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As initially reported by IHS Markit, POSCO International in late April 2020 confirmed the completion of its three-well exploration drilling campaign in Block A-3, offshore Rakhine Basin. The final well, Yan Aung Myin 1, is believed to be unsuccessful, as the company reported one discovery in the campaign from the previous wildcat Mahar 1. Yan Aung Myin 1 was drilled at a water depth of approximately 900 m, targeting Pliocene turbidite sandstones. As of late March 2020, drilled depth for Yan Aung Myin 1 was over 2,600 m. The well was likely spudded in mid-March 2020. The "Maersk Viking" D/S was released in mid-April 2020 after completing the three-well programme that included wildcats Kissapanadi 1 and Mahar 1 prior to Yan Aung Myin 1. The drilling contract was valued at approximately USD 33 million, including mobilization fee. IHS Markit understands that a contract option for a fourth well was not exercised. The Yan Aung Myin ("Victory" in Myanmar language) prospect is located 24 km southeast of the Mahar ("Greatness") prospect that was successfully drilled in February 2020. Mahar 1 was initially announced by POSCO as a gas discovery on 17 February 2020. The well flowed 38 MMcfg/d upon testing, with a gross gas column of 18 m. Initial estimates by the company indicate contingent gas resources of approximately 660 Bcf from the discovery. Mahar 1 was drilled in approximately 1,100 m of water. The first well in the campaign, Kissapanadi 1, was drilled in December 2019 and has been plugged and abandoned, with results still under evaluation as of early 2020. The operator is planning to drill two to three appraisal wells in 2021 to confirm the commercial status of the Mahar discovery. Despite the deepwater location, the newly discovered resources could be developed with a reduced investment via facility sharing with POSCO's Shwe Gas project straddling Block A-1 and Block A-3. The Shwe project produced approximately 550 MMcf/d of dry gas in March 2020. About 70% of the produced gas is exported to China, while the rest is allocated to the domestic market. Blocks A-1 and A-3 are operated by POSCO International with 51% interest alongside partners ONGC Videsh (17%), MOGE (15%), Gail (India) (8.5)% and Kogas (8.5%). Background Information The 6,779 sq km block was awarded to Daewoo (100%) in February 2004. OVL and Daewoo had applied separately for the block, both seeking a 100% equity. Block A-3 lies adjacent and south of Block A-1, where operator Daewoo made a gas discovery with the sidetrack of its first wildcat Shwe 1, marking the first discovery in Myanmar waters in the Rakhine Basin. The well, drilled from November 2003 to January 2004, flowed 32 MMcfg/d from Lower Pliocene basin floor fan sandstones upon testing. On 1 November 2004 Daewoo entered into the exploration phase of the block by paying an agreed signature bonus of US$ 2.5 million. Subsequently, during February-April 2005, the company acquired 7,797 line km of 2D seismic over the block at an estimated cost of US$ 2.2 million. Interpretation of the new seismic data has led to the identification of undisclosed number of prospects including Mya (Emerald). On 3 October 2005, Daewoo finalised a deal with ONGC Videsh Ltd (OVL), Gas Authority of India Ltd (GAIL) and Korea Gas Corporation (Kogas) to acquire stakes of 20%, 10% and 10%, respectively in Block A-3. The two Indian state firms, OVL and GAIL, paid premiums of US$ 2.88 million and US$ 1.44 million, respectively. It followed a Memorandum of Understanding (MOU) signed on 5 October 2004 to finalise the farm-in agreement, where a combined 30% equity was offered to the two Indian firms against their request for 50% equity. Daewoo drilled four exploration wildcats in the block and discovered the Mya field in 2005. In 2007, two appraisal wells were drilled, Mya 2 and Mya 3, and successfully appraised gas. Three wildcats, Mya West 1, Kyauk-Seine 1 and Thandar 1, were drilled between 2007 and 2008 but did not have favorable results. In January 2008, the operator completed a 1,006 sq km 3D seismic survey using CGGVeritas’s “CGG Harmatan” survey vessel.

Myanmar (Rakhine B.) Mya

Pilot Energy Ltd announced on 27 July 2018 that it had reached a binding agreement to assign its interest to exploration permit WA-503-P, located in the Barrow Sub-basin, North Carnarvon Basin, to joint venture partner Black Swan Resources Pty Ltd.  Pilot Energy currently holds 80% and operatorship, but will assign all interest and exit the permit upon completion of the deal. Under the terms of the transaction, Pilot will take a share of the any net profit interest that arises from the permit in the future, and Black Swan will take over operatorship and responsibility for all costs and management associated with future activities in the permit. In the current phase of work commitments, which have been suspended and extended for 24 months, 80 sq km of new 3D seismic acquisition is required, as well as post-seismic interpretation and analysis.  The first well is required between May 2021 and May 2022, but remains contingent at this stage. WA-503-P was awarded to Neon Energy on 13 May 2014.  Pilot Energy, which was previously Rampart Energy, entered the permit – acquiring 80% interest – in March 2015.  Subsequently, Black Swan Resources acquired Neon Energy’s remaining 20% interest in June 2015, as Neon exited the permit. Pilot Energy had been looking to farm-out its interest in the permit. Pilot reported it was looking for a partner to acquire around 20% interest in the permit in return for assistance in funding 80 sq km 3D seismic acquisition over the block. Pilot has reported that low acquisition costs have been contracted for the seismic programme.  However Pilot will exit the block upon completion of the deal, reporting that it is looking to reduce cost and focus on its core assets where it sees greater potential under its strategy. WA-503-P, which covers an area of 81 sq km, was awarded on 14 May 2014.  Once Pilot’s exit from the permit is complete, Black Swan Resources Ltd will hold 100% interest and operatorship.

Pilot Energy Ltd announced on 27 July 2018 that it had reached a binding agreement to assign its interest to exploration permit WA-503-P, located in the Barrow Sub-basin, North Carnarvon Basin, to joint venture partner Black Swan Resources Pty Ltd. Pilot Energy currently holds 80% and operatorship, but will assign all interest and exit the permit upon completion of the deal.

On 6 November 2018 OMV announced that it is selling its 100% owned subsidiary OMV Tunisia Upstream GmbH to a subsidiary of Panoro Energy ASA. OMV Tunisia Upstream holds a 49% interest in five production concessions: Cercina, Cercina South, Gremda/El Ain, El Hajeb/Guebiba and Rhemoura. The concessions are located onshore and shallow offshore Gulf of Gabes in the Pelagian Basin. The company also holds a 50% interest in Thyna Petroleum Services SA. operating company. The sales agreement will be signed following the completion of an equity private placement by Panoro. The agreed purchase price is USD 65 million and the closing date of the transaction is 1 January 2018. The production of the divested assets in 2017 was around 2,000 b/d of oil net to OMV. Partner in the production concessions will continue to be ETAP with 51%. The OMV assets acquisition complements the recent acquisition by Panoro of the Sfax Offshore permit from DNO. The resource potential of the Sfax Offshore permit will benefit from the production infrastructure established on the OMV acreage. This appears in the drilling plans recently announced by Panoro. The Salloum West 1 appraisal well targets resources in the Sfax Offshore permit which will be developed using OMV’s infrastructure nearby.

Panoro will acquire 49% interests in the Cercina/Cercina Sud, El Ain/Gremda, El Hajeb/Guebiba and Rhemoura concessions from OMV for US$65 MM. The remaining stakes in the concessions continue to be held by Etap.

Pilot Energy Ltd reported on 21 February 2018 that it had reached a binding agreement with Black Swan Resources Pty Ltd to sell its 80% beneficial interest in exploration permit WA-507-P, located in the North Carnarvon Basin.  Under the terms of the agreement, joint venture partner Black Swan Resources will increase its holding to 100%, with pilot to receive a 7.5% share, paid quarterly, of any net profit interest from the permit.  Black Swan Resources will take over all costs for operations and management of the permit. Pilot reports that after the transfer of interest is complete, it will retain an 80% legal holding on the permit title, though Black Swan Resources will hold sole beneficial interest and operatorship. WA-507-P was awarded on 17 November 2014 to NWS O&G Pty Ltd (80% and operator) and Black Swan Resources (20%). It had been offered as block W13-7 in the 2013 Federal Offshore Acreage Release. Pilot Energy (previously named Rampart Energy) acquired NWS O&G’s interest in February 2015.  No drilling has yet taken place within the permit, with the first well scheduled under the work commitments between November 2019 and November 2020. Pilot Energy Ltd and Black Swan Resources reported that they were jointly looking to sell full interest in the permit, with Black Swan Resources managing the sale process. It is thought this could still be ongoing once Black Swan Resources takes full ownership. WA-507-P covers an area of 1,616 sq km.  Once the sale process is complete Black Swan Resources Pty Ltd will hold 100% interest and operatorship of the permit.

Black Swan Resources (->100%) has acquired 80% interest in WA-507-P from Pilot Energy.

Metgasco Pty Ltd, Vintage Energy Pty Ltd and Bridgeport Energy Ltd reported on 24 February 2020, that they have executed the farm-in agreement, to enter PRL 211, located in the Cooper-Eromanga Basin. Under the terms of the farm-in, which was entered into in November 2019, the companies will be acquiring interest from current operator of PRL 211, Senex Energy Ltd. A number of conditions are required to be satisfied, including executing a formal farm-in agreement. Other conditions include Ministerial approvals and a demonstration of sufficient funds being available to drill a well. The remaining conditions are expected to be completed by 31 March 2020. Under the terms of the farm-in agreement, it's proposed that Vintage will acquire operatorship of the licence with 42.5% interest, with the remaining interest split between Bridgeport (21.25%), Metgasco (21.25%) and current holder Senex (15%). Senex will be free carried for the first well, as part of the farm-in terms. The joint venture partnership of Metgasco, Vintage Energy, Bridgeport Energy and Senex Energy already has ownership of adjacent exploration licence ATP 2021-P, which is on the Queensland side of the basin (subject to relevant authority approvals and registration of the interests). PRL 211, located in South Australia, is currently 100% owned by Senex's subsidiary Stuart Petroleum Pty Ltd. Entry into the retention lease provides the joint venture with complete access to the Odin Prospect which straddles both ATP 2021-P and PRL 211. With the Odin structure being the main target, the terms extend to specifically drilling the prospect, for which, Vintage will be liable for 50% of the costs to acquire its 42.5% equity. The remaining costs will be split evenly between Bridgeport and Metgasco. The well is planned to be drilled in Q4 2020. It is expected that the initial well costs will be around AUD 4 million. Subsequent well testing costs will reflect the equity share in the licence once the farm-in deal is completed. The Vali Prospect, located solely in ATP 2021-P, was drilled in December 2019/January 2020 and was, prior to drilling, reported to provide significant de-risking of the Odin Prospect. The Vali 1 exploration well encountered 35 m net gas pay in the primary Patchawarra Formation, plus additional gas recovery and oil shows the deeper Triassic and Jurassic secondary targets. Vintage reported that the results are on the high side of pre-drill estimates. Oil shows in the Jurassic Westbourne and Birkhead formations were also reported by Vintage. As of 16 January 2020, Vintage plans to case and suspend the well for potential stimulation, which could increase permeability in the Patchawarra sandstones, flow testing and future production. PRL 211 was awarded over exploration licence PEL 637 (replacement of PEL 516, 2010), which was awarded in 2014 to Stuart Petroleum. Origin entered in 2015 forming the subsequent partnership for PRL 211, which was awarded on 25 October 2017. PRL 211 now covers nearly 100 sq km. The joint venture partnership ended on 26 June 2018 with Stuart acquiring Origin's 40% interest. The Odin Prospect comprises an anticlinal structure on the eastern boundary of the permit 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 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 gross P50 recoverable resources of 12.6 Bcf, a 3.9 Bcf upgrade from estimates released in 2018.

Vintage will acquire operatorship of the PRL 211 licence with 42,5% interest, with the remaining interest split between Bridgeport (21,25%), Metgasco (21,25%) and current holder Senex (->15%).

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

United Kingdom, P255

Petrosynergy is assumed to have plugged and abandoned dry the 1-PSY-20D-BA (1-PSY-20D-BA) directional new-field wildcat (NFW) in the REC-T-141 block in the onshore Reconcavo Basin on 25 November 2019 after reaching a final total depth (TD) of 2,041 m. The ANP has reported no show reports filed for the well through early-December 2019. The NFW was spudded on 21 October 2019. The NFW had a proposed total depth (PTD) of 2,041 m and was targeting the Early Cretaceous Agua Grande Formation. The prospect is located approximately 1.2 km north-east of the Petrosynergy operated Canario Field and its 1-MPE-005DP-BA oil and gas discovery well. On 12 July 2017, the ANP granted Petrosynergy a contract extension for its REC-T-141 contract in the onshore Reconcavo Basin due to delays with access to a seismic survey. The ANP granted a 10-month extension to the first period exploration expiry from 23 December 2018 to 23 October 2019 and the final expiry from 23 December 2020 to 23 October 2021. The ANP granted a final award for the ANP Round 13 REC-T-141 block to Petrosynergy 100% on 23 December 2015.

Brazil (Central Reconcavo Sub-basin (Reconcavo B.)) Agua Grande

Jiatan 1 flow tested approximately 11.48 MMcfg/d through an 8mm choke after fracture stimulation between 4,360-4,396m from the Middle Member 3 of Shahejie Formation volcanic basalt on 7 May 2020. The success of Jiatan 1 has boosted the volcanic reservoir hydrocarbon potential in the Eastern Sag of the Liaohe Sub-basin. Jiatan 1 was drilled in the 2H of 2019 to a TD of 4,428m MD (PTD of 4,800m). The objective of Jiatan 1 was to explore the oil and gas potential of the volcanic reservoir of the Middle Member 3 of Shahejie Formation within the Taoyuan Structure, Liaohe Sub-basin. Jiantan 1 is in the PetroChina operated Liaohe Basin Eastern Block in the onshore Bohai Gulf Basin and is geographically located within Liaoning Province, Panjin City, Dawa District Xiongjiabao Village.

China (Bohai Gulf B.) Jiatan (Bo) 1 op. by PETROCHINA (100%) in Eastern Liaohe Sag block, TD = 4428 m, flow tested approximately 11.48 MMcfg/d through an 8mm choke after fracture stimulation between 4,360-4,396m from the Middle Member 3 of Shahejie Formation volcanic basalt

The ANH reports that the next set of blocks on offer under the Permanent Process of Assignment of Areas (PPAA) will be announced on 23 Sep ’19. Of note, the ANH has reduced the number of bidding cycles per year from 3 to 2. The first one concluded in June (official awards signatures imminent) and this will be the final round for 2019.

The ANH reports that the next set of blocks on offer under the Permanent Process of Assignment of Areas (PPAA) will be announced on 23 Sep ’19. Of note, the ANH has reduced the number of bidding cycles per year from 3 to 2. The first one concluded in June (official awards signatures imminent) and this will be the final round for 2019.

Frontera Energy reported that the Galope-1 appraisal well on the CPE-6 Block (Llanos Basin), reached a final TD of 2,476m on 1 November 2019 and encountered 3.2m of net pay in the C7B member of the Carbonera Formation. Petrophysical analysis of logging whilst drilling data indicates a sandstone reservoir with 33% porosity, permeability of 2.6 darcys, water saturation of 36% and clay content of 1.5%. The well will now be completed and tested using an ESP in Q4 2019. The appraisal well was spudded with the "Pioneer 51" land rig in early October 2019 and had an original PTD of about 3,048m. A second appraisal well, Contrapunteo-1, has now been spudded following the completion of drilling operations at Galope-1.Earlier in the year, in May and July 2019, Frontera Energy was successful on the CPE-6 Block with both its Amanecer-1 and Coplero-1 wells. Galope-1 is the first appraisal well to further delineate the Coplero-1 discovery. Coplero-1 was spudded in July 2019 and encountered 2.4m of net oil pay in the Paleogene Carbonera Formation, C7 Member. Petrophysical logs showed a clean sand system with 32% porosity, 2.3 Darcy permeability, 40% water saturation and 1.6% clay content. The well was completed with an electrical submersible pump and is currently producing 132 bo/d of 11deg API oil with an 85% water cut. Galope-1 is located less than 0.5km to the north of Coplero-1. Frontera Energy holds the heavy oil CPE-6 Block through subsidiary Meta Petroleum. The Hamaca Field on the block was discovered in 1989 and brought into production in late 2013.

