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Lundin Petroleum has announced that its wholly owned subsidiary Lundin Norway has successfully completed the Luno II appraisal well 16/4-11 in PL359 on the Utsira High in the Norwegian North Sea.The appraisal well was located approx. 2.5 km south of the original Luno II discovery well and is the fifth well on the Luno II oil discovery. The main objective of the appraisal well was to prove additional resources in the Luno II discovery to progress to development.The appraisal well encountered a gross oil column of 22 metres in Triassic sandstone with very good reservoir quality, which is significantly better than expected. The oil-water contact was encountered at 1,947 metres below the sea surface. The entire reservoir, including the water zone, consists of sandstones with some conglomeratic sandstone intervals with a total thickness of about 400 metres. Extensive data acquisition and sampling have been carried out in the reservoir, including conventional coring and fluid sampling.Following these positive well results, the previous gross resource range for the Luno II discovery of 30 to 80 MMboe has been increased to between 40 and 100 MMboe. Development studies for Luno II will now be progressed with the objective of submitting a PDO around the end of 2018. The development concept for Luno II is a subsea tie-back to the nearby Edvard Grieg platform.Lundin Norway completes successful appraisal well on Luno IILundin Norway is the operator of PL359 with a 50 percent working interest. The partners are OMV with 20 percent and Statoil and Wintershall with 15 percent each.After completion of the Luno II appraisal well, the semi-submersible drilling rig COSL Innovator will proceed to drill appraisal well 16/1-28S on the nearby Rolvsnes oil discovery in PL338C. The main objective is to confirm commercial rates from a horizontal well that will be drilled in fractured and weathered basement reservoirs similar to the reservoirs currently producing in the northern area of the Edvard Grieg field. Rolvsnes is also considered a potential tie-back development to Edvard Grieg and success will further de-risk the larger area prospectivity, estimated to contain gross resources of more than 200 MMboe. Drilling and testing at Rolvsnes is expected to take 115 days.Lundin Norway is the operator of PL338C with a 50 percent working interest. The partners are Lime Petroleum with 30 percent and OMV with 20 percent.Click here for NPD announcement (with location map): Delineation of the 16/4-6 S (Luno II) oil and gas discovery in the North Sea - 16/4-11Original article linkSource: Lundin Petroleum

Norway (Utsira High (Horda Platform)) Rolvsnes

Kina Petroleum Corp is offering an opportunity for a farm-in partner to acquire equity in exploration licence PPL 437, located in the Papuan Basin. Kina holds 57.5% interest and operatorship in the permit with partner Heritage Oil (42.5%). Kina is seeking a partner in return for funding an upcoming work programme which would ideally include much needed 2D seismic acquisition. In early-January 2020, Kina reported that, along with Heritage, it was in discussions with a potential farminee. Heritage is looking to divest its entire 42.5% interest in PPL 437. As part of a portfolio review, the company no longer sees Papua New Guinea as a core growth region and is thus looking to exit the country. PPL 437 is located immediately north of the Elevala and Ketu fields which lay in Horizon’s operated PRL 21. Kina considers the Malisa Prospect as drill ready and the permit also contains Ebony, Mango and Ketu North prospects. Kina has submitted a permit extension application to the Department of Petroleum in a bid to continue exploration past the due expiry date of 18 February 2019. Under an extension, Kina would like to acquire seismic along the Mango, Ebony and Kandis prospects ahead of constraining and ranking. Malisa has the potential for gas within the Kimu and Elevala/Toro formations, with Heritage reporting that it could contain 2P prospective recoverable resources of 280 Bcf gas. The licence lies in close proximity to the Elevala, Ketu, Stanley, P’nyang and Juha discoveries, meaning opportunities for development through the proposed Western LNG project or third party access to the considered P’nayng to Kutubu pipeline, should a discovery be made. A total 170.4 km of 2D seismic was acquired over Malisa in 2014 during the Gosur Survey. Interpretation of this data was reported to be completed in 2H 2017, along with integrated aerogravity data. Initial results show significant prospectivity in the east of the permit. In addition, vintage seismic data has been reprocessed within the licence, which is now complete and fully interpreted. Once the Malisa data and reprocessed vintage seismic data have been merged, farm-in conditions and equity level will again be assessed prior to pushing the opportunity further to potential farminees. Under the work commitments, the option existed to either drill one well or complete an additional phase of seismic in place of the well before reaching the end date of 18 February 2019. It is thought that the terms were renegotiate to allow Kina to submit an extension application in 2H 218. Drilling targets could potentially be identified through interpretation of reprocessed vintage 2D seismic data. A seismic programme was expected in 2018 which did not materialise. Heritage farmed into PPL 437 in 2013 with the condition that Kina would be free-carried through the first seismic programme. Additional interest could be earned by Heritage (up to 50%) if the option to drill an exploration well was taken, in which Kina would also have been free carried. Kina is also offering a farm-in opportunity in its two southern Western Province licences: PPL 435 and PPL 436, which are interpreted to extend the liquids fairway from Stanley-Tingu-Elevala-Ketu fields. PPL 437, which covers an area of 1,537 sq km, was awarded on 19 February 2013 and is scheduled to expire on, or be eligible for renewal by, 18 February 2019.Operator Kina Petroleum Corp holds 57.5% interest with partner Heritage Oil Ltd (42.5). Kina is seeking a farm-in partner to assist in a continued exploration programme. Heritage is looking to exit the permit. Companies interested in pursuing this opportunity should contact: Richard Schroder – Kina, MD Email: [email protected] Krey Stirland – Heritage Oil, Vice President Business Development Email: [email protected]

Kina Petroleum Corp offering farm-in opportunity in PPL 437, Papuan Basin

On 20 April 2020 Zenith Energy announced that it signed a conditional sale and purchase agreement with Kufpec for the acquisition of its interest in the Sidi El Kilani concession, onshore Pelagian Basin. Kufpec holds a 22.5% interest in the asset through a 22.5% ownership in the operating company Compagnie Tuniso-Koweito-Chinoise de Pétrole (CTKCP). Zenith will pay USD 0.5 million to purchase the stake in the Sidi El Kilani field. The deal is subject to approval by the authorities. Current participants are: state company ETAP with 55%, CNPC with 22.5% and Kufpec with 22.5%. On 2 March 2020, Zenith Energy reported that it signed an exclusivity agreement to acquire an operated working interest in an onshore oil production asset in Tunisia. No further details were given. The company expected to complete the operation by 31 March 2020, subject to the satisfactory conclusion of an ongoing due diligence evaluation. Zenith Energy took advantage of the depressed prices of E&P assets due to the oil price crash and the COVID-19 pandemic. Sidi El Kilani was discovered in 1989 by Kufpec and started production in 1991. The field currently produces around 560 b/d of oil. According to Zenith Energy, the field generates gross annual revenues of approximately USD 15 million. Sidi El Kilani produces 39 API gravity oil from a fractured carbonate reservoir in the Abiod Formation, at a depth of around 1,600 m. The reservoir characteristics are enhanced by natural fractures and locally by dolomitisation. The field facilities include a gas-oil separation plant and a 125 km 8 inch pipeline to the La Skhira terminal with a capacity of 22,000 b/d. Andrea Cattaneo, CEO of Zenith commented: "The board views Tunisia as a safe, democratic jurisdiction with a well-established history of successful oil a d gas production activities for junior, independent companies such as Zenith. Upon completion of the deal, Zenith will have a material production revenue for reinvestment in field development activities. Our strategic outlook is that oil prices will progressively strengthen in line with a gradual worldwide recovery in financial and industrial activity following the progressive alleviation of the devastating COVID-19 pandemic."

Zenith has signed a conditional SPA with Kufpec for the acquisition of the latter's 22.5% in CTKCP (Compagnie Tuniso-Koweito-Chinoise de Pétrole) operator of onshore the Sidi El Kilani lease/field (204 sq km) and North Kairouan block (3,172 sq km), for USD 500,000. Holding would presumably remain unchanged (CTKCP (op), Kufpec, CNPC + ETAP).

