79,911.29 $14.51 323.39     Source: IHS Markit               © 2017 IHS Markit   On 26 October 2017 the US Bureau of Land Management (BLM) officially announced details for the NPR-A 2017 oil & gas lease sale to be held in the National Petroleum Reserve-Alaska (NPR-A). The sale covered the largest area available for tracts since leasing resumed in 1999. The sale encompassed 10.3-milllion acres (41,683 sq km) out of the 22.8 million acre (92,268 sq km) NPR-A in 900 total tracts. Sealed bids had to be received by 4 p.m. local time on 4 December 2017, at the BLM-Alaska State Office.  The BLM opened sealed bids submitted on the tracts offered at 1 p.m. local time on 6 December 2017. The opening of the bids was livestreamed at www.blm.gov/live. The bidding method was a cash bonus bid for each block. The sale includeed acreage not previously available before in the western part of the NPR-A, however the majority of open blocks in the northeastern planning area will not be included as well a good deal of the tracts in the eastern and northern part of the northwestern planning area.  Unfortunately the onshore area excluded in the northern part of the Northwestern planning area is immediately south of the Caelus 2016 oil discovery just offshore in Alaskan state waters. The BLM invited nominations and comments on tracts that might be made available in the sale during the summer to gauge industry interest and give conservation groups and other stakeholders an opportunity to provide input to the scope of the sale. Tracts selected for inclusion in the sale was “based on evaluation of comments received, natural resource information, resource potential, industry interest and subsistence values,” BLM said.  

ConocoPhillips (partner Anadarko) ended high bidder for 7 parcels (79 911acres) under the NPR-A 2017 lease sale.B.)) Northwestern

On 1 December 2017, Shell Offshore was formally awarded four blocks in the Garden Banks Protraction Area: GB 719 (lease G36151), GB 720 (G36152), GB 763 (G36153) and GB 807 (G36154), situated in the East Texas Coastal Basin. All four blocks were originally offered as part of Western Gulf of Mexico Lease Sale 249, which was held on 16 August 2017. The leases expected to expire on 30 September 2024. Following formal award, Shell Offshore is now the operator and sole interest-holder (100% WI + Op) in all four Garden Banks blocks.

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In late October 2019, operator Kosmos Energy Ltd (Kosmos) has hit a 39-m net oil pay in its S-5 exploration well in Block S, offshore Rio Muni Basin. The well (AKA G-13 ILX for Infrastructure-Led Exploration), was spudded on 20 September with the “Maersk Voyager” drillship and drilled to a total depth of 4,400 m, before the rig was demobilized around 13 November. The company explained that oil was encountered in good-quality Santonian reservoir (Upper Cretaceous). With this success, Kosmos sees a potential for an accelerated development through the existing nearby infrastructures (Ceiba and Okume Complexes). First oil for G-13 is therefore expected around 2021. S-5 is considered as an appraisal well by IHS Markit, as it is located in the center of G-13 oil discovery made in 2002 by Triton Energy. It targeted the G-13 main reservoir fairway (prospecting resources estimated at 50 MMboe). Kosmos mobilized the “Maersk Voyager” drillship on 18 September. This well is part of a five-well programme for Kosmos, including one basin-opener in Mauritania, and three exploration wells in the Gulf of Mexico, all to be drilled in 2019. Of note, Kosmos is believed to have a good understanding of the regional geology of Rio Muni Basin, as Kosmos was formed in 2003 from Triton people, who discovered Ceiba in 1999. As of February 2019, Kosmos Energy was estimating the G-13 oil discovery recoverable reserves around 56 MMboe. Three outposts were drilled after the discovery (two in 2003 and one in 2014), but the development of the field was never made possible because of the failure to clearly identify the Senonian main fairway. Recent new seismic material apparently helped the company to image it.

Kosmos Energy Ltd found Cretaceous oil in S-5 (G-13 ILX) explo well, in Block S

ATP 1189-P (Innamincka), Cooper-Eromanga Basin, P&A gas shows at TD 2,764m on 3 Feb '20.

Durham Downs W.-1 expl. in TP 1189-P (Innamincka), P&A gas shows at TD=2764m.