Galope-1 appraisal well on the CPE-6 Block (Llanos Basin), reached a final TD of 2,476m and encountered 3.2m of net pay in the C7B member of the Carbonera Formation. Petrophysical analysis of logging whilst drilling data indicates a sandstone reservoir with 33% porosity, permeability of 2.6 darcys, water saturation of 36% and clay content of 1.5%.

On 23 August 2019, Lekoil (Nigeria) Ltd (Lekoil) reported that it agreed to acquire 45% working interest in Newcross Petroleum Ltd’s OPL 276, a coastal permit located in the eastern Niger Delta, south of Calabar city. Upon governmental approval, Lekoil through its wholly owned subsidiary Lekoil 276 Ltd, will buy half of current operator’s stakes, for a total staged consideration of USD 5 Million, payable in three steps explained in detail in the company statement. The resulting new ownership for OPL 276 will be Newcross Petroleum, with 45% operated interest, Lekoil 276 with 45% WI and Albright Waves Petroleum Development Ltd holding the remaining 10% WI. Lekoil stated that with this deal, it “sees a clear opportunity for re-entering one or more of these discovery wells, with the potential for rapid monetization of resources due to existing export facilities nearby”. OPL 276 was awarded in February 2006 to Centrica plc while Newcross Petroleum took over operatorship four years later in 2010. The coastal permit (c.a. 500 sq km) is the host of four gas and oil discoveries, made between 1972 and 1990, by previous operator in the area, Royal Dutch Shell plc. Recoverable reserves to date are estimated around 600 Bcf of gas. However, Lekoil intends to commission an independent Competent Persons Report (CPR) in due course. Before that deal, Lekoil (Nigeria) Ltd was partner in Green Energy’s producing marginal field Otakikpo (5,300 bo/d in 2018), partner in Optimum Petroleum’s OPL 310 appraisal block (Ogo oil discovery), and co-operator in Ash-Bert’s OPL 325 exploration permit.

Lekoil reported that it agreed to acquire 45% working interest in Newcross Petroleum’s OPL 276, a coastal permit located south of Calabar city.

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, for Vintage to acquire 50% interest in ATP 2021-P. The agreement is subject to several approvals and completion of a farm-in agreement (expected around 30 June 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

Vintage will earn a 50% operated interest in the ATP 2021 permit from Metagasco (->50%) by funding 65% of the first exploration well, up to a maximum gross cost of US$3,6 MM.

Horiz shale gas well in Dingshan – Dongxi block, Qijiang District, Sichuan Basin, TMD 6,062m (4,248m TVD), reportedly tested 313,000 cum/d from 4,270m after fracking, the 1st high-yield flow achieved from below 4,200m in China. Target Wufeng + Longmaxi fm’s.

Dongye Shen 1 (Sinopec – Xinan 100%) is a horizontal nfw, targeting the Upper Ordovician Wufeng – Lower Silurian Longmaxi shale formations at burial depth of over 4,000 m, tested a high-yield gas flow of 313 Mcm/d from deep-buried depth 4270 m after fracking, this is the first well with high-yield gas flow achieved in a burial depth over 4200 m in China, it is also a breakthrough in the fracturing technology for the deep-buried depth over 4000 m shale gas well.

MOL and AziNor Catalyst are offering the opportunity for interested parties to farm-in to licence P2179 (block 21/25c) to drill a well on the Hinson oil prospect. The prospect is a large stratigraphic trap with a pinch-out of reservoir sands to the north. The primary reservoir target is the Upper Jurassic basin floor mass-flow sands of the Kimmeridge Clay Formation, sourced from the northern and western platform areas. AziNor and MOL are prepared to jointly farm down between 10% and 60% in exchange for the funding of a well, on a promoted basis, to test the Hinson prospect. Pmean gross recoverable resources have been estimated at 178 MMboe with an upside of 329 MMboe (P10). There are plans to drill an exploration well in 2019. As of August 2018 the opportunity was still available. The prospect, located in the Central North Sea near existing infrastructure as that of the Gannet complex, is covered by 2009 3D Geostreamer seismic data. Analysis of 3D Geostreamer data indicates the presence of a direct hydrocarbon indicator (DHI) associated with the prospect. This is supported by offset well modelling work and is the focus of the seismic reprocessing and quantitive interpretation. Mulitple proven play types exist in the area with a variety of trap styles. The main focus within the aforementioned farm-out block are the Upper Jurassic deepwater turbidite and shallow marine shoreface systems. The reservoir sands are located within or extremely near to the oil mature, organic rich Kimmeridge Clay Formation source rocks. These plays are proven in nearby discoveries such as 22/22b-2 Selkirk which flowed, at discovery, 4,864 boe/d from high quality (600 mD permeability) Upper Jurassic Kimmeridge Clay Formation sands. Interest in P2179 is held by Molgrowest (I) Ltd (51% + operator) and AziNor Catalyst Limited (49%). For further information please contact: Nick Terrell +44 (0)20 3588 0065 [email protected] or Richard Fairbairn from MOL.

MOL and AziNor Catalyst are offering the opportunity for interested parties to farm-in to licence P2179 (block 21/25c) to drill a well on the Hinson oil prospect.

PEMEX plugged and abandoned dry the Teca 1DEL outpost in the AE-0009 block in the Sureste Basin on 7 September 2018.  The well reached a final total depth (TD) of 3,730 m and testing indicated salt water.  The outpost was spudded on 14 July 2018. The outpost had a proposed total depth (PTD) of 3,710 m and the primary target was the Upper Miocene Formation. It is located approximately 3.1 km east south-east of the Teca 1 discovery well in a water depth of 43 m. This was the first outpost of the June 2016 Teca 1 oil and gas discovery. The drilling cost estimate was reported to be USD 17.51 million at an exchange rate of 1USD = 18.5 MXN and the completion cost was USD 7.95 million. The Teca 1DEL had an estimated 73 MMboe reserves to incorporate into the field area. PEMEX suspended as an oil and gas discovery the Teca 1 new-field wildcat (NFW) in the AE-0009 block in the Sureste Basin on 3 June 2016.  The operator published information on 28 July 2016 with its 2nd quarter results that the NFW was a discovery.  The operator reported that the well tested 3,186 bo/d and 7.3 MMcfg/d from the Upper Miocene Formation and it estimates 3P reserves of 50-60 MMboe.  The CNH reported that the zone was perforated from 3,162 m to 3,170 m.  The NFW reached a final total depth (TD) of 3,569 m. The NFW was spudded on 11 March 2016.  The well had a proposed total depth (PTD) of 3,730 m.  The middle Pliocene formation was the primary objective and the Miocene Formation was a secondary objective. The “Fortius” J/U drilled the well in a water depth of 44 m.  The well is located in the northeastern area of the block. The nearest well is the Marbella 1 located in the same block about 8.9 km southwest. The trap is reported to be an east west trending salt induced anticlinal nose. The prospect size is reported to be 64 MMboe. The water depth is 44 m.  On 26 November 2015, the CNH approved plans by PEMEX to drill the Teca 1. SENER awarded the AE-0009-2M-Tucoo-Xaxamani-01 entitlement to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 977.8 sq km.

Mexico (Salina Sub-basin (Sureste B.)) Teca 1

In October 2019, a PSC was formally gazetted awarding the Egyptian National Petroleum for Exploration & Development Company (ENPEDCO) the concession for the 1,038 sq km South East Abu Sennan (SEAS) block. The concession agreement was signed on 5 September 2019, following the Energy & Environment Committee and House of Representatives (HoR) approval on 11 June 2019. The out-of-round award had been provisionally agreed in Q4 2018. The PSC is for a maximum eight-year term (5+3) with commitments in the first period of one exploration well, reprocessing of 2D and 3D seismic and a US$ 1 million minimum investment. In the second exploration period, commitments include additional studies, one exploration well and an additional US$ 1 million minimum investment. A US$ 1 million bank guarantee has also been lodged. The under-explored SEAS block lies in the southern part of the Abu Gharadig Basin. It comprises of acreage formerly held by Tharwa Petroleum under the East Abu Sennan PSC and encloses development leases (DL) which form part of the El Diyur concession, operated by El Diyur Petroleum. The concession area has seen just three wells drilled, with the last by Enap in 2003 (Baraka 1, TD 2,096m, P&A dry). ENPEDCO was only formed in 2017 and is 70% owned by the National Service Projects Organization, the investment arm of the Egyptian military. EGPC hold a 20% stake, with state E&P company General Petroleum Co (GPC) holding the remaining 10%. The company has been granted six concessions in out-of-round awards. ENPEDCO operates the concession with 100% equity.

Egypt, Abu Sennan

On 29 January 2019, the Federal Agency for Subsoil Use held an auction for eight blocks in Bashkortostan Republic (Volga-Ural Province). Nine companies submitted bids and Bashneft, Lukoil-Perm, UDS Neft and Sabunskiy (Udmurtia) emerged as the winners. The companies will obtain 25-year E&P licenses.   The Amzyanskiy block covers 76 sq km and encompasses four prospects with combined oil resources estimated at 7 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 9 MMbbl of oil and 27 Bcf of gas. The starting price amounted to RUB 17.05 million (USD 0.26 million). UDS Neft offered RUB 18.755 million (USD 0.28 million). The Baykinskiy block covers 348 sq km and encompasses six prospects with combined oil resources estimated at 8 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 26 MMbbl of oil and 52 Bcf of gas. The starting price amounted to RUB 19.81 million (USD 0.3 million). Bashneft offered RUB 21.791 million (USD 0.33 million). The Verkhne-Yarkeyevskiy block covers 349 sq km and encompasses nine prospects with combined oil resources estimated at 12 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 10 MMbbl of oil and 17 Bcf of gas. The starting price amounted to RUB 24.95 million (USD 0.38 million). Bashneft offered RUB 39.92 million (USD 0.6 million). The Toshkurovskiy block covers 244 sq km and encompasses three prospects with combined oil resources estimated at 7 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 5 MMbbl of oil and 2 Bcf of gas. The starting price amounted to RUB 13.5 million (USD 0.2 million). Lukoil-Perm offered RUB 14.85 million (USD 0.23 million). The Turtykskiy block covers 358 sq km and encompasses eight prospects with combined oil resources estimated at 9 MMbbl and seven oil fields excluded from the offer. Hydrocarbon resources (category D1) of the block are estimated at 8 MMbbl of oil and 1 Bcf of gas. The starting price amounted to RUB 22.47 million (USD 0.34 million). Bashneft offered RUB 296.604 million (USD 4.5 million). The Kushkulskiy Severnyy block covers 424 sq km and encompasses six prospects with combined oil resources estimated at 7 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 1 MMbbl of oil and 2 Bcf of gas. The starting price amounted to RUB 14.52 million (USD 0.22 million). Sabunskiy offered RUB 15.972 million (USD 0.24 million). The Burayevskiy Zapadnyy block covers 451 sq km and encompasses eleven prospects with combined oil resources estimated at 20 MMbbl and several oil fields excluded from the offer. Hydrocarbon resources (category D1) of the block are estimated at 23 MMbbl of oil and 10 Bcf of gas. The starting price amounted to RUB 51.06 million (USD 0.77 million). Bashneft offered RUB 66.378 million (USD 1 million). The Shakhtauskiy block covers 67 sq km and encompasses the Novo-Berezovskaya prospect with oil resources estimated at 2 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 1 MMbbl of oil and 34 Bcf of gas. The starting price amounted to RUB 3.5 million (USD 0.05 million). Bashneft offered RUB 3.851 million (USD 0.06 million).

Russia, not found

Statoil has commenced the relinquishment process for Block AD-10, located in Bengal Deep Sea Fan in late November 2017, at the end of the first study period of 2 and a half years. Statoil is operator and sole interest holder of the block, which was officially awarded in April 2015. Contract commitments for the first study period included environmental and social impact studies, and the acquisition of new 2D seismic data. After the fulfilment of commitments, the operator had the option to decide whether to continue with a three-year exploration period, or to exit the block. The 2D seismic commitment for the block was fulfilled with a survey conducted between June and July 2016, using the “Polarcus Amani” MV. The acquisition covered approximately 4,800 km. Later in January-February 2017, Statoil acquired a new 3D seismic survey covering approximately 2,500 sq km, in conjunction with Shell. The survey covered the southern part of Shell’s Block AD-11 and the southwest part of Statoil’s AD-10. This survey was also carried out by the “Polarcus Amani”. Prospective target in the block are Pliocene turbidite plays.

Myanmar, Block AD-10

SE part of AE-0013-M-Pilar de Akal-Kayab-04 block, offshore Sureste Basin, WD 29m, P&A dry at TD 5,321m on 4 Feb ‘18, Cantarell-II JU.  Target Oxfordian sst.

Jalachil 1EXP op. by Pemex (100%) in SE part of AE-0013-M-Pilar de Akal-Kayab-04 block, WD 29m, P&A, dry. PTD=5400m, target Oxfordian sst.

Operations were concluded at the Rubin 1 NFW on 5 January 2018, with the Noble "Globetrotter II" drillship en route to port at Varna. Operator Total reported it was spudded in the 1-21 Han Asparuh licence on 23 September 2017, scheduled to take at least three months. It was drilled in 1,300 to 1,600m WD in the western Black Sea from a well location 14km NE of the successful Polshkov 1 NFW, which was concluded on 5 September 2016 having identified a play opening oil discovery in the Oligocene. Polshkov 1 is located in 1,924m WD, and was the first truly deepwater exploration well drilled offshore Bulgaria. It is understood to have reached TD below 5,500m, short of the 7,000m original PTD, although a shallower depth was expected. The Polshkov Ridge was identified as having high exploration potential with a number of syn-rift and post-rift Cenozoic play types identified overlying Mesozoic carbonate fault blocks. The 1-21 Han Asparuh licence covers 14,220 sq km and was awarded to an OMV-led consortium in August 2012, with 7,740 sq km of 3D and 3,000km of 2D acquired during 2013. Total took over operatorship on 1 April 2014 ahead of the drilling programme. On 12 April 2017 the Bulgarian Government extended the licence by 135 days. The acreage was previously held under the Varna Deep licence awarded to OMV in 2002 when reprocessing of vintage seismic and acquisition of new 2D and 3D surveys was undertaken before the licence was finally relinquished in 2008. Han Asparuh is operated by Total with 40% equity in partnership with OMV (30%) and Repsol (30%) and is valid until January 2018.