SW sector of PDL 4, Papuan Fold Belt, deviated from Gobe Main wellpad, sidetrack early 2020 (KOP 1,230m), P&A'ing oil shows at TD 4,370m, High Arctic 103 rig. Target Iagifu + Toro sst. Oil Search (op), partners Merlin, Ampolex + Petroleum Resources Gobe.

Gobe Footwall-1ST expl. (Oil Search 10% op, Merlin 73,48%, Ampolex 14,52%, Petroleum Resources Gobe 2%) in SW sector of PDL 4 block, P&A oil shows at TD=4370m, Target Iagifu + Toro sst.

Exxon reports completion of the 36.5% interest transfer from Equinor in the BM-S-008 contract, Caracará discovery evaluation area, Santos Basin. Although the farmout is complex it represents an alignment of equity across the 2 blocks that together make up the Caracará find. As a result, both Equinor and Exxon have a 36.5% interest in BM-S-008 and 40% in Norte de Caracará. Galp 17% in BM-S-008 and 20% in Norte de Caracará. Equinor operates the unitised field devt. Production from the field is expected to start in 2023 - 2024.

Exxon reports completion of the 36.5% interest transfer from Equinor in the BM-S-008 contract, Caracará discovery evaluation area, Santos Basin.

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

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

Jafarli oilfield, Muradkhanli licence onshore South Caspian Basin, deepening of devt well to TD 4,350m, successfully identified 3 new oil-bearing clastic layers in the Middle Eocene, total net pay ab. 16m, currently wireline logging prior to perforate + test. Zena Drilling rig.

Azerbaijan (Kura Sub-basin (South Caspian B.)) Jafarli

On 7 July 2020 Comet Ridge Ltd reported that the Mahalo Gas Project (MGP) has been granted Petroleum Leases (PL) 1082 "Humboldt" and 1083 "Mahalo" by the Queensland State Government for a term of 30 years. The awarding of the leases, which lie in the northern part of ATP 1191-P, will now allow the project to transition to production. In early June 2020 Comet reported that the MGP had been granted Queensland State Government environmental approval. This was the second of two approvals required for the gas development to move to production following Commonwealth approval in late May 2020. As a result, the project had fulfilled all federal and state environmental requirements, and all that was required was the issuing of Petroleum Leases from the Queensland State Government. Also reported was that the environmental work for Mahalo North was to begin in the approaching Spring or Summer season. In late May 2020 Comet reported that the MGP was granted approval under the Commonwealth Government Environment Protection and Biodiversity Conservation Act (EPBC), which was one of two environmental requirements needed for the project to progress to the production phase. The second requirement was under assessment as of reporting by the Queensland State Government Department of Environment and Science. Previously in late February 2020 Comet reported that it had signed a non-binding Memorandum of Understanding (MoU) with LogiCamms for the development of a >65 km pipeline connection from the Mahalo North field, located in the Bowen Surat Basin. Also included within the agreement was the option to potentially transfer Comet's share of gas from the Mahalo field. It was reported that both parties intended to carry out an evaluation of the technical and economic aspects of a six to eight inch diameter pipeline solution from Mahalo North which would transfer the company's net gas production which was in the range of around 20 to 50 TJ/d into larger pipelines to the south of the field. Under the terms of the MoU activities were to be conducted to get an understanding of debt funding options for both the upstream and pipeline portions of the project. ATP 1191-P, which covers an area of 2,000 sq km, was awarded on 25 September 2015. Comet Ridge has a 40% interest in the Mahalo Coal Seam Gas project (909 sq km), with joint venture partners Santos QNT Pty Ltd (30% plus operatorship) and Australia Pacific LNG Pty Ltd (30%). Background Information: April 2004 - Mahalo discovered October 2019 - Named Preferred Tender for the PRL2019-1-2 for the Mahalo North Block June 2020 - Originally planned Final Investment Decision

Australia ((Bowen - Surat B.s)), Comet Ridge Ltd reported that the Mahalo Gas Project (MGP) has been granted Petroleum Leases (PL) 1082 "Humboldt" and 1083 "Mahalo" by the Queensland State Government for a term of 30 years. The awarding of the leases, which lie in the northern part of ATP 1191-P, will now allow the project to transition to production.

Chevron Australia Pty Ltd has announced that is has made the decision to market its non-operated 1/6th interest in the North West Shelf (NWS) project, located in the North Carnarvon Basin. The decision was made after Chevron received unsolicited offers from a range of buyers. The deal has been reported to be worth around USD 3.5 billion. With the NWS Project moving focus from an independent LNG project to a competitive third-party tolling facility, Chevron believes this represents a good time to exit the joint venture by considering proposals by potential buyers. Since the Woodside operated NWS Project commenced in 1989, Chevron has maintained its position, which is currently holds at 16.67%, alongside equal share with partners Woodside Energy Ltd, BHP, BP, Japan Australia LNG (MIMI) and Shell. Over the coming years, it's planned that the Pluto LNG Plant will be tied into the NWS Project's Karratha Gas Plant – creating the "Burrup Hub" as part of an expansion concept. The Browse LNG Project could also see LNG tolled through the facilities via a 900 km long pipeline, in which, Chevron does not hold position. Overall, the NWS Project comprises 19 licences (JV 15.78% share, with 5.32% held by CNOOC) and 20 gas and 7 oil discoveries. Initially the project produced from foundation fields: North Rankin, Goodwyn, Angel and Perseus. Two completed expansion phases extended production through the tie in of second-tier fields. The third expansion phases reach a financial investment decision in January 2020. Chevron has reported that it intends to maintain its position in its Gorgon and Wheatstone Projects.

Australia (Exmouth Plateau (North Carnarvon B.)) Pluto, Chevron Australia Pty Ltd has announced that is has made the decision to market its non-operated 1/6th interest in the North West Shelf (NWS) project, located in the North Carnarvon Basin.

Murphy and partner Santos will shortly be looking to farm-down their respective 50% stakes in EPP 43, Bight Basin, once detailed prospect mapping is complete. EPP 43 covers 16,600 sq km on the W. flank of the Ceduna sub-basin. Contact [email protected].

Murphy and partner Santos will shortly be looking to farm-down their respective 50% stakes in EPP 43, Bight Basin, once detailed prospect mapping is complete. EPP 43 covers 16,600 sq km on the W. flank of the Ceduna sub-basin. Contact [email protected].

In mid-March 2018, Perenco Oil & Gas Gabon was evaluating the Akoum South 1 exploration well in the DE8 block. The well was spudded on 23 January 2018 and reached a TD of 2,302 m on 5 March 2018. Perenco operates the block with a 60% interest and Sasol holds the recently acquired 40% interest DE8 exploration permit is located along the coast off Omboue, 90-190km SSE of Port Gentil, in water depths ranging from 0 to 80m. Straddling the limit between the North and South Gabon sub-basins, DE8 surrounds three fields operated by Perenco Oil Gabon Ltd, Tchatamba Marin, Tchatamba West and Tchatamba South. Potential reservoirs in the area are the Albian Upper Madiela unit, which is the main reservoir on the Tchatamba complex, and the Senonian Batanga Formation. Potential source rocks lie in the Turonian Azile and Albian Madiela formations.

Perenco Oil & Gas Gabon was evaluating the Akoum South 1 exploration well in the DE8 block.Perenco operates the block with a 60% interest and Sasol holds the recently acquired 40% interest

The authorities are planning a tender call designated Round 4 for 5 areas, namely Bestwina-Czechowice (83 sq km), Krolowka (189 sq km), Pyrzyce (1,172 sq km), Zloczew (702 sq km) and Zabowo (1,000 sq km). Tender docs shouléd appear in the EU Journal before long in time for a 1Q '20 opening. A data room is available, contact: [email protected].