Rubin 1 NFW in the 1-21 Han Asparuh licence P&A results n/a

It was reported by Pakistan Petroleum Ltd (PPL) on 7 May 2019 that gas has been discovered in Unarpur 1 (also called Unarpur 1 ST1) new field wildcat (NFW) well within the Kotri North 2568-21 EL (Kirthar Fold Belt) onshore concession. PPL holds participating interest in the block which is operated by United Energy Pakistan Ltd (UEPL). During testing, the well is reported to have flowed 18.5 MMcfg/d through 44/64” choke at a well head flowing pressure of 1,916 psi between 3,833.6 m to 3,853.7 m (12,578 to 12, 644 ft) perforated interval within the Cretaceous Lower Basal Sand unit of Lower Goru Formation. It also flowed 54 bw/d during testing. Unarpur 1 was drilled to a TD of 3,938 m and testing was carried out from early February to late March 2019 after setting a 7” liner. The well was spudded on 2 November 2018 using the ‘HL-5’ land rig with a prognosed TD of 4,358 m in the Cretaceous and it was targeting the Lower Basal Sand unit of Lower Goru Formation. A sidetrack was initiated in mid-November 2018 after drilling to 3,191 m depth and the well had reached 3,846 m depth by the end of December 2018. Kotri North EL, which covers an area of 2,472 sq km, is located in the Sindh province and current equity split is as follows: UEPL (60%, operator) and Pakistan Petroleum Ltd (PPL) (40%). UEPL had earlier drilled Aliabad 1 exploratory well in the block which was suspended in February 2018 after conducting testing. The well was spudded on 29 November 2017 and it reached the TD of 4,340 m in mid-January 2018.   Background Information The Kotri North EL block was exclusively awarded to PPL on 29 April 2010. PPL subsequently assigned 10% working interest in the block to Asia Resource Oil Ltd with effect from 27 May 2011. PPL acquired 569 line km of 2D seismic over the acreage during September 2010-January 2011 using the BGP '2273' land crew. The company subsequently acquired an additional 44 line km of 2D seismic during March 2012, using the BGP ‘9501-E’ seismic crew. In April 2015, PPL abandoned the Kotri North X-1 new field wildcat well following testing, having reached TD at 3,650.7 m by the end of March 2015. The well failed to find hydrocarbons. PPL was granted a ten-month extension to the third year of Phase I of the Kotri North EL from 29 June 2015 till 28 April 2016. The company acquired 475 sq km 3D seismic over the block during April-November 2016 using the ‘BGP 9501-A’ seismic crew. It was reported in June 2017 that PPL was granted a two-month extension to the third year of Phase-I of the Kotri North EL from 29 April 2016 to 28 June 2016. The licence has subsequently been granted renewal as well and it entered into two-year Phase-II of initial term with effect from 29 June 2016. PPL assigned 50% of its working interest along with operatorship in the block to UEPL with effect from 2 August 2017. As a result of this transaction the revised equity split in the block was as follows: UEPL (50%, operator), PPL (40%) and Asia Resource Oil Ltd (AROL) (10%). UEPL subsequently acquired AROL’s full 10% interest in the block in 4Q 2017.

Unarpur 1 nfw (UE op, PPL %) in Kotri North 2568-21 EL block, gas disc, during testing, the well is reported to have flowed 18,5 MMcfg/d [44/64” choke] perforated interval within the Cretaceous Lower Basal Sand unit of Lower Goru Formation. It also flowed 54 bw/d during testing. It was drilled to a TD=3 938 m.

L20, Canning Basin, separate structure midway between Ungani + Ungani Far West fields, TD 2,322m, oil shows encountered earlier ended non-commercial although reservoir apparently excellent. Suspended as a potential water injector, DDGT-1 rig. Buru (op), partner Roc.

Ungani West 1 (Buru Energy 50% op. Roc Oil 50%) in L 20 block, a full log suite over the interval indicated several zones of good to excellent porosity with interpreted moderate oil saturations, however a detailed wireline pressure survey indicated there was no commercially producible oil column in the well.

Oxy was reportedly assigned E+P rights to 2016-round Hafar block 30, east of the company’s Wadi Aswad block 27 in the Fahud Salt sub-basin + Suneinah Foredeep, Oman Basin. Oxy (op) 72.86%, Oman Oil Co. 27.14%.

Oman (Fahud Salt Sub-basin (Oman B.)) Wadi Aswad

On 6 June 2019, Gazprom Neft and Royal Dutch Shell plc signed an agreement establishing a joint venture in Yamalo-Nenets Autonomous Okrug (Western Siberia). According to the agreement, Shell acquires a 50% interest in the share capital of Meretoyakhaneftegaz currently owned by Gazprom Neft. The deal will be finalized in late 2019-early 2010. After completion of transaction, four more licenses owned by Gazprom Neft in the region will be automatically transferred to the joint venture. The Mereto-Yakhinskiy license (SLKh15895NE) covers 1,330 sq km in the south-western part of the Nadym Taz Province and encompasses the Mereto-Yakhinskoye oil field. It is valid until 2085. The Yubileynyy Zapadnyy production license (SLKh02456NE) covers 449 sq km in the western part of the Nadym-Taz province and encompasses the Yubileynoye Zapadnoye discovery. It is valid until 2032. The Yubileynyy Zapadnyy exploratory license (SLKh02457NP) covers 1,269 sq km in the same region and it is valid until the end of 2020. The Samburgskiy Severnyy license (SLKh16360NE) covers 763 sq km east of the giant Urengoyskoye field and encompasses the Samburgskoye Severnoye field. It is valid until 2027. The Tazovskiy license (SLKh16411NR) covers 1,450 in the north-eastern part of the Nadym-Taz Province and encompasses the Tazovskoye field and several prospects. It is valid until 2025.

Shell has teamed up with Gazprom Neft (50:50) to jointly develop licence blocks in the Yamal-Nenets region. Number of license blocks at varying stages of development - the SLKh16411NR (Tazovsky) and SLKh16360NE (Severo-Samburgsky), as well as two SLKh02457NP & SLKh14952NE (Zapadno-Yubileiny), SLKh15895NE (Mereto-Yakhinskiy) blocks - will be automatically transferred to the JV’s asset portfolio as soon as the transaction closes.

PetroChina – Xinjiang achieved a breakthrough in shale oil exploration in the Junggar Basin in April 2020. Maye 1 tested 318 b/d of oil at an interval from 4,579 to 4,852 m in the Permian Fengcheng Formation. The success of the well Maye 1 opens shale oil play potential in the Mahu field area and indicated a shale oil play fairway of 2,350 sq km. PetroChina spudded Maye 1, a NFW, on 1 April 2019 in the Junggar Basin. The well is located in the north of Mahu Sag in the Wuxia Fault beltwith a PTD of 4,950 m, and had target in the Permian shale oil play in the Fengcheng Formation and volcanic play in the Carboniferous. Maye 1 completed drilling operation in October 2019. The log data also indicated 68 m oil pay in the Lower Wurhe Formation of Permian, which is one of the main reservoirs in the Mahu field. Mahu field has the main reservoir in the Triassic Baikouquan formation, recently more success wells tested oil and gas in other formations, such as the Baodaowan and Sangonghe formations in the Jurassic and the Wurhe and Fengcheng formations in the Permian. Background Information The dark mudstones and shales of the Fengchang Formation is one of the important source rock in the basin, which is deposited in lacustrine environment. Samples collected from the margin of the basin show that these dark mudstones have an average TOC content of 1.28%, a chloroform bitumen "A" value of 1,492 ppm, a total hydrocarbon content of 819 ppm, and a hydrocarbon potential S1+S2 value of 7.3 mg/g. Most of the source rocks of the Permian series are mature to post-mature with vitrinite reflectance (Ro) ranging from 0.55% to 2.0%. Carboniferous volcanic reservoir has been found in the Kelameili field in the Junggar Basin. The field includes Dixi 14, Dixi 17, and Dixi 18 and Dixi 10 discoveries and has the main reservoir in the Carboniferous volcanic rocks. By 2017, 2.7 Tcf in place gas had been proved in the field.

Maye 1 expl. (PetroChina – Xinjiang 100%), shale oil well in Mahu block, Wuxia Fold Belt, N. Mahu Sag, tested 318 bo/d from 4,579-4,852m in the Permian Fengcheng fm. PTD=4 950m, target Fengcheng fm + Carboniferous volcanics.

On 16 April 2018, Perenco completed the purchase of Chevrons interest in the No 177 concession (DRC Offshore). The interest in the concession are as follows: Perenco operates its offshore concession via its offshore subsidiary Muanda Int'l Oil Co Ltd (MIOC) with a 67.72% interest. Partner Teikoku Oil (DRC) Co Ltd, a subsidiary of Inpex, holds 32.280%. The DRC Offshore concession covers some 737 sq km within the Lower Congo basin. The entire concession is located offshore, water depths range from 0 m to roughly 50 m. The Concession plays host to eleven fields (GCO, GCO South, Libwa, Lubi, Lukami, Mibale, Misato, Moko, Motoba, Mwambe and Tshiala). As of end December 2017, combined production from that aforementioned fields was averaging 11,198 bo/d. Background information As announced on 6 December 2017, after a lengthy delay Perenco and partners in the No 177 concession (DRC Offshore) have agreed with Government on a 20 year extension. The validity of the Concession has thus been extended until 21 November 2043.

Perenco took over Chevron’s 17,7% interest in the shallow-water No 177 concession (aka DRC Offshore). Perenco operates the 737-sq km block under its Muanda Int'l Oil Co sub now with 67,72%, partner Teikoku.

Abu Dhabi National Oil Company (ADNOC) approved the transfer of a 4% interest in the Lower Zakum field and Central Offshore Concession ( Umm Shaif and Nasr fields) from China National Petroleum Corporation’s (CNPC) publicly listed subsidiary PetroChina Company Limited (PetroChina) to China National Offshore Oil Corporation (CNOOC) on 27 July 2020. ADNOC Offshore issued tender documents during 2Q 2020 for the main Long-Term Development Plan (LTDP-1) EPC contract which is intended to sustain oil production capacity at 275,000 barrels a day (b/d) from the Umm Shaif field from 2024 to 2028. It is focused upon de-bottlenecking capacity constraints in the existing Umm Shaif infield pipelines network and includes several new offshore facilities. McDermott International announced on 9 May 2019 that ADNOC had awarded it a front end engineering design (FEED) services contract as the initial phase of the Umm Shaif Gas Cap Condensate Development Project. The scope of work includes preparation and submission of an engineering, procurement, construction and installation proposal (EPCI) proposal reflecting the design of the offshore facilities developed by McDermott through its FEED work. ADNOC had awarded China National Petroleum Corporation’s (CNPC) publicly listed subsidiary PetroChina Company Limited (PetroChina) the final 10% participating interest in its new oil development contact for the offshore Nasr and super giant Umm Shaif oil fields on 21 march 2018. The company paid a US$ 570 million (AED 2.1 billion) signature bonus, proportionally in line with the cash sums paid by its coventurers Eni SpA (10%) and Total SA (20%). ADNOC subsidiary ADNOC Offshore retains a 60% government working interest in the oil development consortium. Total announced on 18 March 2018 that it had paid US$ 1.15 billion for a 20% stake in the new 40-year concession agreement to operate both the Nasr and Umm Shaif oil fields. Eni had acquired an initial 10% holding on 11 March 2018. The Supreme Petroleum Council (SPC) approved the creation of a new operating consortium prior to the expiry of the former Abu Dhabi Marine Operating Co (ADMA-OPCO) contract for the ADMA Central Block. The remaining 10% interest has yet to be awarded. ADNOC had confirmed in October 2016 that it planned to combine its two largest offshore operating companies, namely ADMA-OPCO and Zakum Development Company (Zadco) into a single operating unit. It subsequently announced on 15 October 2017 that it had established a new subsidiary “ADNOC Offshore” to be responsible for the development and delivery of oil and gas resources in Abu Dhabi waters. In launching its new unified brand in line with a 2030 smart growth strategy, ADNOC entered a transition period during which former company names are hereby being referenced for the purposes of clarity and historical integrity. ADMA-OPCO shareholders were ADNOC 60%, BP 14.66%, Total 13.33% and JODCO 12%. ADMA-OPCO was 100% right holder in the ADMA Central Block up until the point that its 45-year ADMA contract expired on 18 March 2018. The 1,303 sq km former ADMA Central concession encompassing both the giant Nasr and super-giant Umm Shaif oil fields expired in March 2018. Although discovered in 1971, the Nasr oil field was only brought onstream during 2015. Early production averaged around 22,000 bo/d during 4Q 2017, but the field is being developed to reach a peak plateau rate of 65,000 bo/d in 2H 2019. Umm Shaif was producing at a rate of around 250,000 bo/d during 4Q 2017. A new oil gathering network is to be commissioned during 2H 2019, which will allow an average production rate of 275,000 bo/d to be sustained until the year 2031. The original Abu Dhabi offshore concession was awarded to D'Arcy Exploration Company in 1953. In 1955 the concession was assigned to ADMA, a company owned by BP and CFP. BP assigned 45% of its interest to Japan Oil Development Company Limited (JODCO) in 1972. In January 1973 ADNOC acquired 25% interest in ADMA Limited. The following January ADNOC increased its shareholdings in ADMA to 60%. ADMA-OPCO was subsequently incorporated in 1977 to operate the ADMA concessions on behalf of the interest holders, ADNOC (60%) and ADMA (40%). In early November 2010, ADMA-OPCO CEO Ali Rashid Al Jarwan re-affirmed the fact that his company intended to increase its offshore oil production capacity to 1.75 million barrels a day (MMbbl/d) by 2019. Partners in the Central Offshore concession effective 27 July 2020 are ADNOC Offshore (60%) Total (20%) Eni (10%), PetroChina (6%) and CNOOC (4%).

UAE, not found

ShaleTech was granted sole rights to the 9/2019/L Wejherowo contract, 710 sq km NW of Gdansk in N. Poland, in late Dec '19. Wejherowo was offered under a 2018 tender call (Round 3 Part II), ShaleTech sole applicant.

Stena subsidiary ShaleTech Energy has been awarded 9/2019/L Wejherowo block.

Mari has acquired PEL’s 41.18% interest in the Sukkur 2768-9 EL, 2,426 sq km in the Middle Indus Basin, retro-effective 1 Mar ‘17. Mari is now sole holder of the contract.

MPCL (Mari Petroleum) has agreed to acquire from PEL (Petroleum Exploration) its full 41,18% interests in the Sukkur 2768-9 EL onshore concession.

Hub 2566-4 EL, onshore Kirthar Fold Belt, spudded Sep ’17, TD 4,555m reached in late Apr ‘18, declared non-commercial gas discovery after DST in May, HL-17 rig.

Hub X-1 (PPL 100%) in the Hub 2566-4 EL onshore block, The well flowed 0,08 MMcfg/d [16/64” choke] during DST and it has been declared as a non-commercial discovery.

On 17 July 2018, the General Directorate of Petroleum Affairs (GDPA) awarded Turkish Petroleum Corp (TPAO) two new and exclusive exploration licences for onshore areas E19-d3, d4 (273.39 sq km) and F18-b2 (107.67 sq km). The licences are located in the NW Turkish provinces of Kirklareli and Tekirdag (District I) and will be valid for an initial five-year term. They adjoin various existing exploration licence held by TPAO and lie within the Thrace Basin.<P />The Thrace Basin has received a lot of attention recently, following Valeura and Equinor's successful Yamalik 1 NFW. Over four production tests within the Eocene Kesan formation, the well tested an aggregate 24-hour rate of around 2.9 MMcfg/d, thereby validating the JV's basin-centred gas play concept. Areas E19-d3, d4 and F18-b2 lie along the northern edge of this play fairway.<P />TPAO submitted the applications for the areas on 12 December 2017. The company holds a 100% interest in all three exploration licences.

TPAO (100%) was awarded exploration licences L44-C1,C2, E19-D3, D4, E19-D3, D4 and F18-B2, N52-A

Total has reportedly elected to withdraw from CI-100,  1,373 sq km in deepwaters of the Côte d’Ivoire Basin / W. Tano Basin. Partner Eni may follow suit. So far Total (op), partners Eni, Petroci + Yam’s Petr. The latter may therefore not seek to renew upon expiry end 2019.

CI-100

Springfield is offering ‘significant’ equity in its West Cape Three Points 2 offshore block, 673-sq km in WD 100-1,700m. The area is home to the Odum (Kosmos, 2008) and Banda (Kosmos, 2011) oil finds, the latter to which an appraisal plan is being prepared.

Springfield is offering ‘significant’ equity in its West Cape Three Points 2 offshore block, 673-sq km in WD 100-1,700m.

October 2019 reports confirmed Suelopetrol discovered oil in its OMI 1 new-field wildcat (NFW) well on the LLA-61 Block of the Llanos Basin. The wildcat was spudded in late July 2019 targeting Carbonera sandstones at reservoir depths between 3,500 ft to 4,500 ft. By August 2019 the well was producing some 350 bo/d and plans for the OMI 2 exploration well were underway. Suelopetrol operates the acreage with 100% interest. Background information Suelopetrol acquired 165 km of 3D seismic data over the LLA-61 Block during 2012. After receiving the necessary environmental permits, access road construction commenced for the Llanos Basin drilling campaign.

Colombia (Catatumbo B.) ? op. by WELL LOG (100.0%, WELL LOG 100.0%) in Carbonera block

N. sector of Ratna (R-12) field, Ratna & R-Series ML, Bombay offshore, ops terminated at TD 3,300m, Harvey H. Ward JU off location 30 Mar '20.

Ratna (R-12) F appr N. sector of Ratna (R-12) field, Ratna & R-Series ML, Bombay offshore, ops terminated at TD 3,300m,

The Neuquén authorities awarded on 8 Nov ’17  4-year rights to the 120-sq km Las Tacanas Norte block to Pampa Energía, offered in the Neuquén V round (V Ronda Licitatoria del Plan Nuevos Horizontes) launched in Apr ‘17. The block lies adjacent to the company’s El Mangrullo block, main target Vaca Muerta to which 8 wells are planned. It is recalled Statoil also went for Bajo del Toro Este (136 sq km), and Retama Argentina for Parva Negra Oeste (128 sq km). GyP Neuquén will own a 10% stake in each contract.

Argentina (Neuquen B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: El Mangrullo op. by PAMPA P (100.0%) to be check.Las Tacanas Norte op. by PAMPA EN (90.0%, NEUQUEN 10.0%) to be check.Parva Negra Oeste op. by RETAMCO (90.0%, NEUQUEN 10.0%) to be check.Las Tacanas op. by YPF (50.0%, PLUSPET RS 50.0%) to be check.Bajo del Toro op. by YPF (100.0%) to be check.Bajo del Toro Este op. by STATOIL (90.0%, NEUQUEN 10.0%) to be check.

Equinor has increased its interest in PL 785 S by 20% as a result of a deal with operator Total. The licence covers parts of blocks 26/2 and 31/11 (to the south of Troll), totalling 622 sq km, and applies below Base Cretaceous. Total plans to drill a well on the Brunost prospect in 2020. The deal was reported by the NPD on 4 January 2020 and is effective from 20 December 2019. This area of the Horda Platform (Stord Basin and Bergen High) has seen almost no drilling. The closest wells to the north and south are dry holes 31/8-1 and 26/5-1. 31/8-1 was drilled by E.ON Ruhrgas in 2011 on the Breiflabb prospect. The main target was the Upper Jurassic Sognefjord Formation and there were secondary objectives in the Jurassic Johansen, Fensfjord and Krossfjord formations and the Brent Group. The Sognefjord, Fensfjord and Krossfjord formations were all present but there were no shows. The Brent Group was not reached (the Krossfjord Formation was mistaken for the Brent Group at the time). 26/5-1 targeted the Paleocene Balder Formation and the Miocene Utsira Formation in the Storbarden prospect. Rocksource drilled this well in 2013, finding both formations but with almost no sand. Interest in PL 785 S is now divided between Total E&P Norge AS (50% + operator) and Equinor Energy AS (50%).

Equinor has increased its interest in PL 785 S by 20% as a result of a deal with operator Total. The licence covers parts of blocks 26/2 and 31/11 (to the south of Troll), totalling 622 sq km, and applies below Base Cretaceous.

Tullow’s pending assignment of offshore block Z-64 in the Tumbes Basin has been approved by the govt. The signing of the contract is to take place shortly between Perupetro and Tullow.  Meanwhile Tullow continues to work with Perupetro to execute licences for other offshore blocks Z-65, Z-66, Z-67 + Z-68.

Supreme decree published in offical gazette for award of toTullow (100%), four other blocks expected to follow eventually.

In early 2019 the Peruvian government approved an interest transfer on the 792 sq km Block 39 Contract in the Maranon Basin. India's Reliance Exploration ceded its 10% in the license back to the French operating company Perenco. Perenco will now have 65% of the license while partner Petrovietnam retains a 35% share. The deal will be complete once signed by Perupetro. The interest was the only upstream holding of Reliance in Peru and the company did not disclose why it was letting it go although it has been recently focused on hydrocarbon production in India. Reliance entered the block in 2009. The deal has been pending approval since July 2017. In its annual report for 2016-2017, Reliance first announced it was withdrawing from its 10% interest in Block 39. Reliance once had interests in four blocks in Peru. With an effective date of 6 May 2016, Perenco relinquished almost 90% of Block 39. This was the oldest exploration block in Peru having been awarded in 1999. The exploration acreage is expired and was relinquished but areas were retained around the Buena Vista and Raya discoveries on the block. In August 2014, Repsol completed the divestment of its 55% stake to Perenco in Block 39. Block 39 is a top block in Peru for probable oil reserves with 274 MMbo but no proven reserves, as commerciality has not been declared yet. Previously, Repsol acquired some seismic on Block 39 covering the Raya structure, the largest discovery on Block 39, which is prone to heavy oil. In August 2017, Perenco filed a request with PeruPetro to unite blocks 67 and 39 in the Maranon Basin into one license. Block 67 was once an enclave within Block 39. Perenco may or may not declare commerciality on Block 39 and develop the heavy oil block. This could be a bellwether decision for the future of the hydrocarbon industry in Peru and the Northern Maranon region. In March 2015, Perenco received government approval for an environmental impact assessment (EIA) to acquire 108 sq km of 3D seismic on Block 39. The survey will be focused on the area to the east of the Block 67 in the Dorado Este and Pirana Sureste Field areas.

Reliance is reportedly selling its 10% in block 39, 792 sq km in the, to partner Perenco, who thus boosts to 65% with Petrovietnam partnering on 35%. Reliance farmed-in to the 2-block licence in 2009, and it is the company’s sole asset in Peru.

RG 5 Moldova Sud block, Outer Carpathian Foredeep in E. Romania, P&A Dec ’18, results n/a. PTMD was 2,350m (TVD 2,300m), target Sarmatian.

Iliesi 1 in RG 5 Moldova Sud block, E. Romania, P&A, results n/a. PTMD was 2350m (TVD 2,300m), target Sarmatian.

Enping Sag in PRMB, South China Sea, WD 90m, target Mio-Oligocene clastics, completed 10 Jul ’19, results unreported, HYSY 943 JU.

Enping 20-7-1 (EP 20-7-1) nfw Enping Sag in PRMB, South China Sea, WD 90m, target Mio-Oligocene clastics, completed 10 Jul ’19, results unreported,

Correction DEA 18 Jul '19: South Deepwater Tano Block (SDWT), WD 3,080m, reportedly oil discovery (contrary to earlier reports suggesting concurrent Kyenkyen-1X has been successful), no further info. Maersk Viking DS.

Ghana, not found

MOL used the “Deepsea Bergen” S/S to drill an exploration well on its Evra and Iving prospects in PL 820 S located between the Jette and Ringhorne fields. 25/8-19 S was spudded on 2 November 2019 and was drilled to TD at 2,760 m. Pre-drill potential recoverable reserves are 181 MMboe (source: Lundin, October 2019). Evra is an injectite prospect, with remobilised Paleocene Hermod Sandstones expected in the Eocene Hordaland Group. Two sand bodies were expected – one at 1,783 m and the other at 2,023 m. The main objective for the Iving prospect (four-way closure at the BCU) was the Lower Jurassic Statfjord Formation at 2,207 m. There were also further targets in the Paleocene Ty Formation, the Triassic Skagerrak Formation and the Basement. The drilling plan called for a sidetrack (targeting Evra only with a planned TD of 2,104 m / 2,000 m TVD) if the well made a discovery at Evra and on 31 December 2019 MOL kicked off 25/8-19 A which is designated as an appraisal, indicating that a discovery has, indeed, been made. Operations are continuing on 12 February 2020. PL 820 S contains the 2001 dry hole 25/8-13 which was drilled by Esso. Good reservoir sands were present in both the Ty Formation and the Statfjord Formation, although both were water-bearing. MOL Norge AS operates PL 820 S with a 40% interest. It is partnered by Lundin Norway AS (40%), Pandion Energy AS (10%) and Wintershall Dea Norge AS (10%).

025/08-19 S (Evra/Ivring) expl. (MOL 40% op, Lundin 40%, Pandion 10%, Wintershall Dea10%),1st well in PL 820 S, location between Jette + Ringhorne fields, WD=125m, industry rumours suggest a positive outcome. Evra is an injectite prospect, with remobilised Paleocene Hermod Sandstones expected in the Eocene Hordaland Group.

According to reports in early-April 2018, Vista Oil & Gas has completed the acquisition of several assets from Pampa Energia and Pluspetrol following separate agreements that were signed with each company in January and February 2018, respectively. From Pampa Energia and Pluspetrol, Vista purchased both companies’ interest in Petrolera Entre Lomas SA (PELSA), effectively giving it 100% stake and operatorship in Charco del Palenque (184 sq km), Jarilla Quemada (194 sq km), Bajada del Palo (452 sq km), and Entre Lomas (733 sq km) production concessions located on the Neuquen Embayment part of Neuquen Basin. It was noted that Vista acquired Pluspetrol’s equity in PELSA through the purchase of the latter’s Apco Oil & Gas International. Apco Austral, a wholly-owned subsidiary of Apco International for assets located in the Austral Basin, was excluded from the transaction as it was already in the process of being acquired by a different company at the time Vista’s agreement with Pluspetrol was executed. Outside of the previously mentioned assets linked to PELSA, Vista also acquired Pampa Energia’s 100% interest in the producing blocks of 25 de Mayo-Medanito SE (125 sq km) and Jaguel de los Machos (112 sq km) blocks in the Northeast Platform part of Neuquen Basin. Meanwhile in a separate agreement with Pluspetrol, Vista purchased several assets that were controlled by Pluspetrol’s subsidiary, Pluspetrol Black River, including 55% interest and operatorship on Coiron Amargo Norte (115 sq km) and a non-operated 45% interest in the Coiron Amargo Sur Oeste (64 sq km) in Neuquen Basin. In addition, Vista also acquired non-operated interest in Sur Rio Deseado Este block in San Jorge Basin, specifically 16.94% in the production side (50 sq km) and reportedly 44% on the exploration side (256 sq km), as well as 1.5% non-operated interest in the Acambuco block (1,189 sq km) in Noroeste Basin. Following the acquisition, the company reportedly became the fifth largest oil producer and operator in Argentina based on data from the Argentinean Ministry of Energy and Mining. Background Information Vista Oil & Gas is an energy company that was incorporated in early-2017 based in Mexico, and is headed by former CEO of Argentinian state company YPF, Miguel Galuccio.

Argentina, Jarilla Quemada

Ref. DEA 25 Feb ’19, RockRose has now completed the takeover of Marathon Oil UK and Marathon West of Shetland Ltd for USD 95 MM, the deal retro-effective 1 Jan ’19. MOUK holds 26% in P313 and 40% in P340 + P108 (Greater Brae Area). MOWOS has 28% in the Foinaven field (BP op) and sundry interests in the Foinaven East, T25 + T35 satellites. The deal also includes stakes in the SAGE, Brae-Forties and WOSPS infrastructures.

RockRose has now completed the takeover of Marathon Oil UK and Marathon West of Shetland Ltd for USD 95 MM, the deal retro-effective 1 Jan ’19. MOUK holds 26% in P313 and 40% in P340 + P108 (Greater Brae Area). MOWOS has 28% in the Foinaven field (BP op) and sundry interests in the Foinaven East, T25 + T35 satellites.

Brazil's first pre-salt oil auction on 30 May failed to attract any offers, and the PPSA is now reportedly intending to re-launch the round later this year. The auction will presumably be held under revised terms. It offered future oil output from the Mero (Libra project), Lula and Sapinhoá areas.  Oil from the Tartaruga Verde area was due to be offered too but was not be released since the percentage of govt profit oil is still under negotiation.

Brazil's first pre-salt oil auction on 30 May failed to attract any offers, and the PPSA is now reportedly intending to re-launch the round later this year. The auction will presumably be held under revised terms. It offered future oil output from the Mero (Libra project), Lula and Sapinhoá areas. Oil from the Tartaruga Verde area was due to be offered too but was not be released since the percentage of govt profit oil is still under negotiation.

Senex Energy Ltd, through wholly owned subsidiary Victoria Oil Exploration (1977) Pty Ltd, spudded vertical exploration well Avenger 1 in PRL 146, located in the Cooper-Eromanga Basin, on 29 October 2018.  On 7 November 2018 the well was plugged and abandoned as a dry hole, after reaching a total depth of 2,144 m. The well was drilled around 11 km west of the Snatcher oil discovery, which was made in 2009 and is currently producing. 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%).

Avenger 1 (Senex 60%, op. Beach 40%) in PRL 146 block, P&A dry.

By decree of the Sicilian regional authorities dated 28 February 2019 Irminio was awarded the Case la Rocca exploration permit located in southern Sicily to the north of the Irminio oil field. The contract, valid for six years, will be effective upon publication of the decree in the official gazette of the Sicily region (GURS), which is expected for March 2019. Commitments include geological studies, the re-processing of the existing 3D seismic within 12 months from the award and the drilling of two exploratory wells within 24 and 48 months respectively. The total expenditure related to the work program amounts EUR 18.3 million (USD 20.7 million). It is recalled that onshore Sicily is not affected by the 18-month suspension of exploration decided by the Italian authorities in early-2019 due to the specific status of the region. Irminio applied for the Case la Rocca exploration permit on 3 April 2013. The block, encompassing 80-sq km in the Ragusa province, covers the former Tresauro exploration permit, which expired on 29 December 2012, and surrounds the 22-sq km Sant’Anna exploitation concession (EniMed). The company is planning to drill two wells from the same location in the northern part of the block, 5 km to the west-southwest of the city of Ragusa. Proposed depths are of 2,702 m PTVD for Case La Rocca 1 and 2,650 m PTVD for Case La Rocca 2. The main objective of the wells is to find oil within the dolomites of the Triassic Sciacca (Gela) Formation. The secondary objective is the Upper Triassic Noto carbonate Formation (light oil- 32°-33° API). The two prospects, located 1.7 km away from each other, were identified through a 3D seismic acquired in 2002 and 2006 in the area. Irminio Srl holds a 100% interest in the Case La Rocca exploration permit.

Irminio Srl. was awarded the Case la Rocca exploration permit located to the north of the Irminio onshore oil field.

Calik Petrol Arama Uretim San. ve Tic. A.S. completed the Caliktepe Guney 4 appraisal well in Block 4495, southeast Turkey, in December 2017. The well, which is believed to have had a primary objective in the Ordovician Bedinan Formation, was brought on-stream at a rate of 200 bo/d. Block 4495 was first awarded in 2009 and covers an area of 497 sq km in the Southeast Turkey Zagros Fold Belt. Calik Petrol is 100% owner and operator of the block. Calik also completed the Caliktepe Guney 2 and 3 appraisal wells in the licence area in 2017. The Caliktepe Guney 1 discovery well was completed in March 2016 as an oil producer in the Bedinan Formation.  

Caliktepe Guney 4 appraisal well in Block 4495, southeast TurkeyThe well, which is believed to have had a primary objective in the Ordovician Bedinan Formation, was brought on-stream at a rate of 200 bo/d. southeast Turkey

On 12 October 2018, the Federal Agency for Subsoil Use held an auction for two blocks in Samara Oblast (Volga-Ural Province). Udmurtia-registered Sabunskiy offered the highest bids for both blocks. The winner of the auction will obtain 25-year E&P licenses. Details of the offer are as follows: The Podkolskiy block covers 178 sq km in the northern part of the Buzuluk Depression and encompasses the Uvarovskiy Severnyy and Podkolskiy prospects and a part of the Ostrogorskiy prospect. Combined oil resources of the prospects are estimated at 6 MMbbl. Five exploratory wells have been drilled in the block. Hydrocarbon resources (category D1) of the block are estimated at 26 MMbbl of oil and 17 Bcf of gas. The starting price amounted to RUB 11.8 million (USD 0.18 million). Sabunskiy offered RUB 12.98 million (USD 0.2 million). The Matyanovskiy block covers 528 sq km in the southwestern flank of the Tatarskiy Yuzhnyy Dome and encompasses the Bugulminskiy, Nabokovskiy, Suvarskiy, Khersonskiy and Lefanovskiy Yuzhnyy prospects with combined oil resources estimated at 20 MMbbl. Seismic coverage amounts to 1,320 km. 28 exploratory wells have been drilled in the block. Hydrocarbon resources (category D1) of the block are estimated at 50 MMbbl of oil and 3 Bcf of gas. The starting price amounted to RUB 38.9 million (USD 0.59 million). Sabunskiy offered RUB 42.79 million (USD 0.65 million).