The authorities are planning a tender call designated Round 4 for 5 areas, namely Bestwina-Czechowice (83 sq km), Krolowka (189 sq km), Pyrzyce (1,172 sq km), Zloczew (702 sq km) and Zabowo (1,000 sq km). Tender docs shouléd appear in the EU Journal before long in time for a 1Q '20 opening.

Total and partners have applied to convert Licensing Option (LO) 16/27 to a full Frontier Exploration Licence, as announced on 18 April 2018. LO16/27 was awarded on 1 July 2016 as part of the 2015 Atlantic Margin Round and covers 1,323 sq km, located approximately 90km S of the Spanish Point (gas and condensate) and Burren (oil) discoveries. The partners have identified the Palaeocene oil Avalon prospect consisting of a deep-water fan system up to 125m thick, which is viewed as being analogous to the Druid structure drilled 90 km to the SSW by 53/6-1 (2017, Providence), P&A dry. On 13 October 2017, Total farmed in to LO16/27 acquiring 50% WI and operatorship from Providence Resources and Sosina Exploration. Total agreed to pay its pro-rata share of past costs, and an additional 21.4% of past and future costs during the two year LO term (gross cap of US$ 1.33 million). If the conversion to a Frontier Exploration Licence (FEL) is approved and the partners decide to drill the Avalon prospect, Total will pay 60% of drilling costs (gross well cap of US$ 42 million). LO16/27 licence partners are Total E&P Ireland BV (50% + Op), Providence Resources plc (40%) and Sosina Exploration Ltd (10%).

Ireland, LO16/27

G11/48, S. Pattani Trough, drilled + P&A minor oil 29 Jun – 3 Jul ’19, TD 1,116m, Valaris 115 JU. Mubadala (op), partner Palang Sophon.

Nong Nuch-4 appr G11/48, S. Pattani Trough, drilled + P&A minor oil TD 1,116m,Mubadala (op), partner Palang Sophon.

Shuangtan 8 flow tested commercial amount of gas from the Xixia Formation on 21 November 2017 with testing operations having commenced on 8 October 2017. Shuangtan 8 was drilled to a TD of 7,529.49m MD on 18 August 2017 and was suspended in late August 2017 for testing after having been spudded on 23 November 2017. A total of 35.02m of cores were collected in the Qixia Formation and Guanwushan Formation. The gas exploration/appraisal well had a PTD of 7,240m and was targeting the Permian and Triassic Maokou and Qixia formations and Triassic Feixianguan Formation in the Shuangyuzi-Hewanchang Structure. Shuangtan 8 is geographically located in Sichuan Province, Jiangyou City, Yuuji Town, Guanlu Village in the PetroChina operated Beichuan-Jiange Block. <P /><P />

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Actis Oil & Gas is offering companies to participate on a promote basis in return for the drilling of an exploration well on licence P2339 (block 21/30e). Actis has identified ten prospects in the acreage collectively named the ‘Biscuits’ prospects with an estimated combined P50 recoverable resource of 38.64 MMbbl. The Jurassic Fulmar Sandstones form the reservoir objective in all ten prospects which are sourced and sealed by Kimmeridge Clays and Shales. The trapping mechanisms involve four-way dip closures and rotated fault blocks. The current work programme aims to de-risk the structures and mature them into drillable prospects. The abundance of local infrastructure should enable the prospects to be rapidly developed if successful. Furthermore, the Triton FPSO is on licence with spare slots for early production, subject to negotiation.     Hobnob forms the primary prospect and includes the independent Digestive and Ginger closures in a P10 scenario. Further potential from Oreo, Bourbon and Creme are all defined as single culmination structures. The Cracker North and South prospects are closed against thick Lower Cretaceous Shales to the north and east. In the west, fault seal provides closure and a salt diapir provides closure in the south where Actis interpret the Jurassic Fulmar Sandstone to be juxtaposed against the Zechstein. Garibaldi is defined as a four-way dip closure at the Base Cretaceous Unconformity stratigraphic level. The company state that reservoir presence provides the key risk however, thick Jurassic reservoirs could be preserved over the crest of the structure. Jaffa is described as a large westerly tilted fault block bounded by a major fault. The P10 scenario relies on fault seal to the south west, with further upside potential in smaller terraces to the east.   The licence was awarded in the 2016 Offshore Supplementary Round on 1 August 2017. The acreage is surrounded by several fields including Guillemot A, Gannet C, Gannet F and Gannet E. No exploration wells have been drilled in block 21/30e to date due to the risks associated with the Upper Jurassic play. Interest in P2339 is held solely by Actis Oil & Gas Ltd (100% + operator). For further information please contact: David Marsden – Exploration Manager Email: [email protected]

Actis Oil & Gas is offering companies to participate on a promote basis in return for the drilling of an exploration well on licence P2339 (block 21/30e).

Ref. DEA 8 May ’19, Kufpec + Migas have now signed the Gross Split PSC for the 3,434-sq km Anambas block offshore West Natuna. Commitments G&G studies, 600 sq km of 3D seismic + 1 well in 3 years.

Kufpec + Migas have now signed the Gross Split PSC for the 3,434-sq km Anambas block offshore West Natuna. Commitments G&G studies, 600 sq km of 3D seismic + 1 well in 3 years.

NEO Energy has completed the acquisition of Spirit Energy's 13% interest and operatorship of licence P456 which hosts the Babbage gas field. It was confirmed that NEO acquired the interest on 14 May 2020. Babbage was discovered in 1989 by Amoco’s 48/2-2Z well and appraisal drilling took place in 2006. The field has a Permian Leman Sandstone reservoir. During Phase 1 of development three horizontal multi-fractured wells were drilled between April and November 2009 and a platform was installed in September 2009. Production commenced from the field in August 2010. During phase 2, which took place between 2012 and 2013, there were 2 multi-fracced development wells were drilled. The Not Permanently Attended Installation (NPAI) is tied-back to the West Sole field which is located 28 km to the south. The field is expected to produce over 175 Bcfg over a life of 20 years. Following the completion of the deal interest in the licence is held by NEO Energy (SNS) Limited (60% + operator) and Dana Petroleum (E&P) Limited (40%).

NEO Energy has completed the acquisition of Spirit Energy's 13% interest and operatorship of licence P456 which hosts the Babbage gas field. It was confirmed that NEO acquired the interest

Block 9 (Suneinah), P&A'ing, pilot hole to 2,367m. Oxy (op), partners OQ Upstream + Mitsui.

Oman (Oman B.) Nakhlah 2 op. by OXY (50%), OQ (45%), MITSUI (3%), MOECO (2%) in Block 09 (Suneinah) P&A'ing, pilot hole to 2,367m

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

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

Aceiro has acquired and undisclosed in prod. licence P8a from Petrogas, retro-effective 20 Dec '19. Petrogas retains operatorship of the 26-sq km lease, partners Aceiro + EBN.

Netherlands (Anglo-Dutch B.) P/08a op. by MB HLD (60%), EBN (40%) Aceiro Energy has gained an unspecified minority stake in offshore licence P08a from Petrogas.

A renewed tender is planned 25 Jun '20 for 5-year rights to the diminutive (1.4 sq km) Poznyakevichskiy block in the Pripyat Basin, application deadline 22 May. Starting price USD 7,000. Contact: [email protected]. The permit was already offered in 2018 but no takers.

A renewed tender is planned 25 Jun '20 for 5-year rights to the diminutive (1.4 sq km) Poznyakevichskiy block in the Pripyat Basin, application deadline 22 May.

Beach Energy Ltd spudded the Wirruna 1 exploration well in PRL 130, located in the Cooper-Eromanga Basin, on 25 July 2019.  The well was drilled by the “SLR Rig 185” land rig.  On 4 August 2019 the well was plugged and abandoned, at a total depth of 2,777 m, have encountered gas shows. The well was part of Beach’s ongoing Cooper-Eromanga 2019 exploration and appraisal programme.  Wirruna 1 is located to the south of the Crockery, Haslam and Ralgnal gas fields. PRL 130, which covers an area of 54 sq km, was awarded on 8 October 2014.  Beach Energy Ltd holds 100% interest and operatorship of the permit, with 50% held through wholly owned subsidiary Great Artesian Oil and Gas Pty Ltd.