Sabunskiy was awarded 2 blocks in Samara Obl.: Matyanovskiy block and Podkolskiy.

On 26 April 2019 Rathlin Energy spudded appraisal well L46/05-4 (West Newton A-2) on its West Newton discovery in PEDL 183. The well is located approximately 1.5 km south of the 2013 West Newton well. It targeted the Kirkham Abbey Shoal and Cadeby Reef formations for gas (contingent resources of 189 Bcf/g) and oil (prospective resources of 79.1 MMboe) respectively.  On 17 June 2019 partner Union Jack Oil announced that the well had encountered hydrocarbons (including a significant liquids component) across a 65 m (net) interval in the Kirkham Abbey Formation along with shows in the Cadeby Reef Formation. Drilling operations were concluded after reaching a TD of 2,061 m and production casing was run in preparation for testing which is planned for Q3 2019. The test is designed to establish flow rates and help determine the future development drilling programme. On 23 June 2019 it was understood that the drilling rig had left location. Drilling was planned to take 6 - 12 weeks where the company was not planning to test any shale horizons estimated to be deeper than its Permian targets. It was hoped that the well would determine the commerciality of the discovery. In an update from the company on 17 June 2015 it confirmed that East Riding of Yorkshire Council had granted planning permission for the well. On 26 November 2015 Rathlin announced that it was pleased that the planning committee had unanimously approved the planning application for an extension at West Newton A. Following the well encountering gas the company is permitted to 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 had granted a permit for the drilling of the well. On 15 November 2018 partner Union Jack announced that it had received approval to extend the existing planning permission for a further 36 months at its wellsite. 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 Cadeby 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 is held by Rathlin Energy (UK) Limited (66.67% + operator), Humber Oil and Gas (16.665%) and Union Jack Oil Plc (16.665%).

West Newton A-2 appr. (Rathlin Egy 66, 67% op, Union Jack 16,67%, Humber O&G 16,67%) in PEDL 183 block, had been drilled to a TD=2061m and intersected both gas and liquids. Net 65m hc saturated interval was encountered within the primary Kirkham Abbey Fm which indicated “a substantial hc accumulation”, hc shows had also been observed in the secondary target Cadeby Fm. with an oil saturated core. Preliminary data suggested a best estimate contingent resource of at least the pre-drill estimate of 189 Bcf, or 31,3 MMboe.

On 14 December 2017, Petrobras issued a press release indicating that CEO Pedro Parente signed a Memorandum of Understanding (MOU) for a wide ranging Strategic Alliance with ExxonMobil in Rio de Janeiro.  The MOU will allow the companies to evaluate various potential projects in Brazil and internationally that will include the entire oil and gas value.  Both companies have already partnered, ahead of this agreement, in the ANP Round 14 whereby they acquired six blocks. This represents the 4th Strategic Alliance agreement, the others are with CNPC, Statoil, and Total.  Additionally a letter of intent was signed with BP on 31 October 2017 for a similar Strategic Alliance agreement which would represent the 5th major Strategic Alliance agreement.   Petrobras indicated that the Strategic Alliance agreements are an important part of its 2017-2021 business plan to share risks, to increase its capacity for investments in the oil and gas value chain, transfer and interchange of technology, and strengthening its corporate governance.  

Brazil, not found

S. part of Junggar Basin, tested 8,500 bo/d + 11 MMcfg/d, WHP 4,700 psi. Regional targets Cretaceous + Tertiary clastics.

Gaota 1, S. part of the basin, a major discovery, tested 8500 bo/d + 11 MMcfg/d. A few wells have been drilled in this area with oil tested from the regional targets Cretaceous and Tertiary clastic rock, but without commercial value. Gaotan 1 is believed to achieved commercial oil and gas flow from the deeper formations.

Dana Gas seeking a partner for the deepwater Block 6 (North El Arish Offshore) located in the Eastern part of the Mediterranean area. The company plans to drill a wildcat in the block in 2019. Dana Gas announced on 18 February 2014 that it had signed an agreement for the Block 6 (North El Arish Offshore). The company is committed to spending USD 71.5 million, paying a signature bonus of USD 20 million and drilling three wells. The Block, which was included in the Egyptian Natural Gas Holding Company’s (EGAS) 2012 international bid round, was awarded to Dana Gas on 22 April 2013. It covers 2,980 sq km and lies in water depths from 20 to 1,000 m. The agreement includes an eight-year exploration period with three phases starting with an initial four-year exploration period and two additional two year extension periods. A 20-year development lease period will be granted in case of commercial discovery.

Dana Gas seeking a partner for the deepwater Block 6 (North El Arish Offshore) located in the Eastern part of the Mediterranean area. The company plans to drill a wildcat in the block in 2019.

ADM has agreed to acquire a 25% interest from Energy Equity Resources’ 16.88% in western offshore delta OML 113, equating to a 4.2% stake or a 9.2% revenue interest. The cash-and-share deal carries a price tag of USD 3 MM. ADM already holds a 2.7% interest in OML 113, resulting partnership unchanged, viz. Yinka Folawiyo (op, NewAge (together operating as Aje Petr.), Energy Equity Res., PetroNor + ADM Egy.

ADM Energy has entered into a sale and purchase agreement with EER (Energy Equity Resources AS) to acquire 25% of the ERRs interest in OML 113.

Kirthar 2667-7 EL, Kirthar Fold Belt in Sindh, P&A dry early Sep ’18, tested. PTD was 3,537m, Exalo-304 rig. PGNiG (op), partner PPL.

Pakistan, Kirthar 2667-7 ELRoshan 1 (PGNiG 70%, PPL 30%) the exploratory well within the Kirthar 2667-7 EL onshore block, P&A, after failed to flow hydrocarbons during testing.

PPL secured rights to the Sorah 2768-13 EL, 1,152 sq km in the Sukkur and Khairpur districts, Sindh (M. Indus Basin), and Musa Khel 3069-10 EL, 2,176 sq km in the Musa Khel + Zhob districts of Balochistan (Sulaiman Fold Belt), on 20 Jun ’19. Both had been offered under the 2018 round.

PPL secured rights to the Sorah 2768-13 EL, 1152km² (M. Indus Basin), and Musa Khel 3069-10 EL, 2176km² in Balochistan (Sulaiman Fold Belt).

Santos and Denison Gas have been awarded rights in the Bowen + Surat basins of S. QLD, believed issues of the 2019 Queensland State Acreage Release only now formally announced. Santos gets PLT2019-2-9/10/11/12, 2,000 sq km between Chinchilla + Roma, Denison PLR2019-1-3 (now ATP 2049-P), 568 sq km near Emerald in the Bowen Basin.

Santos and Denison Gas have been awarded rights in the Bowen + Surat basins of S. QLD, gas-prone acreage, believed issues of the 2019 Queensland State Acreage Release only now formally announced. Santos gets PLT2019-2-9/10/11/12, 2,000 sq km between Chinchilla + Roma, Denison PLR2019-1-3 (now ATP 2049-P), 568 sq km near Emerald in the Bowen Basin.

Tap Oil has provided an update on exploration drilling at the Mubadala-operated Ladawan-1 exploration well in the G1/48 concession in the northern Gulf of Thailand (Tap Oil 30%). Mubadala, operator of the G1/48 concession and the Manora oil field has advised that drilling of the Ladawan-1 exploration well has reached TD of approx. 2,175m true vertical depth subsea (TVDSS). Interpretation of the logging while drilling data shows approx 3.3m of oil column in the primary reservoir target below a depth of 2,033m TVDSS. The result is not viewed as commercial and the well has been plugged and abandoned. Original article link Source: Tap Oil

Thailand (Kra Sub-basin (Gulf of Thailand B.)) Manora

A 2013 farmout offer for the wholly-owned, 8,523-sq km offshore Andaman III PSC in deepwaters off North Sumatra is confirmed still open. Repsol is offering up to 49% ahead of a high-impact planned drilling campaign later next year.

Indonesia, Andaman III PSC

Pursuant to an October agreement (DEA 17 Oct '19), Armour and Santos have executed the farmin agreement covering Armour’s South Nicholson Basin project in Queensland: so far wholly-owned ATP 1087-P (4,720 sq km, Santos gets 70% + optr) and applications ATP 1107-P, ATP 1192-P, ATP 1193-P, EP(A) 172 + EP(A) 177 (Santos can get 70% + optr), total 36,420 sq km. Santos will also carry Armour for up to AUD 64.9 MM.

Australia, ATP 1087-P

As of late June 2019, it is understood that Eni will take over operatorship of the shallow water Congo Fan Block 1/14. According to sources a new contract to explore the block has already been negotiated and is with the ministry for final approval. The 3,730 sq km block plays host to four small oil discoveries all discovered by Agip (Africa) Ltd in the early 1980s. At least 18 additional prospects have been identified however, these are thought to be gas prone.    Sonangol E.P currently holds the block with a 100% interest however, once ministerial approval is received, Eni will operate the tract with a 35% interest, Sonangol P&P will hold a 30% stake, Equinor will hold a 25% stake and ACREP will hold the remaining 10% interest.

Eni is taking over from Sonangol EP as operator of block 1/14, 3,730 sq km in Congo Fan shallow waters. The deal is pending ministerial approval and will be retro-effective 1 Jun ’19. Partnership-to-be is Eni (op) 35%, Sonangol P&P 30%, Equinor 25%, ACREP 10%.

As of 8 January 2018 ConocoPhillips Canada Resources was officially awarded significant discovery license SDL 154 on 20 October 2016 located in the Northwest Territores within the Mackenzie Plain Basin. The award was back dated for administrative purposes. ConocoPhillips is a 100% owner in the rights under the 839.78 sq km SDL. In February 2015 ConocoPhillips submitted an application for a Significant Discovery Declaration (SDD) to the Government of Northwest Territories (GNWT) Regulator of Oil and Gas Operations for the Dodo Canyon E-76 and Mirror Lake P-20 shale oil horizontal exploration wells drilled in 2014. Both wells were located in EL 470 and were drilled to test the shale oil potential of the Devonian Canol Formation. The area over which the SDD application is made covers approximately 839.41 sq km, nearly the entire area for EL 470 which encompasses 874.95 sq km. The SDD set in motion the geologic evaluation of lands by NWT government agencies over which the application is made as a prelude to applying for a Significant Discovery License which in itself will extend the term of the lands being applied for. A comment period for directly affected person (DAP) ran through 1 April 2015. ConocoPhillips had until 1 May 2015 to file any comments on submissions from a DAP with the Regulator. The 874.95 sq km block EL 470 was awarded to ConocoPhillips for a work commitment bid of CAD 66,712,035.00 from the 2011 Central Mackenzie Valley Call for Bids. The effective date of the award was 20 December 2011. Background In April 2015 ConocoPhillips shut-in the Dodo Canyon E-76 shale oil wildcat located onshore in EL 470 following testing and after completing a 10 stage Acid, Slickwater, WF103 & WF 125 Flex fracture procedure on 17 February 2014. The company did not release test results but an aerial image of the well location showed a flare burning during testing. The well drilled an 1,00m horizontal section into the Devonian Canol formation and reached a total depth of 2,910 m (1,790 m TVD). The Dodo Canyon E-76 offset the Loon Creek O-06 new-field wildcat drilled as a vertical well in 2013. The Loon Creek O-06 was used as a monitor well to gauge the impact of fracturing on formations up hole. At the same time ConocoPhillips shut-in the Mirror Lake P-20 shale oil wildcat also located onshore in EL 470. The well was also drilled as a horizontal well into the Devonian Canol formation to a total depth of 3,152 m MD. The Mirror Lake P-20 offset the Mirror Lake N-20 drilled as a vertical well in 2013. Plans called for the well to be drilled down to a vertical depth of about 1,600 m and then directionally steered to a well bore attitude of 90 degrees reaching a measured depth of about 2,300 m and a vertical depth of about 1,800 m. The well will then be horizontally drilled an additional 1,000 m to 1,500 m. A ten stage hydraulic fracturing procedure was performed, followed by testing of the well. The Mirror Lake N-20 was used as a monitor well to gauge the impact of fracking up hole. Geology The Mackenzie Plain Basin is one the most heavily explored basins in the Central Mackenzie Valleys with a total of 480 wells being drilled of which 101 are exploratory wells. The basin includes the Norman Wells Field, the only oil producing field in the Northwest Territories. Mackenzie Plain overlies the southern Peel Trough between the arc of the Cordillera (Mackenzie Mountains) to the west and the flank of the Keele Arch (Franklin Mountains) to the east. A westward-thickening wedge of Cretaceous-Tertiary strata overlies a broad Lower Paleozoic syncline with a gently-dipping eastern limb and a more steeply-dipping western limb rising to outcrop as the front ranges of the Mackenzie Mountains. Lower Paleozoic strata outcropping in the Franklin Mountains border the Peel Trough to the east. The trough widens to the northwest where the Mackenzie Mountains swing westwards. The Mackenzie Foldbelt in this northern area extends beneath Mackenzie Plain. To the south, the trough becomes increasingly constricted as the Keele Arch reaches a terminus close to the Mackenzie Mountain front at about 64°N. The entire region has been affected by compressional tectonics, expressed as long wavelength folds (especially in the north), bedding-parallel detachments (beneath Mackenzie Plain), and thrust faults outcropping in the Franklin Mountains.

ConocoPhillips (100%) was officially awarded license SDL 154, located in the Northwest Territories.

On 23 November 2018 Amerisur Resources reported a farmout agreement with Occidental Andina for four blocks in the Putumayo Basin. The USD 93.25 million deal includes 50% interest in each of the PUT-9, Terecay, Tacacho, and Mecaya blocks where Occidental will fully fund five exploration wells and pay 85% of the costs for a 2D seismic acquisition, estimated at USD 38 million and USD 55.25 million, respectively. Amerisur will retain operatorship and the remaining 50% interest in each block. This company deal accelerates Amerisur’s work programs in the Terecay and Tacacho blocks where the social consultations (Consulta Previa) and licensing procedures have already been completed for the 878 km 2D seismic survey to commence in Q1 2019. Consulta Previa for drilling on the Tacacho Block is anticipated to commence in Q1 2019 with drilling plans slated within a year.

Amerisur Resources reported a farmout (for 50% share) agreement with Occidental for 4 blocks Putumayo-9, Terecay, Tacacho and Mecaya blocks by funding a US$93.2 MM exploration and appraisal programme.

Obskiy Severnyy block (licence ShKM15746NR), shallow waters of the Ob Estuary, W. Siberia, gas-cond discovery, 3P gas reserves pegged at 10.96 Tcf, gas resources of deeper reservoirs within Obskoye Severnoye estimated at 31 Tcf. PTD was 3,000m, Amazon JU.

Obskaya Severnaya-1 nfw Obskiy Severnyy block (licence ShKM15746NR), shallow waters of the Ob Estuary, W. Siberia, gas-cond discovery, 3P gas reserves pegged at 10.96 Tcf, gas resources of deeper reservoirs within Obskoye Severnoye estimated at 31 Tcf. PTD was 3,000m,

PEDL 137 near Gatwick, testing of Portlandian has restarted, currently flowing 208-218 b/d. Test prod to continue until completion of the HH-2 Portland horiz well, scheduled for spring ’19 (all permits and planning in place). Permanent long-term Portland production by end-year.

More tests: Horse Hill-1 nfw (Portland)PEDL 137 near Gatwick, testing of Portlandian has restarted, currently flowing 208-218 b/d. Test prod to continue until completion of the HH-2 Portland horiz well,

NW part of AE-0053-3M-Mezcalapa-03 block, onshore Sureste Basin in Tabasco, discovery looking to be the largest onshore Sureste discovery since 1987, est. 3P reserves 500 MMboe (up from erstwhile 40 MMboe). Meanwhile Quesqui 1DEL appr is underway, last reported below 4,400m in late Nov '19. The 34-sq km field calls for 11 devt wells. Production hoped to reach 300 MMcfg/d + 69,000 bc/d in 2020, 410 MMcf/d + 110 Mbc/d in 2021.

Quesqui 1EXP (Pemex 100%) in NW part of AE-0053-2M-Mezcalapa-03 block, onshore in Tabasco, compl o&g, testing ab. 800 bo/d + gas from an HPHT reservoir. Targets Cret. (npw) + Jurassic (dpw). Initial tests produced 4,478 bc/d of 43.8° API and 16.67 MMcfg/d from the Late Jurassic Kimmeridgiano Fm. Discovery looking to be the largest onshore Sureste discovery since 1987, est. 3P reserves 500 MMboe (up from erstwhile 40 MMboe).

Hub 2566-4 EL, Kirthar Fold Belt in Sindh + Balochistan, TD 5,406m, P&A dry in Oct '19, SLR-223 rig.

Nooh X1 (PPL 100%) in Hub 2566-4 EL block, P&A, dry, after Testing, targeted Jurassic objectives.

Gujarat State Petroleum intends to dispose of much interests in India, 12 blocks earmarked and data room open. Of those 12 blocks, 5 are operated by ONGC, 3 by Gujarat Natural Resources, 2 by GSPC, 1 each by Sun O&G + Oilex. Background from GEPS.

Gujarat State Petroleum intends to dispose of much interests in India, 12 blocks earmarked and data room open. Of those 12 blocks, 5 are operated by ONGC, 3 by Gujarat Natural Resources, 2 by GSPC, 1 each by Sun O&G + Oilex.

On 17 June 2020, Petrobras published a teaser to sell its working interest in 7 fields (Alagoas Package) that include the Anambe, Arapacu, Cidade de Sao Miguel dos Campos, Furado, Paru, Pilar and Sao Miguel dos Campos in the Sergipe-Alagoas Basin. All the fields, except the Paru field, are onshore. The offshore Paru field lies in a water depth of about 24 m. Petrobras is operator with 100% working interest in all the fields offered. Interested companies must submit the customary manifestation of interest by 6 July 2020 and qualification documents by 24 July 2020 to J.P. Morgan at [email protected]. Petrobras reported that the average production of the fields for 2019 was 2,348 bpd of oil and condensate and 30 Bcfgpd (856 thousand m3/d of gas), and that they generated 1,010 bpd of LNG. Besides the production concessions and its production installations, the offer includes the natural gas process unit of Alagoas, which processes 100% of the gas of the cluster and generates LNG and has a processing capacity of 70 MMscfpd (2 million m3/day). The following table provides more details about the cluster of fields on sale: Alagoas Package of fields on sale Field Name Disc Date Year Contract Name Award Date Year Block Sqkm Anambe 2004 BT-SEAL-002 2000 11.28 Arapacu 2011 SEAL-T-240 2009 10.9 Cidade de Sao Miguel dos Campos 1969 Cidade deSao Miguel Dos Campos 1998 16.38 Furado 1968 Furado 1998 45.35 Paru 1983 Paru 1998 15.12 Pilar 1981 Pilar 1998 89.42 Sao Miguel dos Campos 1973 Sao Miguel dos Campos 1998 45.25 Source: IHS Markit © 2020 IHS Markit

Brazil (Sergipe-Alagoas B.) Anambe op. by PETROBRAS (100%), On 17 June 2020, Petrobras published a teaser to sell its working interest in 7 fields (Alagoas Package) that include the Anambe, Arapacu, Cidade de Sao Miguel dos Campos, Furado, Paru, Pilar and Sao Miguel dos Campos in the Sergipe-Alagoas Basin. All the fields, except the Paru field, are onshore.

BT-PN-001 contract, PN-T-102 block P&A assumed dry early Nov ‘18. PTD was 1,622m, targets Cabeças + Poti fm’s.

3-PGN-ARAGUAINAD-MA (3-PGN-029-MA) (Parnaiba Gas Natural 100%) in PN-T-102 block P&A assumed dry.

OMV successfully completed the Bernhardsthal 11 new pool wildcat, after it reached TD at 3,140m and discovered oil in a previously unexplored reservoir to open up a deeper play beneath the Bernhardsthal-Sud Field. The well also encountered oil within the overlying Miocene 2nd - 3rd Eggenburg Sand and 24th Torton Horizon which will be tested in the future. It was converted for oil production in June 2018, and six new production wells are planned to produce the oil in the Bernhardsthal Ost area. Bernhardsthal 11 was spudded by mid-April 2018 in NE Austria, less than 5km from the Czech border. OMV Aktiengesellschaft operates the Lower Austria licence with 100% equity.

OMV successfully completed the Bernhardsthal 11 new pool wildcat, after it reached TD at 3,140m and discovered oil in a previously unexplored reservoir to open up a deeper play beneath the Bernhardsthal-Sud Field. The well also encountered oil within the overlying Miocene 2nd - 3rd Eggenburg Sand and 24th Torton Horizon which will be tested in the future. It was converted for oil production in June 2018, and six new production wells are planned to produce the oil in the Bernhardsthal Ost area. Bernhardsthal 11 was spudded by mid-April 2018 in NE Austria, less than 5km from the Czech border. OMV Aktiengesellschaft operates the Lower Austria licence with 100% equity.

AE-0024-2M-Okom-07, offshore Sureste Basin, 5km NNE of Wayil discovery, P&A dry at TD 4,900m mid-Jan ’19, Prospector II JU. Target Cretaceous.

Yok 1EXP (NFW) (Pemex 100%) in the AE-0024-2M-Okom-07 block entitlement block, P&A dry.

Shell has acquired a 50% operating stake from Ecopetrol in the Fuerte Sur, Purple Angel and COL-5 blocks, 2,583, 2,234 + 3,985 sq km resp. in the Caribbean and home to the Kronos, Gorgon + Purple Angel discoveries. Ecopetrol retains 50%:

Shell has acquired a 50% operating stake from Ecopetrol (->50%) in the Fuerte Sur, Purple Angel and COL-5 blocks, 2 583, 2 234 + 3 985km² resp. home to the Kronos, Gorgon + Purple Angel discoveries.

By Q3 2017, Sonatrach was understood to have abandoned its Menzel Ledjmet Centre Nord 1 (MLCN 1) NFW, located on the El Haiad exploration licence in the Berkine Basin. The well was spudded on 3 May 2017 and drilled using the ENAFOR #59 rig. It reached a TD of 3,980m (PTD 4,100m). It was targeting multiple objectives in the Triassic and Carboniferous in a prospect west of the El Kheitt Tessekha Field and NE of the Menzel Ledjmet Centre Field. MLCN 1 is the second well drilled on the block in 2017. The El Merk Devonian 1 (EMKD 1) NPW was P&A dry in April 2017, after reaching a TD of 4,480m. Sonatrach operates El Haiad with 100% equity.

Not Found

Hub 2566-4 EL, onshore Kirthar Fold Belt, spudded Sep ’17, TD 4,555m reached in late Apr ‘18, declared non-commercial gas discovery after DST in May, HL-17 rig.

Hub X-1 (PPL 100%) in the Hub 2566-4 EL onshore block, The well flowed 0,08 MMcfg/d [16/64” choke] during DST and it has been declared as a non-commercial discovery.

According to official reports in late-November 2018, GeoPark has signed an agreement with its partner in Chile and Colombia, LG International (LGI), to purchase all of the latter’s interest in GeoPark’s local operations and subsidiaries. The acquisition price was said to include a fixed payment of USD 81 million payable at closing, plus two equal installments of USD 15 million each, to be paid in June 2019 and June 2020, respectively. Additionally, three contingent payments of USD 5 million each could be payable over the next three years, subject to certain production thresholds being exceeded. In Chile, LGI holds 20% stake in GeoPark’s local subsidiary GeoPark Chile, along with 31% in GeoPark TdF which operates blocks in the Tierra del Fuego region in a partnership with state company ENAP. Earlier in the same month, GeoPark announced its plan to drill two wells on its 100%-held and best producing Fell block as part of its 2019 work program. In addition, the company also plans to test an unconventional oil project on the block in the Estratos con Favrella Formation shale. GeoPark’s 2019 program also includes a new tight gas play in the Tranquilo block, as well as drilling one exploration well with objective of oil in the Isla Norte block. Total investment for the work program is expected to be between USD 17 to 20 million. Background Information GeoPark is the first and largest non-state controlled oil and gas producer in Chile. The company formed a strategic partnership with LGI in 2010 to jointly acquire and develop upstream oil and gas projects in Latin America.

GeoPark has signed an agreement with its partner in Chile and Colombia, LG International (LGI), to purchase all of the latter’s interest in GeoPark’s local operations and subsidiaries.In Chile, LGI holds 20% stake in GeoPark’s local subsidiary GeoPark Chile, along with 31% in GeoPark TdF which operates blocks in the Tierra del Fuego region in a partnership with state company ENAP. Earlier in the same month, GeoPark announced its plan to drill two wells on its 100%-held and best producing Fell block as part of its 2019 work program. In addition, the company also plans to test an unconventional oil project on the block in the Estratos con Favrella Formation shale

On 4 June 2018, ShaMaran Petroleum Corporation announced that it had entered into an agreement to acquire a further 15% working interest in the Atrush Production Sharing Contract (PSC) along with other specified assets, from Marathon Oil KDV BV, for USD 60 million. At the time, ShaMaran stated that the agreement would be effective as of 1 January 2018, subject to the consent of the Kurdistan Regional Government (KRG) and partner Abu Dhabi National Energy Co (TAQA).  However, on 18 November 2018, ShaMaran announced that TAQA had refused to provide consent to the agreement. Subsequently, Marathon re-issued an offer to acquire Marathon Oil KDV BV as a corporate transaction not requiring TAQA consent and, as such, ShaMaran is engaged in a bidding process for Marathon’s 15% interest in the Atrush PSC. ShaMaran has stated that there is no guarantee that any offer by the company, if submitted, will result in the acquisition of the additional 15% interest. As part of the original agreement the KRG had requested guarantees of the company’s commitments, with an approved work program and budgets up to 2020. The acquisition included USD 21.3 million in loans provided to the KRG over 22 months starting 1 January 2018. The new interests in the Atrush PSC would potentially be Abu Dhabi National Energy Co (TAQA) (operator) 39.9%, General Exploration Partners Inc (subsidiary of ShaMaran Petroleum Corporation) 35.1% and Kurdistan Regional Government 25%. The Atrush PSC was initially signed by General Exploration Partners on 10 November 2007, with Atrush 1 being announced as an oil discovery in April 2011. A Declaration of Commercial Discovery was subsequently made on 7 November 2012.

ShaMaran Petroleum Corporation announced that it had entered into an agreement to acquire a further 15% working interest in the Atrush Production Sharing Contract (PSC) along with other specified assets, from Marathon Oil KDV BV, for USD 60 million.

As of late 2017, the Ministry of Mines & Energy of Ethiopia is offering 26 open blocks. Open Blocks in Ethiopia (as of late 2017)             Basin Name Block Name Block Sq km Existing drilling Existing discoveries Existing Explo Surveys Political Province Abbay (Blue Nile) Basin~Amhara Massif Block AB8 12,135 no no no Amara Abbay (Blue Nile) Basin~Amhara Massif Block AB9 12,128 no no no Amara Afar Basin~Mekele Basin~Red Sea Basin~Northeast African Fold Belt Afar 24,570 no no no Afar Afar Basin~Red Sea Basin~Mekele Basin~Ogaden Sub-basin (Somali Basin) Afar Area 63,068 no no 2009 (2D) Afar Amhara Massif Block AB1 * 9,900 no no no Amara Amhara Massif Block AB2 12,069 no no no Amara Amhara Massif Block AB3 12,069 no no no Amara Amhara Massif Block AB4 * 9,900 no no 2011 (seismic) Amara Amhara Massif Block AB7 * 9,900 no no no Amara Amhara Massif~Abbay (Blue Nile) Basin Block AB5 12,109 no no no Amara Amhara Massif~Abbay (Blue Nile) Basin Block AB6 12,109 no no no Amara Amhara Massif~Abbay (Blue Nile) Basin Gambela 157,052 no no 1982 (Gravity/Magnetic),1983 (Gravity), 2008 (Gravity/Magnetic) Binshangul Gumuz Amhara Massif~East African Rift System, Eastern Branch Area 4 3,679 no no no Ye Debub Biheroch Amhara Massif~South Omo Graben (EARS, East Branch) Omo 30,765 2013 (OG Shows), 2013 (G shows), 2014 (2 wells, G shows), no 2007 (G/M), 2011 (2D), 2012 (2D), Ye Debub Biheroch Mekele Basin~Amhara Massif~Northeast African Fold Belt North West 82,514 no no 2008 (Gravity/Magnetic) Amara Mekele Basin~Northeast African Fold Belt~Amhara Massif Metema 29,793 no no 2010 (Gravity/Magnetic) Binshangul Gumuz Mudugh Sub-basin (Somali Basin)~Ogaden Sub-basin (Somali Basin) Block 21 6,149 1955 (OG Shows) no no Sumale Ogaden Sub-basin (Somali Basin) Block 01 12,207 1974 (dry) no Unknown (2D), Oromiya Ogaden Sub-basin (Somali Basin) Block 05 18,299 no no 1976 (Gravity/Magnetic), Oromiya Ogaden Sub-basin (Somali Basin) Block 06 12,232 no no Unknown (2D),  1969 and 2007 (Gravity/Magnetic) Oromiya Ogaden Sub-basin (Somali Basin) Block 10 12,207 no no 1989 (2D) Sumale Ogaden Sub-basin (Somali Basin) Block 14 12,207 no no 1962 (2D), 1963 (Gravity/Magnetic). 1992 (2D) Sumale Ogaden Sub-basin (Somali Basin)~Mandera-Lugh Sub-basin (Somali Basin) Block 02 12,232 no no no Oromiya Ogaden Sub-basin (Somali Basin)~Mandera-Lugh Sub-basin (Somali Basin) Block 07 12,254 1974 (dry) no 1969 and 2007 (Gravity/Magnetic), 1972 (2D), 1973 (2D),  2010 (2D) Sumale Ogaden Sub-basin (Somali Basin)~Mudugh Sub-basin (Somali Basin) Block 18 12,232 1950 (dry), 1955 (2 wells, dry) no 1962 (G/M), 2009 (2D), 2008 (G/M), 2015 (G/M), 2015 (2D) Sumale Ogaden Sub-basin (Somali Basin)~Mudugh Sub-basin (Somali Basin) Block 19 6,538 1963 (dry) no 1961 (2D), 1962 (G/M), 1963 (G/M and 2D) Sumale Source: IHS Markit © 2018 IHS Markit NOTE: (*) Blocks "under negotiation" according to the Ministry of Mines & Energy, 2017   For further details, interested companies are invited to contact: Mr. Ketsela Tadesse Head of Petroleum Operations Department Ministry of Mines & Energy 486 Addis Ababa, Ethiopia Phone: + 251 11 646 12 09 Fax: + 251 11 646 34 39 Petroleum contracts are in the form of Model Production Sharing Agreement of 1994 between the government of Ethiopia, represented by the Minister of Mines and Energy, and a contractor. The contracts have an initial exploration term of four years and an optional two year term, with two possible further exploration periods of two years (4+2+2). The development and production period is of 25 years. The minimum exploration and expenditure obligations are negotiable. The signature and production bonuses are also negotiable. The income tax is 30%.