Beach Energy Ltd Wirruna 1 (exploration) PRL 130, Cooper-Eromanga Basin - P&A, gas shows

Liaodong Bay, Bohai Gulf Basin, WD ca. 30m, ops terminated mid-Sep ’18, results n/a. Nohai 7 JU. Target Tert. sands.

Liaodong 4-3-1 (LD 4-3-1) nfw Liaodong Bay, Bohai Gulf Basin, WD ca. 30m, ops terminated mid-Sep ’18, results n/a. Nohai 7 JU. Target Tert. sands.

West Madura Offshore PSC off East Java, drilled Jan – mid-Feb ’18, Ensco 67 JU. Target assumed Kujung fm carbs. Pertamina (op), partners Kodeco + Mandiri Madura Barat.

N'7 expl, West adura Offshore PSC, Pertamina (op), partners Kodeco + Mandiri Madura Barat.drilled Jan – mid-Feb ’18, Ensco 67 JU. Target assumed Kujung fm carbs.

15 July 2019, Uzbekneftegaz (UNG) intends to offer over 50 mature fields with low/falling oil production for development to foreign companies on risk-service contract basis, as announced by Mr. Sidikov, UNG’s Chairman of the Board. UNG has a stock of more than 50 fields with falling oil production. These are mostly small fields or fields with hard to recover reserves where UNG is not able to work or does not see justification to invest large amounts of money. UNG will offer them to foreign investors if they are ready to bring in new technologies and are confident that they will be able to increase production from these fields. Foreign companies would invest at their own risk. The existing production would be fixed as a base level and will belong to UNG, and any incremental production would be split between UNG and the investor based on an agreed formula. These so-called “undistributed risk” contracts are not a new form of co-operation in Uzbekistan. This type of contract has already been used in the past, there already are several investors with whom such contracts have been concluded. UNG has already started working with several foreign companies on certain fields. UNG’s priority now is to develop a system of tendering such fields. This will all be completed in 2019.

15 July 2019, Uzbekneftegaz (UNG) intends to offer over 50 mature fields with low/falling oil production for development to foreign companies on risk-service contract basis, as announced by Mr. Sidikov, UNG’s Chairman of the Board. UNG has a stock of more than 50 fields with falling oil production. These are mostly small fields or fields with hard to recover reserves where UNG is not able to work or does not see justification to invest large amounts of money.

On 24 January 2018, TOTAL E&P USA INC. announced that it has reached an agreement to acquire the equity position held by Samson Offshore LLC at the Anchor project in the deepwater Central Gulf of Mexico. Total will obtain the 12.5% non-operating working interest in four blocks currently owned by Samson affiliate Samson Offshore Anchor LLC over the Chevron-operated Anchor discovery, a subsalt Wilcox oil find made in December 2014. Samson’s leasehold occurs in Green Canyon blocks 806 (G31751), 807 (G31752), 850 (G31757), and 851 (G31758). Total previously owned a participating interest in the subject leases ranging from 8% to 40% but sold it, effective 1 January 2014. TOTAL’s press statement said the deal also includes Samson’s 12.5% stake in Green Canyon block 761 (G35684), a tract where TOTAL already owns a 25% working interest. This latter block is found immediately northwest of the Anchor unit. When the deal is finalized, TOTAL will join the Anchor partnership consisting of Chevron U.S.A. Inc. (55%), Cobalt International Energy LP (20%) and Venari Offshore LLC (12.5%). “The entry in the Anchor discovery further increases Total’s footprint in deepwater Gulf of Mexico. It follows our entry in seven exploration prospects located in the promising Wilcox (Central GoM) and Norphlet (Eastern GoM) plays thanks to an agreement signed with Chevron last September, and in the Jack field where the Group will acquire a 25% interest as part of the Maersk Oil deal”, stated Arnaud Breuillac, President Exploration & Production at Total. Anchor lies in some 6,000 feet (1,828 m) of water in the southwest quadrant of the Green Canyon (GC) protraction area, roughly 150 miles (240 km) southwest of the coastal support base at Port Fourchon, Louisiana. In April 2014, the Bureau of Ocean Energy Management approved the Green Canyon block 807 “Anchor” Unit (Contract No. 754314005). This initial unit formed a four-block square, consisting of GC blocks 762 (G25198), 763 W/2 (G25199), 806 (G31751), and 807 (G31752). The former two unit leases expired in 2014 and are now held by unit operations. On 12 July 2017, Cobalt announced that the company had reached an agreement with its partners to include two Cobalt-owned (100%) blocks, Green Canyon blocks 850 and 851, to the existing four-block Anchor unit. Upon government approval of the transfer of interests in the two leases, Cobalt said it would retain a 20% working interest in the revised six-block Anchor unit. All the blocks associated with TOTAL’s acquisition and the Anchor unit are standard 5,760-acre (23.31 sq km) deepwater tracts.

TOTAL E&P USA INC. announced that it has reached an agreement to acquire the equity position (12.5% non-operating working interest) held by Samson Offshore LLC at the Anchor project (Green Canyon blocks 806 (G31751), 807 (G31752), 850 (G31757), and 851 (G31758). TOTAL’s press statement said the deal also includes Samson’s 12.5% stake in Green Canyon block 761 (G35684), a tract where TOTAL already owns a 25% working interest.

Roemerberg-Speyer prod. lease, Rheinland-Pfalz, Upper Rhine Graben, TD 2,942m, successful oil well (results hitherto unreported), completed for production in Lower Triassic reservoir. Neptune Energy (op), partner Palatina GeoCon.

Roemerberg-Speyer prod. lease, Rheinland-Pfalz, Upper Rhine Graben, TD 2,942m, successful oil well (results hitherto unreported), completed for production in Lower Triassic reservoir. Neptune Energy (op), partner Palatina GeoCon.

In May 2019 Telpico continues to offer interest in its VSM-22 Block of the Upper Magdalena Basin. The Yaguara (Los Mangos) field is located on the block’s eastern border and the primary objective is the Cretaceous Caballos Formation. This sandstone is overlain by the La Luna/Villeta Shale, a world class source rock and target for unconventional plays. In 2014, Telpico identified the Hidalgo Prospect from high quality 3D seismic acquired on the VSM-22 and recoverable reserves are estimated between 21-25 MMbo. With block expiration scheduled for August 2020, plans to drill the Hidalgo prospect are slated for June 2019. Telpico is offering a 49% working interest with a potential partner to pay a USD 2.5 million buy-in cost. The deal also includes the partner to pay 100% of the initial well test costs for the 49% working interest. Interested parties should visit the website at www.telpico.com.

Telpico continues to offer interest in its VSM-22 Block of the Upper Magdalena Basin. The Yaguara (Los Mangos) field is located on the block’s eastern border and the primary objective is the Cretaceous Caballos Formation.

During the first quarter of 2020 Sand Hill Petroleum drilled the Portita 10 exploration well in the E X-1 Voivozi license. The company reported on 29 May 2020 that the well, which is located approximately 2.5 km to the southwest of the abandoned Portita gas field, was a dry hole. Portita 10 had a planned TD of 1,536 m and was understood to be targeting gas within the Miocene series. Civil works began in January 2020 and it is believed that the well was drilled in March. The E X-1 Voivozi block, located in western Romania close to the Hungarian border, was awarded to MOL and Expert Petroleum in April 2011. The block was offered as part of Romania 10th licensing round. In January 2017 Sand Hill petroleum became the operator of the license with a 70% interest by acquiring the stake held by Expert Petroleum and a part of MOL's interest. In H1 2019 Sand Hill Petroleum acquired 420 sq km of new 3D seismic in the eastern portion of the block. Interest in the E X-1 Voivozi permit is held by Sand Hill Petroleum Romania SRL (70% + operator) and Panfora Oil and Gas SRL, a wholly owned subsidiary of MOL Group (30%).