Ethiopia, Afar (Gewane-El Wiha)

In December 2017, local sources reported that Sinopec International Petroleum has completed its El Huemul 4301 outpost as an oil well at the approximated total depth of 3,200 m (10,500 ft) on the El Huemul-Koluel Kaike block after it flowed 65.4 bo/d from the Pozo D-129 Formation during testing. The El Huemul-Koluel Kaike block covers 603.8 sq km of onshore land in San Jorge Basin. The well was spudded in late-February 2017, with original target in the shallower Lower to Middle Albian Mina El Carmen Formation.

Argentina (San Jorge B.) El Huemul 4301 op. by SIPC (100.0%) in El Huemul-Koluel Kaike block

Capricorn plugged and abandoned dry the Alom 1SON directional stratigraphic new-field wildcat (NFW) in the CNH-R02-L01-A9.CS/2017 PSC contract, Area 9 block during late-October 2019. Parent company Cairn issued a press release on 28 October 2019 indicating the targeted Pleistocene sandstones were 500 m thick but water bearing. The well reached a final total depth (TD) of 2,056 m. The NFW was spudded on 17 September 2019. The well had an estimated proposed total depth of 2,629 m measured depth (MD) and 2,332 m true vertical depth (TVD). It was targeting stacked, DHI supported Pleistocene sandstones starting at 1,550 m. The well was drilled by the “Maersk Developer” S/S in a water depth of 115 m. The unrisked prospective resources now reported for the Alom prospect is 140 MMboe. The drilling cost of the Alom 1SON is estimated to be USD 36 million and the completion cost estimated to be USD 4 million. The CNH granted a drilling permit to Capricorn for the Alom 1SON well on 17 September 2019. Capricorn is operator of the contract and has 50% working interest, Citla has 35% working interest, and ENI holds 15% working interest pending formal governmental approvals for its farm-in. On 10 September 2019, Cairn reported with its 1st half 2019 results that it swapped 15% working interest with ENI with ENI entering the CNH-R02-L01-A9.CS/2017 contract operated by Cairn subsidiary Capricorn, and Cairn acquiring a 15% working interest in the ENI operated CNH-R02-L01-A10.CS/2017 contract. Capricorn Energy is operator of the CNH-R02-L01-A9.CS/2017 contract and held 65% working interest and Citla Energy has 35% working interest. Cairn reported it now has 50% working interest, Citla has 35% working interest, and ENI holds 15% working interest. In the ENI operated CNH-R02-L01-A10.CS/2017 contract, ENI held 80% working interest and Lukoil had a 20% working interest. ENI now holds a 65% working interest, Lukoil 20% working interest, and Capricorn holds 15%.The deal is pending formal approvals. On 16 May 2019, the CNH approved a modified exploration plan for the Capricorn operated CNH-R02-L01-A9.CS/2017 PSC contract, Area 9 block involving only changes to the drilling schedule of prospects and a change in the proposed budget. From its November 2018 approved exploration plan Capricorn had planned to drill the Bitol-Kukulkan prospect first and the Alom prospect second. This has been changed to drilling the Alom prospect first and the Bitol-Kukulkan prospect second. The second modification in the exploration plan is an increase in the well drilling budget.The total budget approved for the exploration plan is USD 125.85 million.The estimated drilling expenditures for the two commitment wells increased from USD 105.21 million to USD 113.20 million. The Alom prospect is to be drilled first and has an estimated proposed total depth of 3,000 m in a water depth of 140 m.It is targeting stacked, DHI supported Pliocene sandstones starting at 1,550 m.The prospective resources now reported for the Alom prospect is 103 MMboe.The overlapping Bitol and Kukulkan prospects have been merged into one prospect, Bitol-Kukulkan, as reported by the CNH.The NFW will be drilled directionally to an estimated proposed total depth of 5,300 m in a water depth of 180 m.It is targeting stacked Pleistocene, Pliocene, and Upper and Lower Miocene sandstones from 765 m to 3,980 m.The prospective resources now reported for the Bitol-Kukulkan prospect is 261 MMboe. Parent company Cairn contracted the “Maersk Developer” S/S to drill its commitment wells commencing in 3rd quarter 2019. On 12 March 2019, Capricorn published a presentation updating its plans to drill two new-field wildcats (NFW) in its operated CNH-R02-L01-A9.CS/2017 PSC contract, Area 9 block during 3rd and 4th quarter 2019.The partners have five scenarios of prospects to drill with the primary prospect now reported to be Alom and Bitol. The operator reported in mid-March 2019 that the Alom prospect, located in the south-eastern corner of the block has 140 MMboe in prospective resources and is targeting a DHI supported Pleistocene stacked reservoirs.The proposed total depth (PTD) for the Alom 1EXP is 3,000 m in an approximate water depth of 140 m. The Bitol 1EXP is a directional new-field wildcat (NFW) prospect located in the south-western area of the block and has a PTD of 5,300 m.The well will target the Miocene in an approximate water depth of 180 m and has 180 MMboe estimated prospective resources On 27 November 2018, the CNH approved the first budget and exploration plan for the Capricorn operated CNH-R02-L01-A9.CS/2017 PSC contract, Area 9 block from the CNH-R02-L01/2016 Bid Round.The approved exploration plan includes geological and geophysical studies and plans for two firm commitment exploration wells to be drilled in 2019. The total budget approved for the exploration plan is USD 123.18 million.The estimated two commitments well cost is USD 68.18 million.The total work unit commitments proposed is 66,960 work units, above the minimum of 61,100 work units committed to. On 25 September 2017, the CNH signed the final award contract with the consortium of Capricorn Energy Ltd (Cairn), and Citla Energy E&P S.A.P.I. de C.V. for the CNH-R02-L01-A9.CS/2017 PSC contract, Area 9 block from the CNH-R02-L01/2016 Bid Round.On 19 June 2017, the consortium of Capricorn Energy Ltd (Cairn), and Citla Energy E&P S.A.P.I. de C.V. was the high bidder in the CNH-R02-L01/2016 Bid Round for the Area 9 block in the Sureste Basin and was granted a preliminary award.There was a tie in the bidding for the block between ENI and the consortium of Capricorn and Citla each bidding the maximum of 75% state participation and a 1.5 work unit factor.The Capricorn consortium won the tie-break with a bonus offer of USD 30,003,333.33 versus the ENI offered bonus of USD 20,470,500.00. The consortium offered 54.9% additional state take participation above the minimum 20.10% for a maximum total state take participation of 75.00%.The minimum work commitments were 2,500 units equivalent to USD 2,500,000 at an oil price between USD 45 to USD 50/bbl.The consortium offered an additional work unit factor of 1.5 equivalent to two wells with a value established by the CNH in the bid documents of 29,300 or USD 29.3 million at an oil price between USD 45 to USD 50/bbl. The total work commitment therefore is estimated to be USD 61.1 million plus the bonus payment of USD 30.0 million is a total financial commitment of USD 91.1 million.There were five other bids for the block.The 3rd highest bidder was the consortium of Chevron, PEMEX, and Inpex who bid total state take of 70.45% and a 1.5 unit work factor. The general PSC contract terms include a 1st exploration period of four years with the possibility of a two-year extension.Relinquishment of the entire contract area is required if there is no evaluation or development plan filed for any discoveries.There is the possibility of a 2nd exploration period of two years with 50% relinquishment if committing to one exploration well and 0% relinquishment if committing to two exploration wells in the extension period.If a discovery is made there is an evaluation period of two years.The development phase is for approximately 22 years from the date of an approved development plan with two possible five-year extension periods.The maximum contract term is 40 years.Local content during the exploration period is 15%, 17% for the evaluation period, and 26% during the first year of the development period until 2025 when it increases to 35%.A variety of taxes and fees apply to the PSC contract.There is a maximum 60% cost recovery with an adjustment mechanism.

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

OMV has completed the acquisition of a 24.99% share in the Yuzhno Russkoye natural gas field located in Western Siberia from Uniper following fulfillment of all closing conditions including regulatory and co-shareholder approvals. The purchase price paid by OMV to Uniper amounts to EUR 1,719 mn and includes customary closing adjustments. The transaction takes retroactive economic effect as of January 1, 2017 and was largely funded out of proceeds generated from disposals and OMV’s strong cash flow. Rainer Seele, Chairman of the OMV Executive Board and CEO: 'The closing of this landmark transaction is a further milestone in OMV´s successful delivery on its corporate strategy to establish Russia as a new core region of OMV. Our stake in Yuzhno Russkoye adds 100,000 boe/d to OMV´s production. This boosts OMV´s total production to more than 430,000 boe/d.' Johann Pleininger, OMV´s Deputy CEO and Board Member Upstream: 'With this acquisition OMV gets additional recoverable reserves of 580 mn boe. In addition, our production costs will be further decreased.' The Yuzhno Russkoye field is one of the largest gas fields in Russia, situated in the Yamal-Nenets region. Current plateau production of the field amounts to 25 bn cubic meters per year (100%). The license will expire by the year-end 2043. Original article link Source: OMV

Russia, not found

Hitherto-unreported, earlier this year ONE-Dyas picked up a 40% share + operatorship from Wintershall Dea in B20008/71, 2,660 sq km offshore along the border between the Netherlands – Germany. Partnership has become ONE-Dyas (op), Neptune Egy + Discover Expl.

ONE-Dyas acquired a 40% op. WI in the B20008/71 (2660km²) contract offshore North Sea, from Wintershall Dea (->0%, Neptune Egy 40%, Discover Explo 20%).

Vainateyam A ML, KG offshore, WD, ops terminated late Aug ’18 at TD 2,855m, Aban II JU.

GS-15 AS-ST (GS-15-20 ST) Vainateyam A ML, KG offshore, WD, ops terminated results n/a.

On 2 March 2020 Spirit Energy announced the proposed divestment of three licences containing the Hejre and Solsort fields to INEOS. The deal is subject to governmental approval. The HPHT Hejre discovery is in the 5/98 licence (blocks: 5603/24a, 5603/28b, 5604/21b and 5604/25b), which INEOS will hold 100% interest in after it acquires the 15% and 25% interest from Spirit Energy Danmark ApS and Spirit Energy Petroleum Danmark AS. The Solsort discovery is in the 4/98 and 3/09 licences (blocks: 5604/25b Solsort, 5604/26 Solsort, 5604/26a Solsort and 5604/30a Solsort), which INEOS will acquire 30% interest in from Spirit Energy Danmark ApS. The southeast section of the Solsort discovery extends into the neighbouring 7/89 South Arne licence which is operated by Hess. In January 2019 it was understood that INEOS were evaluating the possible development scenarios for the Hejre field, this could include the combined development of Hejre and Solsort fields. The Hejre HPHT (1,011 bar and 160 degrees Celsius) oil and gas discovery was made in 2001 by the Hejre-1 well and appraised in 2004 by Hejre-2. The reservoir is in the Upper Jurassic Heno Formation at approximately 5,200 m. The previous operator (DONG) commenced development work on the field using contractors Technip France SAS, partnered by Daewoo Shipbuilding and Marine Engineering Co. Ltd (DSME) for the engineering, procurement, fabrication, hook-up and commissioning assistance of the Hejre wellhead and processing platform. A 8000-tonne jacket was installed in 2014 and five development wells were drilled between and March 2016. The field development ceased in 2016 when DONG terminated the contract for the platform after a dispute with the contractor over delays in the topside and platform. In September 2017 INEOS acquired DONG Energy and took over its 60% interest in the licence and in December 2017 Spirit Energy was formed from the merger of Centrica and Bayern Norge AS to take 40% interest in the licence. The Solsort oil and gas field was discovered by Solsort 1 (6504/26-5) in 2010, the TD was at 3,041 m TVDSS and three sidetracks were drilled with a reach of up to 1.5 km. In 2013 the discovery was successfully appraised by Solsort 2 (5604/26-6) which tested oil and associated gas from the Paleocene Rogaland Group sandstone. Two sidetracks were drilled from Solsort 2 but both were dry.

Spirit Energy has signed an agreement to sell two "non-core" Hejre (40%) and Solsort (27.7%) assets to Ineos.

AleAnna has taken over Cygam’s 100% in the 206-sq km San Patrizio application in Emilia-Romagna. The block covers the E. part of the former Massa Lombarda permit. This follows the dissolution of Cygam in Nov ‘16.

AleAnna has taken over Cygam’s 100% in the 206-sq km San Patrizio application. The block covers the E. part of the former Massa Lombarda permit.

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%).

KrisEnergy is offering a farm-in opportunity consisting of 44.5% participating interests in G10/48, located in the Pattani Trough (Gulf of Thailand Basin). The concession surrounded with five oil fields, including the Wassana field that was brought onstream in August 2015. As of April 2018, the operator is focusing on the development of the Greater Wassana area which consists of Wassana Satellite and Mayura areas. The Wassana satellite at the north of the field is expected to come onstream in 2H of 2019. The development will be tied back to the existing facilities with potential ramp up production to 12,000 b/d of oil. The field has been producing from a series of stacked Miocene fluvial sand at 4,500 to 6,000 bo/d in 1Q of 2018.   The G10/48 concession is in production period of 20 years which commenced on 7 December 2015. The Wassana production area was approved by the Thailand Department of Mineral Fuel (DMF) on 9 February 2015. On 8 December 2015, DMF has also approved an “Exploration Reserved Area” of approximately 1,525 sq km, comprising contiguous and non-contiguous to the Wassana production area, for up to five years. The operator has also identified over 50 mapped prospects and leads which would assigned un-risked oil in place of 1.4 BBL to the concession. KrisEnergy holds the operatorship with 89% participating interest in the G10/48 concession since May 2014. Local company Palang Sophon Ltd holds the remaining 11% interest following the acquisition of an indirect 14.67% interest in KrisEnergy G10 (Thailand) Ltd, which holds 75% interest in the concession, in February 2015. For further information, interested parties may contact: James Parkin VP Exploration [email protected] or Mike Whibley VP Technical [email protected] Background Information      The G10/48 concession was originally awarded to Pearl Oil in December 2006. The concession is situated at the southern section of the Pattani Basin in water depth of 60 m, containing a producing field, Wassana (2009) and four oil discoveries – Niramai (2009), Mayura (2010), Nong Yao Southwest 1 (2012) and Rayrai (2015). The Wassana field is one of the most matured assets for KrisEnergy in the Gulf of Thailand. The discovery well, Wassana 1 was drilled in 2009 to a TD of 1,705m, targeted Miocene sandstones of the Pattani II/III units. The discovery is followed with a series of successful appraisal wells during 3Q 2010. Wassana 2, Wassana 2ST1 and Wassana 3 were drilled to total depths of 2,005 m – 2172 m. All three wells encountered oil. KrisEnergy acquired operatorship in the G10/48 concession from Mubadala (which had acquired Pearl Oil) in May 2014. The company approved the Final Investment Decision (FID) for the Wassana development in late June 2014. A converted Bethlehem Matt Type jack-up rig was employed as a Mobile Offshore Production Unit (MOPU) which is suitable for water depth of around 65 meters and has full hydrocarbon processing facility for up to 20,000 b/d of oil and a water injection capacity of 15,000 b/d. The last exploration activity in the concession is the drilling of Wassana 4/ST in late-February to mid-March 2018. The well was drilled to a TD of approximately 1,703 m (-1665 m TVD) and encountered approximately 20 m of net oil pay. The original borehole, Wassana-4 encountered net vertical oil pay of 9.4 m true vertical thickness (TVT). It was drilled back-to-back after the completion of five infill development wells in Wassana Production Area. The concession is covered by 728 line-km and 1,814 sq km of 2D and 3D seismic data respectively, from four different surveys. Total recoverable reserves in the field have been estimated at 14 MMbbl of oil (2P). Contingent resources were estimated at 1.2 - 2.23 - 4.52 MMbbl of oil (1C-2C-3C). Wassana is the first field brought on production by KrisEnergy as operator. The field came onstream on 14 August 2015 at an initial rate of 4,000 b/d from three initial wells. Production is achieved through the “Ingenium” MOPU and crude is stored in the “Rubicon Vantage” FSO. The field achieved it target to reach the plateau rate of 10,000 b/d by end of 2015. Production at the field peaked at around 12,800 bo/d, above the originally forecast plateau rate, and had levelled off to 11,060 bo/d in end of January 2016.

KrisEnergy is offering a farm-in opportunity consisting of 44.5% participating interests in G10/48, located in the Pattani Trough (Gulf of Thailand Basin).

Wintershall Dea used the “West Hercules” S/S to drill exploration well 6611/1-1 on the Toutatis prospect in PL 896. The well was spudded on 2 November 2019 and targeted the Lower Jurassic Tilje (prognosed at 1,360 m) and Are (prognosed at 1,562 m) formations. Toutatis lies in the northeastern part of the Norwegian Sea in the Vestfjord Basin. It was drilled to TD at 1,905 m in the Triassic and has made a minor oil discovery of under 6 MMbo (non-commercial). A 7 m oil-bearing sandstone was present in the upper part of the Jurassic sequence (not yet dated) and 200 m of water-bearing sandstone was found in the Tilje and Are formations. On 24 November 2019 the well was abndoned. This area of the Norwegian Sea has seen little drilling. The closest well is 6610/3-1 (in the adjacent block to the west of Toutatis). This well and 6610/2-1 S were both drilled by Statoil and both encountered oil and gas shows in the Cretaceous (the Nise, Lysing and Lange formations in 6610/3-1, and the Lysing Formation in 6610/2-1 S). In 6610/3-1 the Tijle Formation sandstone was tightly cemented and in 6610/2-1 S this interval was mostly silt and mudstone. Upon completion of a deal, Wintershall Dea Norge AS will operate PL 896 with a 30% interest. It will be partnered by Lundin Norway AS (30%), Equinor Energy AS (20%) and Petoro AS (20%).

6611/01-01 (Toutatis) (Wintershall Dea 40% op, Equinor 20%, Lundin 20%, Petoro 20%) in PL 896, off Lofoten islands, ops terminated early, P&A, intersected a total of about 200m of sst, 7m oil-bearing sst in the upper part of the assumed Jurassic sequence, although the main targets (Tilje + Åre fm’s ) were water-bearing. Est. < 6,5Mmbo recoverable, operator has decided not to exercise an option for a sidetrack at the well. WD=357m, TD= 1874m ss (Triassic).

Committed well, deeper stacked Cretaceous/Jurassic prospect in NW Sitra block, Abu Gharadiq Basin, W. Desert, P&A dry at TD 4,024m, Shams-2 rig. Targets Bahariya, Abu Roash, Safa + Ras Qattara. A drill-or-drop applies in Jan ’19,  2 wells required if extended along with a 30% area reduction.

Egypt, Abu Gharadiq (Dev)

PL 146, Cooper Eromanga, drilled 25 Sep – 2 Oct '19, susp. gas at TD 2,079m (some oil shows). Santos (op), partners Origin + Beach.

Wackett E.-1 expl/appr in PL 146, susp. gas at TD 2,079m (some oil shows). Santos (op), partners Origin + Beach.

CNH-R02-L01-A9.CS/2017, SE part of block 9, WD 115m, 1st in 3-well programme in blocks 7 & 9, offshore Sureste Basin, TD 2,056m (Pleistocene), P&A dry, Mærsk Developer SS. To be followed by Bitol-1, WD 180m, PTD 5,300m, target Miocene, spudding Nov '19. Capricorn (op), partners Citla + Eni. Block 7 is run by Eni op, partners Capricorn + Citla.

Alom 1 nfw. (Cairn 50% op. Citla Energy 35%, Eni 15%) in CNH-R02-L01-A9.CS/2017, SE part of block 9, WD 115m, 1st in 3-well programme in blocks 7 & 9, TD=2056m (Pleistocene), P&A dry, encountered 500m of, high-quality, water bearing sands across multiple targets.

Noble Energy has signed a definitive agreement with SRC Energy to divest approx. 30,200 net acres from the Company's non-core DJ Basin position in Weld County, Colorado.  Included with the acreage sold is approx. 4,100 barrels of oil equivalent per day (Boe/d).  The total value of the transaction is $608 million.  The transaction, effective as of November 1, 2017, is anticipated to close on two separate dates, with acreage and non-operated production included in the initial closing by the end of 2017, followed by a second closing for operated producing properties by mid-2018.  The closings are subject to customary terms and conditions, with the initial closing representing over 90 percent of the total transaction value. Gary W. Willingham, Noble Energy's Executive Vice President, Operations, commented: 'This sale of acreage in our Greeley Crescent and Bronco development areas represents an acceleration of value as it was not likely to be developed by us for a number of years.  Our DJ Basin activities, both now and for several years to come, will remain focused on the northern and eastern parts of the basin.  This is where we have a deep inventory of long lateral drilling opportunities in an oilier part of the basin and where our infrastructure provides a competitive advantage.  Proceeds from this transaction continue to highlight a strong market valuation for our DJ Basin position and will be prioritized to further strengthen our investment-grade balance sheet.' Approx. 50 percent of the acreage is located in the Company's Greeley Crescent area and the remainder is in the Bronco area. (See map) Noble Midstream Partners maintains the acreage dedication for in-basin oil gathering, produced water gathering and fresh water delivery. Non-operated production associated with the transaction totals approximately 2,500 Boe/d. Operated production, assumed at the time of the second closing, is estimated to be 1,600 Boe/d.  The commodity mix of the production divested is 20 percent oil, 30 percent natural gas liquids, and 50 percent natural gas.  The acreage and production divested represent approximately eight percent and four percent, respectively, of the Company's totals in the DJ Basin.  Post transaction close, Noble Energy's DJ Basin position will be approx. 335,000 net acres. Tudor, Pickering, Holt & Co. acted as the lead financial advisor, and Bracewell LLP acted as outside legal advisor to Noble Energy on the transaction. Original article link Source: Noble Energy

SRC Energy has agreed to acquire a 30 200 net acres in the state of Colorado from Noble Energy for US$608 MM. Included are ab. 4100 boe/d.

Sound has initiated a formal farmout process for its4,499-sq km Sidi Moktar licence in central Morocco. Following receipt of Ministerial Approval to the Sidi Moktar award last February, completion of technical work and a recent significant inbound 3rd party interest, Sound is now looking to fund the forward 2018 work programme whilst retaining operatorship.  Currently Sound (op), Onhym 25% partner.

Sound has initiated a formal farmout process for its4,499-sq km Sidi Moktar licence in central Morocco. Following receipt of Ministerial Approval to the Sidi Moktar award last February, completion of technical work and a recent significant inbound 3rd party interest, Sound is now looking to fund the forward 2018 work programme whilst retaining operatorship. Currently Sound (op), Onhym 25% partner.

Equinor Energy do Brasil Ltda suspended with oil shows the Carcara West (3-EQNR-001-SPS) outpost in the N_CARCARA block, Norte de Carcara_P2 contract of the Santos Basin during early-February 2019.  The operator reached a final total depth (TD) of 6,539 m on 13 December 2018.  The operator filed a second oil show report with the ANP for the well on 27 December 2018 after filing a first oil show report on 26 November 2018.  It is speculated that some type of testing took place during the December to February interval when operations on the well was finally concluded. The outpost was spudded on 13 September 2018. The well had a proposed total depth (PTD) of 6,669 m and the Aptian Barra Velha Formation was the primary target. The well was drilled by the “West Saturn” D/S in a water depth of 2,052 m.   This is the first well in a possible program of five wells permitted for the block in April 2018. The outpost is located in the south central area of the block and approximately 5 km north-west of the 3-BRSA-1290-SPS located in the BM-S-008 contract.  It is also located 9 km to the north of the 4-SPS-086B-SPS Carcara prospect oil and gas discovery made by Petrobras in 2012 at a total depth (TD) of 6,671 m.    Current working interest breakdown in the contract is Equinor Brasil operator with 40% working interest, ExxonMobil with 40% working interest, and Petrogal Brasil Ltd (Galp Energia) with a 20% working interest. Equinor Brasil Energia Ltda has plans to drill up to five exploration wells in the Norte de Carcara_P2 contract, N_CARCARA block after filing its environmental permit in April 2018.  The Norte de Carcara structure is a northern continuation of the Carcara structure discovered by Petrobras and now operated by Equinor Brasil and partners in the BM-S-008 contract.  The wells to be drilled may all be considered outpost wells.  They will have proposed total depths of approximately 6,500 m to 7,000 m and will target the Barra Velha and Itapema formations of the pre-salt series in the Santos Basin.  The drilling is expected to commence in the block during early-2019.  The A prospect is located about 5.7 km north north-east of the 3-SPS-104A (3-BRSA-1216DA-SPS) outpost. On 31 January 2018, the consortium of Equinor Brasil Energia Ltda operator with 40% working interest, ExxonMobil with 40%, and Petrogal with 20% was granted an official award for the 312.92 sq km Norte de Carcara block from the 2nd PSC Pre-Salt Bid Round. The ANP changed the official denomination of the block to the Norte de Carcara_P2 contract, N_CARCARA block.  The consortium won the block with a profit oil state take bid of 67.12% and USD 911.85 million in total fixed bonus to be paid to the Brazilian government based on the USD to BRL exchange rate of the day of 1USD/3.29 BRL.  The PSC contract has a three year exploration-evaluation phase and the minimum work program is to drill one appraisal well. The minimum financial guaranty for the three year period is USD 47.95 million which is less than the estimated cost of drilling a pre-salt appraisal well.  There was a 2nd place bid for the block by Shell (100%) offering a state take bid of 50.46%.  The working interest breakdown for the block is the same as in the BM-S-008 contract that will be unitized with the Norte de Carcara block after Equinor acquired the 10% working interest from Barra Energia in June 2018.

3-EQNR-001-SPS outpost (Equinor op. 40%, ExxonMobil 40%, Petrogal 20%) in the N_CARCARA block, Norte de Carcara_P2 contract, suspended with oil shows. The operator filed a second oil show report with the ANP for the well on 27 December 2018 after filing a first oil show report on 26 November 2018. It is speculated that some type of testing took place during the December to February interval when operations on the well was finally concluded.

Santos Ltd plugged and abandoned the Gidgealpa South 1 exploration well in PPL 06, located in the Cooper-Eromanga Basin, on 12 May 2020 after encountering gas shows. The well, which spudded on 5 May 2020, was drilled by the Ensign "967" land rig to a total depth of 2,402 m. The well was drilled to the south of the Gidgealpa field, which was discovered in 1964 and has been producing since 1969. The license also covers the Mawson and Kurunda gas fields, located west of Gidgealpa South 1. PPL 06, which covers an area of 257 sq km, was awarded on 1 January 1975. Participants in the permit are, through various subsidiaries, Santos Ltd (66.6% plus operator) and Beach Energy Ltd (33.4%).

Gidgealpa South 1 nfw (Santos op) was drilled to a TD of 2,402m MD in PPL 6 block and was plugged and abandoned on 12 May 2020, having encountered gas shows in the target reservoirs. Cooper Eromanga Basin. Santos Ltd (40.7% + Operator), various Santos subsidiaries (25.9%) Delhi Petroleum Pty Ltd, a Beach Energy subsidiary, (20.21%) and Beach Energy (Operations) Ltd (13.19%).

Further to DEA 8 Feb ’18: Bukhari ML (Badin I), Lower Indus onshore, TD 2,976m, tested 3 MMcfg/d on 8/64” choke. Target Lower Goru. TCPDC-4002 rig.

Tharo West 1 op. by UEPL (100%) in the Bukhari ML (Badin I) gas disc. tested 3 MMcfg/d on 8/64” choke. Target Lower Goru. TD=2976m.

On 18 June 2019, the State Agency for Geology and Subsoil Use of Ukraine held an auction for seven licenses in the western and eastern Ukraine. Competing against some small local companies, Ukrgazvydobuvannya (UGV) emerged as the winner for all offered blocks. The company will obtain 20-year E&P licenses. The Kokhivska block covers 346 sq km in Kharkiv Oblast (Dnieper-Donets Basin). Seismic coverage amounts to 547 km. No wells have been drilled in the block. Gas resources of the Novodachynska prospect are estimated at 15 Bcf. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 2.66 million (USD 0.1 million). UGV offered UAH 2.7 million (USD 0.1 million). The Rozdolivsko-Uspenivska-1 block covers 271 sq km in the Dnieper-Donets Basin. Seismic coverage amounts to 310 km. No wells have been drilled in the block. Gas resources of the Rozdolivska prospect are estimated at 63 Bcf. Unlocated gas resources of the block are estimated at 60 Bcf. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 6.81 million (USD 0.25 million). UGV offered UAH 6.91 million (USD 0.25 million). The Rozdolivsko-Uspenivska-2 block covers 296 sq km in the Dnieper-Donets Basin. Seismic coverage amounts to 433 km. No wells have been drilled in the block. Unlocated gas resources of the block are estimated at 60 Bcf. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 3.1 million (USD 0.11 million). UGV offered UAH 3.16 million (USD 0.11 million). The Orilsko-Brusivska block covers 235 sq km in the Dnieper-Donets Basin. Seismic coverage amounts to 1,355 km. Six wells have been drilled in the block. Gas resources of the Brusivska prospect are estimated at 87 Bcf. Unlocated resources of the block are estimated at 9 MMbbl of oil equivalent. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 23.11 million (USD 0.86 million). UGV offered UAH 23.51 million (USD 0.9 million). The Goshivska block covers 49 sq km in Ivano-Frankivsk Oblast (Pre-Carpathian Foredeep), west of the Dolyske field. Seismic coverage amounts to 142 km. Five exploratory wells have been drilled in the block and oil flows were tested in several of them. Resources of the block are estimated at 4 MMbbl of oil equivalent. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 19.25 million (USD 0.7 million). The Yasenska block covers 35 sq km in Ivano-Frankivsk Oblast (Pre-Carpathian Foredeep), west of the Lukvynske field. Seismic coverage amounts to 138 km. Eight exploratory and appraisal wells have been drilled in the block and oil flows were tested in several of them. Resources of the block are estimated at 3 MMbbl of oil equivalent. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 18.83 million (USD 0.7 million). UGV offered UAH 19.03 million (USD 0.7 million). The Bolekhivsko-Smolyanska block covers 10.39 sq km in Ivano-Frankivsk Oblast (Pre-Carpathian Foredeep), north of the Dolyske field. Seismic coverage amounts to 61 km. Resources of the block are estimated at 0.4 MMbbl of oil equivalent. Commitments include re-processing of existing seismic data, acquisition of 2D or 3D seismic data covering at least a quarter of the block and drilling of one well. The starting price amounted to UAH 2.45 million (USD 0.09 million).

UGV (Ukrgazvydobuvannya) emerged as the winner for all 7 offered blocks proposed for the auction on 18 June 2019.

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: [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. Mean recoverable prospective resources are estimated at 130 MMbo. The licence was awarded in the 7th Danish Licensing Round in April 2016.

In early September 2017, US-based Hupecol Operating Co LLC (Hupecol) acquired 100% WI in the Llanos Basin CPO-11 block from state-company Ecopetrol. The farm-out agreement was signed in 2016 and it appears that Hupecol funded a number of wells in the transfer period including the Venus-2A appraisal well. which produced an average of 332 bo/d in September 2017 during extensive testing. Ecopetrol made the Venus-2 heavy oil discovery in the south western portion of the block in 2013. That well tested 630 b/d of 17-degree API crude with a water cut of 39% from Oligocene basal sands (likely Carbonera Formation). The well reached a total depth of 1,312m on 6 February 2013. In April 2014, the successful Venus-3 ST1 appraisal well was followed in May 2014 by the Venus-4 appraisal (P&A, assumed dry). Hupecol is also thought to have drilled two NFWs called Tamanaco-A1 & Tamanaco-B1 in 2016-2017. Hupecol P&A'd the Tamanaco-1 NFW in the centre of the block in early 2000 to a TD of 1484m.

Hupecol acquired 100% WI in the CPO-11 block from state-company Ecopetrol.