Portita 10 explo. (Sand Hill Petroleum 70% op, MOL 30%). in the E X-1 Voivozi license was a dry hole. The well had a planned TD=1536 m and was understood to be targeting gas within the Miocene series.

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.

Liberia's 2020 offshore licensing round could be facing a delay, pressured by comments from the former NOCAL boss Neyor, who calls for its postponement. Whilst Neyor held words of 'amateur practice', the Covid-19 may also play a role in any delay. The round was so far due to kick-off on 15 Apr '20 at the Conference Hall of the Farmington Hotel near Roberts Airport, Monrovia. Nine blocks (LB 25-33 in brown below) are normally expected to be offered in the Harper Basin, for which 2D + 3D seismic data are available. The offer will be coordinated by TGS. Map below TGS, release here.

Liberia, not found

Total has signed an agreement with Samson in order to acquire Samson Offshore Anchor, LLC, which holds a 12.5% interest in four blocks covering the Anchor discovery, one of the most significant recent discoveries in the Gulf of Mexico (GoM), USA. The deal also includes a 12.5% interest in the nearby exploration block Green Canyon 761, where Total already has a 25% interest.   'The entry in the Anchor discovery further increases Total’s footprint in deepwater Gulf of Mexico. It follows our entry in seven exploration prospects located in the promising Wilcox (Central GoM) and Norphlet (Eastern GoM) plays thanks to an agreement signed with Chevron last September, and in the Jack field where the Group will acquire a 25% interest as part of the Maersk Oil deal', stated Arnaud Breuillac, President Exploration & Production at Total.    Discovered in the Wilcox play in 2014, Anchor is located approx. 225 kms off the coast of Louisiana in more than 1,500 meters of water. Additional prospective resources have been identified in the Anchor vicinity, strengthening the potential of the asset.   Anchor is operated by Chevron (55%) alongside Cobalt (20%), and Venari (12.5%).Location of the Anchor discovery in the Gulf of Mexico (Source: Chevron) Original article link Source: Total

Total acquired Samson Offshore Anchor, holder of a 12.5% interest in the 4 blocks* covering the Anchor discovery. The deal also includes a 12.5% interest in the nearby exploration block Green Canyon 761, boosting Total’s stake here to 37.5%. Anchor lies in WD >1,500m. Chevron (op) 55%, Cobalt 20% + Venari 12,5%. * Green Canyon blocks 806, 807, 850 + 851:

Yunjin 2 flow tested approximately 20.8 MMcfg/d from the Permian Maokou Formation on 13 January 2020 after undergoing acidization. Yunjin 2 was spudded on 5 September 2019 and was drilled to a TD of 3,621m MD on 21 December 2019. The gas exploration well was targeting the Permian Maokou Formation with the objective of exploring the further gas potential within the syncline of the Shunan region in the southern Sichuan Basin, where several gas fields had been discovered in the anticline structures. Yunjin 2 is in the PetroChina operated Luxian-Changning Block in the Sichuan Basin and is geographically located within Sichuan Province, Luzhou City, Lu County, Baihe Town, Xinglongzui Village.

Yunjin 2 flow tested approximately 20.8 MMcfg/d from the Permian Maokou Formation on 13 January 2020 after undergoing acidization. The gas exploration well was targeting the Permian Maokou Formation with the objective of exploring the further gas potential within the syncline of the Shunan region in the southern Sichuan Basin

88 Energy, via subsidiaries, Accumulate Energy and Regenerate Alaska, ended high bidder on 133 sq km gross on 6 Dec ’17 under the North Slope Areawide 2017W lease sale. Two parcels are subject to regulatory approvals and formal award, expected in 2018. Burgundy Xploration has a right to back in to ab. 10 sq km within Parcel 1. Acreage lies adjacent + west of Project Icewine.

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

Sonatrach has bagged rights to the Reggane II explo permit, assumed to be a renewal/re-award of the Reggane Hirane unit, expired Jun '19. The award was officialised on 8 Dec '19. The sketch below outlines the former Reggane Hirane unit, Reggane Basin:

Algeria, not found

Eni + Total will transfer a combined 25% in deepwater Lamu blocks L11A (5,009 sq km), L11B (4,886 sq km) + L12 (4,973 sq km) to Qatar Petroleum.  Explo drilling is planned in L11B in 2020. Partnership becoming Eni (op) 41.25%, Total 33.75%, QP 25%.

Eni + Total will transfer a combined 25% in deepwater Lamu blocks L11A (5,009 sq km), L11B (4,886 sq km) + L12 (4,973 sq km) to Qatar Petroleum. Explo drilling is planned in L11B in 2020. Partnership becoming Eni (op) 41.25%, Total 33.75%, QP 25%.

Following the signing of the Exploration & Production Sharing Agreement (EPSA) for Block 52 (JuzorAl Hallaniyyat) on 14 November 2017, Eni signed an agreement with Qatar Petroleum (QP) by which the latter will receive a 30% interest in the block. The deal, for which no value was reported, is subject to government approval. Upon completion of the transaction Eni will remain the operator of the acreage with a 55% interest and will be partnered by QP (30%) and Oman Oil Co Exploration & Production LLC (OOCEP) (15%).<P />The block (90,760 sq km), which is located offshore of the southern third of Oman in water depths ranging between 10-3,000m, has been awarded following the country's 2016 Licensing Round and is largely unexplored. Only three wells have been drilled on the vast acreage so far. To date no discoveries have been made, however oil and/or gas shows have been reported in all three wells. It is understood that the JV is drawing up plans to carry out an exploration programme on the acreage, which will involve the acquisition and processing of 3D seismic as well as exploration drilling.

Oman, Block 52 (Juzor Al Hallaniyyat)

Doriemus announced on 27 February 2019 that it has agreed to sell 20% interest in the Lidsey field located in licence PL 241 to Angus Energy. Angus paid approximately USD 0.6 million with the transferal of over 8 million shares to Doriemus. Angus announced that the deal completed on 18 April 2019. The Lidsey field was discovered in March 1987 by Carless Exploration Ltd when oil was encountered in the limestones of the Middle Jurassic Great Oolite Formation. The reservoir is sealed by the overlying Oxford Clay and sourced by the Lias, Kimmeridge Clay and Oxford Clay. The structure is a tilted fault block dip closed to the north, east and west and fault sealed to the south. Over the years several EWTs were carried out with daily production in the test periods of between 40-66 bo/d. The field was eventually brought onstream in March 2008 after construction of new production facilities. Angus drilled Lidsey X2 in October 2017 which produces horizontally via an artificial lift from the Great Oolite Formation with a net oil pay of 443 m. Interest in PL 241 is held by Angus Energy Weald Basin No.3 Ltd (80% + operator), Brockham Capital Ltd (10%) and Terrain Energy Ltd (10%).

United Kingdom (Weald Sub-basin (Wessex B.)) Brockham

Angus Energy announced on 19 June 2019 that it has completed a deal with Wingas Storage (UK) Limited in which Angus has acquired a 51% interest in the Saltfleetby onshore gas field in Lincolnshire (PEDL 005). Wingas is also to be renamed Saltfleetby Energy and will retain a 49% interest in the field. The deal, originally announced in April 2019, will see Saltfleetby Energy pay an initial contribution of GBP 2.5 million which will be applied by Angus to either – a) assume 100% of the costs to be incurred during the reconnection of the field to the National Grid, or b) satisfy all abandonment costs for the field is reconnection at commercial rates is not possible. If the reconnection is possible then it is likely that work will be completed in summer 2020. Completion of the deal is subject to regulatory approval. Saltfleetby is a Carboniferous gas/condensate field which was brought onstream in mid-December 1999. On 14 December 1999 gas was introduced to the Theddlethorpe processing plant and within a couple of days production was increased to 40 MMcf/d and about 1,100 boe/d condensate from four wells. During June 2000 the Saltfleetby Gas Field continued to produce at, or close to, plateau rates with an average gas production of 47.3 MMcf/d for the month. The field came off plateau production during July 2000, significantly later than originally anticipated. Further development drilling took place on the field in 2003 and then again in 2007. In total 8 wells and a number of sidetracks have been drilled since first production commenced. It is understood that 67 Bcf of dry gas along with 1.1 MMboc has been produced to date. A recent field development plan which was to be submitted in 2016 to the OGA estimated that an additional 12.7 Bcf of recoverable gas from 2 remaining production wells. Angus believes that 10 – 18 Bcfg could be recoverable over a 10 – 12 year period along with 100,000 to 180,000 barrels of gas condensate. Angus also believes that there could be further upside in the area which could provide new drilling opportunities. Following completion of the deal interest in blocks TF/38a, TF/39a, TF/48a and TF/49a (PEDL 005) will be held by Angus Energy Weald Basin No.3 Limited (51% + operator) and Saltfleetby Energy (49%).

Wingas Storage (Gazprom’s subsid.) has agreed to farm out 51% operator share from its 100% stake in the onshore Saltfleetby gas field (PEDL005) to Angus Energy.

KrisEnergy is still offering a farm-in opportunity consisting of 44.5% participating interests in G10/48, located in the Pattani Trough (Gulf of Thailand Basin), as of early August 2020. The concession contains five oil fields, including the Wassana field that was brought onstream in 2015. The field has been producing from a series of stacked Miocene fluvial sand at a range of 3,250 to 5,000 bo/d in 2019. Production from the field was suspended in June 2020 in view of the global uncertainties related to the coronavirus disease 2019 (COVID-19) outbreak and low oil prices. The G10/48 concession is under a 20-year production period which commenced on 7 December 2015. The Wassana Production Area was granted on 9 February 2015 by the Thailand Department of Mineral Fuel (DMF). On 8 December 2015, DMF 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 assign un-risked oil in place of 1.4 Bbbl to the concession. KrisEnergy holds 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: Mike Whibley VP Technical Email: [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 Montha 1 in November 2018. The well was drilled to a TD of approximately 3,169 m (-2,785 m TVD) prior to plugged and abandoned as a dry well. 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 œIngenium MOPU and crude is stored in the Rubicon Vantage. 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.

(Gulf of Thailand B.) G10/48 operated by KRISENERGY (89%), partner PALANG SP (11%), KrisEnergy is still offering a farm-in opportunity consisting of 44.5% participating interests. The concession contains five oil fields, including the Wassana field that was brought onstream in 2015. The field has been producing from a series of stacked Miocene fluvial sand at a range of 3,250 to 5,000 bo/d in 2019.

Lundin has completed its deal, reported in early March 2020, to acquire Neptune's 20% interests in PL 886 and PL 886 B. The transfer is effective from 30 April 2020. PL 886 covers blocks (or parts of) 6306/6, 6306/8 and 6306/9 and PL 886 B lies adjacent to the northeast, covering parts of blocks 6307/1 and 6307/4. Lundin plans to drill a well on the Melstein prospect, which is targeting a new play with potential recoverable reserves of 160 MMboe, in PL 886 in 2021. It is also understood that there is a prospect in PL 886 B called Tarva, but no drilling plans have yet been released for this. The closest field to these licences is Fenja where development is progressing towards an onstream date of Q4 2021. Neptune will develop the Pil accumulation initially, using a subsea tieback to the Njord A platform. Recoverable reserves are approximately 97 MMboe. The project will use two subsea templates hosting three horizontal producers, two water injectors and a single gas injector. The drilling plan has been modified due to the effects of coronavirus disease 2019 (COVID-19) and drilling will now take place over two years in three phases. Bue represents upside and will be confirmed by Pil development wells before it is potentially brought into production at a later date. Oil will be processed on Njord A before being transferred to Njord B for onward export via shuttle tanker. Gas will initially be re-injected into the Pil reservoir and will later be exported via Njord’s connection to the Asgard Transport System. Plateau production is expected to be approximately 40,000 bo/d and gas production expected to peak at approximately 100 MMcf/d between 2025 and 2036. Total investment costs are approximately NOK 10.2 billion (USD 1.22 billion), with 16-year life forecast. Upon completion of the deal, PL 886 and PL 886 B interests are divided between Lundin Energy Norway AS (60% + operator), Petoro AS (20%) and Spirit Energy Norway AS (20%).

Lundin has completed its deal, reported in early March 2020, to acquire Neptune's 20% interests in PL 886 and PL 886 B.

Kafra block + discovery area, Chad Basin, susp. results n/a in July, GWDC rig.

Kafra N.-1 appr Kafra block + discovery area, Chad Basin, susp. results n/a in July,

Bielsko-Biala block, S. Poland, Horizon Petroleum (which acquired the block from San Leon last year) has signed a letter of intent with an unknown party for a farm-out of the Lachowice gas field. The farminee will get 50% equity in exchange for funding 100% of Lachowice’s initial production capex (around USD 8 million). First well expected Q1 ’19, initial production of 3 MMcf/d in Q4 ’19.

Bielsko-Biala block, S. Poland, Horizon Petroleum (which acquired the block from San Leon last year) has signed a letter of intent with an unknown party for a farm-out of the Lachowice gas field. The farminee will get 50% equity in exchange for funding 100% of Lachowice’s initial production capex (around USD 8 million). First well expected Q1 ’19, initial production of 3 MMcf/d in Q4 ’19.

HOEC has entered into an agreement with Geopetrol Intl to acquire the latter’s share capital from Geofinance Petroleum SA. The acquisition is hoped to be concluded by 15 April 2018. Geopetrol’s main asset is 30% in the Kharsang field in Assam.

HOEC has entered into an agreement with Geopetrol Intl to acquire the latter’s share capital from Geofinance Petroleum SA. The acquisition is hoped to be concluded by 15 April 2018. Geopetrol’s main asset is 30% in the Kharsang field in Assam

Petrobras, further to the Material Fact of 05/15/2017 and Press Release of 06/19/2017, has signed, with the company ENEVA, through its subsidiary Parnaíba Gás Natural, the contract for the assignment of the totality of its participation in the Azulão Field (Concession BA-3), located in the state of Amazonas. The total amount of the operation is US$ 54.5 million and will be paid on the closing date of the deal. The transaction is part of the 2017-2018 Partnerships and Divestments Program and is in line with Petrobras' portfolio management policy, which prioritizes investments in assets with greater potential for short-term operational generation and greater possibility of capital optimization and economies of scale. The completion of this deal is subject to the fulfillment of usual precedent conditions, including approval by the National Petroleum, Natural Gas and Biofuels Agency (ANP) and by the Administrative Council for Economic Defense (CADE). The disclosure to the market herein is in compliance with Petrobras' divestment methodology and is aligned with the guidelines of the Federal Accounting Court (TCU – Tribunal de Contas da União). Original article link Source: Petrobras

Brazil (Sao Paulo Plateau Sub-basin (Santos B.)) Azulao (Santos)

PRL 153, Cooper-Eromanga, susp oil at TD 1,545m 29 Jan ‘19. Hanson SW-1 had earlier been P&A’d dry at 1,745m.

PRL 153, Cooper-Eromanga, susp oil at TD 1,545m 29 Jan ‘19. Hanson SW-1 had earlier been P&A’d dry at 1,745m.

Bozhong 34-1N-9Sa (BZ 34-1N-9Sa) was suspended (results TBC) on or around 18 December 2018 after having been spudded on or around 29 November 2018 using the "Haiyangshiyou 923" jack-up. The drilling of was sidetracked due to mechanical issue. The oil appraisal well was likely targeting the Guantao, Dongying and Shahejie formations. Bozhong 34-1N-9 is in the CNOOC operated Bonan Block in the offshore Bohai Gulf Basin. <P />

Bozhong 34-1N-9Sa (BZ 34-1N-9Sa) was suspended (results TBC)

New Standard Energy is looking to farm-down its interest in its two tenements located in the Canning Basin, Western Australia. EP 481 and EP 482 are located onshore in the east of the basin. New Standard were looking to share the risk and reduce its costs for the committed work programmes and had contracted Miro Advisors to assist. However, both permits are due to expire on 15 August 2018, limiting the work programmes. On 30 April 2018, New Standard reported that it was continuing its interest in exploration activities in the Canning Basin and on 14 May 2018, applications were submitted to the Department of Mines, Industry Regulations and Safety (DMIRS) to renew the permits. The decision is currently under assessment. New Standard further reported on 30 July 2018 that if the applications are successful, and if additional funding is secured, the company will continue exploration within the permit. One exploration well in each permit is due in the last work terms. With these not completed, along with the renewal applications, New Standard has lodged applications to vary the work commitments to maintain a good standing. The decisions also remain under assessment by DMIRS. On 22 June 2018, New Standard completed a capital funding placement valued at nearly AUD 500,000. The funds were expected to be used to identify new opportunities and continue with rehabilitation obligations for historic exploration licences within in the Canning Basin. Four conventional prospects have been outlined across the permits totalling 1.18 Tcf of prospective gas-in-place resources (New Standard, 2012). Condon, Crostella, Logan and Teichert prospects are located in Lower Cretaceous sands of the Byro and Wooramel Groups. Additional shale gas targets have also been identified by New Standard but the current Western Australia moratorium on hydraulic fracturing reduces the likelihood of further exploration for these leads. The farm-out originally included a wider range of New Standard’s assets, across the Canning and Carnarvon basins. The licences were available to farminees either as a package or as individual licences.  New Standard was looking for a partner or multiple partners, to acquire interest via farm-in to EP 481 and EP 482, but also permits EP 451, and EP 456 and applications STP-EPA-0006, STP-EPA-0007, STP-EPA-0010 and STP-EPA-0092. The two permits EP 451 and EP 456 were relinquished in late 2016 and are now no longer valid. New Standard had also reported that it requested the Western Australia DMP to not pursue its applications. New Standard Energy holds 100% in the Merlinleigh permits, which consist of EP 481 and EP 482, covering a total area of 5,482 sq km.  Both permits were awarded on 16 August 2012 and are due to expire or be renewed on 15 August 2018.  New Standard reports that the permits are prospective for both conventional and shale plays.  The permits are located close to the Dampier to Bunbury pipeline and New Standard considered feed gas to the domestic market would form a viable development scheme in the event of a gas discovery. Parties interested in pursuing this opportunity should contact: Mr Xiaofeng Li, Managing Director, Tel: +61 89481 7477

New Standard Energy is looking to farm-down its interest in its two tenements located in the Canning Basin, Western Australia. EP 481 and EP 482 are located onshore in the east of the basin. New Standard were looking to share the risk and reduce its costs for the committed work programmes and had contracted Miro Advisors to assist.

An auction will be held for a block in Perm Kray (Volga-Ural Province) on 31 Mar '20: -Vetosskiy, 16.7 sq km, encompasses the small Vetosskoye oil field, starting price USD 0.09 MM. Winner will obtain 20-year licence. Applications by 6 Mar '20. More information from Permnedra at Kamchatovskaya Str., 5, in Perm.

An auction will be held for a block in Perm Kray (Volga-Ural Province) on 31 Mar '20: -Vetosskiy, 16.7 sq km, encompasses the small Vetosskoye oil field,

Pertamina EP discovered oil and gas with wildcat Akasia Maju 1 (AMJ-1) in the Jawa Bagian Barat (JBB) PPC, located in onshore West Java, around mid-July 2018. The well flowed 3 MMcfg/d from DST 2, 6 MMcfg/d from DST 3 and 1,320 bo/d from DST 4. The tests were conducted over the Upper Oligocene to Middle Miocene intervals of the Upper and Lower Cibulakan groups. The well was likely spudded around March 2018. The discovery reportedly has the potential to produce approximately 1,000 bo/d. The area comprises several producing fields, such as Jatibarang, the Cemara fields complex and Akasia Bagus. In 2017, Pertamina drilled three wells in the block. The first well, Pondok Makmur Indah 1, likely discovered small volumes of gas. Haur Gede 1 was reported as an oil and gas discovery, with approximately 14 MMboe of 2C reserves according to local reports. Both discoveries were made in the Cibulakan Group. The third well was West Gantar 1 gas discovery, in August 2017. The well may have targeted the deeper Eocene-Oligocene clastics of the Jatibarang Formation in a stratigraphic play. Pertamina is operator and sole interest holder in the JBB PPC. Background Information The JBB PPC is managed under Pertamina EP Asset 3, which comprises the Jatibarang, Subang and Tambun field areas. The asset produced approximately 10,000 bo/d and 55 MMcfg/d in 2017. Aside from exploration drilling, a 3D seismic survey was completed in the block in December 2016, over the Akasia Besar area. Approximately 99% of the planned area of around 1,120 sq km has been covered by seismic data recording. Elnusa conducted the survey, which covered an area located in the Cirebon, Majalengka and Indramayu regencies. Akasia Besar 1 wildcat was suspended on 28 August 2012 with at least 2,250 b/d of oil and 0.8 MMcf/d of gas flowed during the test. It had PTD of 2,700 m and was targeting Upper Oligocene to Lower Miocene sandstones of the Talang Akar Formation/Cibulakan Group and Lower Miocene carbonate build-up of the Batu Raja Formation. PT Pertamina's upstream operating areas, converted to "Production Sharing Cooperation Contracts" (subsequently termed "Pertamina Petroleum Contracts" or PPCs), were signed with BPMigas on 17 September 2005. The signature was delayed from its original scheduled date of 25 June 2004 due to undisclosed "internal problems" within PT Pertamina. This was then rescheduled to take place on 12 December 2004 at a PSC signing ceremony but it was again delayed as the PPC model was still being examined by the government.

Pertamina EP discovered oil and gas with wildcat Akasia Maju 1 (AMJ-1) in the Jawa Bagian Barat (JBB) PPC, located in onshore West Java, around mid-July 2018. The well flowed 3 MMcfg/d from DST 2, 6 MMcfg/d from DST 3 and 1,320 bo/d from DST 4. The tests were conducted over the Upper Oligocene to Middle Miocene intervals of the Upper and Lower Cibulakan groups. The well was likely spudded around March 2018.

IHS-Markit understands that Pertamina has likely plugged and abandoned new-field wildcat Radiatus Madu 1 (RDM-001), in the Nanggroe Aceh Darussalam (NAD) 1 PPC, onshore North Sumatra, in March 2019, as dry hole. The well was spudded on or around 31 December 2018, using PDSI’s “N110/59” land rig. The well was targeting oil and gas in the Middle-Upper Miocene Besitang River Sandstone, with a PTD of 2,125 m. Pre-drill resources for the Radiatus Madu prospect were estimated by Pertamina at 10.8 MMbbl and 62.8 Bcfg. According to local reports, well operations were anticipated to require approximately 30 days for drilling and 38 days for completion and testing. Drilling cost for RDM-001 was reported at USD 13 million. In preparation of the drilling, the operator held a socialization event with the local community of the West Brandan district, Langkat Regency, on 31 December 2018. Pertamina was also conducting development drilling in the block, with the Rantau SZ24 (RNT-SZ24) well in Rantau field. The well was spudded on 29 December 2018, ahead of the initial planned 2019 schedule. The purpose of the well is to increase oil production from the field, responding to the government call for maintaining the national energy security. Background Information Previous exploration activity in the Nanggroe Aceh Darussalam 1 PPC was the drilling of wildcat Titanum 1 in 2018. The well is reported to have flowed a small amount of gas, as of July 2018. Well testing was ongoing in early January 2018. The well was spudded in late November 2017 using Pertamina Drilling Services Indonesia’s (PDSI) 500 HP land rig. The largest field in the block is Rantau, which started production in 1929 shortly after its discovery. The field is estimated to contain approximately 300 MMbo plus 400 Bscfg recoverable, from Upper Miocene Keutapang sands. The structure is a diapirically-controlled NW-SE gently-dipping faulted anticline with over 396 m of structural relief. Complex NE-SW cross faulting divides the structure into 12 fault blocks, with displacement varying from 5 to 20 m. The field was shut-in from 1941 to 1960. Improved recovery was implemented in 1982 while enhanced recovery commenced in 2010. Pertamina conducted new development drilling in the field in December 2018, targeting to reach a production rate from the field of 3,000 bo/d in early 2019.

PT Pertamina EP Nanggroe Aceh Darussalam (NAD) 1 PPC - Radiatus Madu 1, P&A, dry

Premier Oil is to purchase 27.5% in Shearwater and 50-100% operator interest in five Andrew area fields from BP for US$ 625 million. The Shearwater acquisition will add 25 MMboe of reserves and resources. This was announced on 7 January 2020 alongside another agreement to acquire 25% in Tolmount from Dana Petroleum. The two deals are to be funded via a US$ 500 million rights issue plus debt, however Premier's largest creditor, Analytical Research Capital Management (ARCM), has expressed opposition, citing a number of concerns including deal cost, decommissioning liabilities, and increased exposure to the UK gas market. The Central North Sea, Quad 16, Andrew area includes the Andrew (BP 62.75%), Arundel (BP 100%), Cyrus (BP 100%), Farragon (BP 50%) and Kinnoull (BP 77.06%) oil and gas fields, with 2019 net forecast production of 18,000 boe/d. Shearwater was discovered by 22/30b- 4 (1991, Arco, 5,234m), and commenced production in October 2000, with gross forecast production of 18,500 boe/d for 2019. It lies within block 22/30b Area B Rest of Block, part of licence P188, and produces gas and condensate from the Late Jurassic Fulmar Formation and the Middle Jurassic Pentland Formation. Shearwater licence P188 partners are currently Shell UK Ltd (28% + Op), ExxonMobil via Esso Exploration and Production UK Ltd (44.5%), and BP via Arco British Ltd (27.5%).

Premier has agreed to acquire the Andrew Area and Shearwater assets from BP for US$625 MM as well as a 25% extra in the Tolmount Area from Dana for US$191 MM plus contingent payments of up to US$55 MM. Andrew involves 50%-100% interests in 5 fields + operatorship

On 1 December 2017, Central European Petroleum Ltd (CEP) was granted the 9/2017/Ł Wolin contract in northwestern Poland. The 593 sq km Wolin block is located in the Zachodniopomorskie political provinces, approximately 50 km north of the city of Szczecin, within the country’s grid blocks 61, 62, 81 and 82. In a geological sense, the area on offer falls within the Pomeranian High, tectonic unit of the Northeast German-Polish Basin.

Poland, not found

According to official reports by state company YPFB in early-April 2020, operations on Total's Nancahuazu X1 ST new-field wildcat (NFW) well in the Azero block has been normalized after the governments of Lagunillas Municipality and Santa Cruz Department, in conjunction with the state company, successfully facilitated the process of personnel replacement on the site despite the quarantine in force in the country due to the outbreak of coronavirus disease 2019 (COVID-19). Last activity reports from March 2020 indicated that the operator was drilling ahead below 4,113 m (13,494 ft) on the sidetracked well in late-February 2020. Nancahuazu X1 ST was recently re-entered in November 2019 after it was previously suspended at the depth of 3,127 m (10,259 ft) due to force majeure during the recent political crisis in the country in late-October 2019. It was sidetracked from the original well earlier in the same month at the depth below 3,100 m (10,175 ft) after the original was P&A’d in mid-October 2019. The original well was initially spudded with planned depth of 5,200 m (17,060 ft) and objective in the Huamapampa Formation. Total operates the block with 50% interest, while partner Gazprom holds the remaining 50% equity, although a subsidiary of state company YPFB, YPFB Azero, will gain 55% interest if the well is successful. The Azero block covers 7,856.25 sq km of land on the Sub-Andean Zone of Chaco Basin, between the departments of Chuquisaca and Santa Cruz. Contract for the Azero block was signed between the companies in August 2013, before it was made official in June 2014. Total officially started exploration activities in the block with a magnetotelluric (MT) survey that was completed in late-December 2016. Background Information YPFB has estimated the potential of the Azero block at 5 Tscf of gas. According to reports from 2017, planned investment for the block was said to be around USD 80 million for the drilling of Nancahuazu X1 (sometimes listed as Nancahuasu) and followed by Nancahuazu X2, pending on positive results.

According to official reports by state company YPFB in early-April 2020, operations on Total's Nancahuazu X1 ST new-field wildcat (NFW) well in the Azero block has been normalized after the governments of Lagunillas Municipality and Santa Cruz Department, in conjunction with the state company, successfully facilitated the process of personnel replacement on the site despite the quarantine in force in the country due to the outbreak of coronavirus disease 2019 (COVID-19). Last activity reports from March 2020 indicated that the operator was drilling ahead below 4,113 m (13,494 ft) on the sidetracked well in late-February 2020.

On 27 April 2019 Equinor used the “Transocean Spitsbergen” S/S to spud exploration well 6507/3-13 on the Snadd Outer Outer prospect in PL 159 B. TD was reached at 3,420 m (3,380 m TVDSS) in the Lower Cretaceous Lyr Formation and on 7 June 2019 the well was abandoned. The primary target was the Upper Cretaceous Lysing Formation and there was a secondary target in the Cretaceous Lange Formation named Black Vulture. The well encountered 25 m of the Lysing formation, including a gas column of 5 m with poor to good reservoir quality. Within the Lange formation, 25 m sandstone layers were encountered in which oil and gas was proven and 14 m had moderate reservoir properties. Estimated recoverable reserves are 1.9-12.6 MMboe in the Lysing formation and 0.6 – 50.3 MMboe in the Lange formation. Technical problems occurred whilst drilling 6507/3-13 A which prevented delineation of the Lange formation resulting in uncertainty in the recoverable volumes. The Snadd Outer Outer prospect lies to the northeast of Snadd Outer which was drilled by BP with 6507/3-9 S in 2012. Snadd Outer has a Lysing Formation reservoir and recoverable reserves at the time of discovery were given as 42-81 Bcfg. The discovery will be brought onstream in Phase II of the Aerfugl development (planned for 2020 / 2021). Aerfugl, which was previously called Snadd, lies to the southwest of Snadd Outer. Aerfugl has estimated recoverable reserves of 975-1,653 Bcfg plus 31-48 MMbc in its Lysing Formation reservoir. Interest in PL 159 B is divided between Equinor Energy AS (53% + operator), DNO through Faroe Petroleum Norge AS (32%) and INEOS E&P Norge AS (15%).

6507/03-13 (Snadd Outer Outer) (Equinor 53% op, DNO 32%, INEOS 15%) in PL 159 B, P&A, o&g disc, found a total of between 2,5 and 63 MMboe both in the primary target in the Lysing Fm (5m of net pay in a sst. reservoir of poor-to-good quality in the Lysing Fm. and the secondary Lange structure (14m of moderate-quality reservoir).

GeoPark announced in April 2020, in its first quarter operational update, that it would plug and abandon the Huillin 1 prospect in the Isla Norte Block, after it encountered non-commercial oil. This commitment well reached a total depth of 2,875m and petrophysical logging was conducted. It targeted the Cretaceous Springhill and Jurassic Tobifera formations. GeoPark operates the block with a 60% working interest while partner ENAP has the remaining 40%. GeoPark disclosed in February 2020 that it would pursue a three well exploration drilling program in Q1 2020 with a focus on oil prospects. One of the wells included the Huillin 1 exploration well in the Isla Norte Block. The final exploration well in the campaign was planned to be the Koo 1 in the Campanario Block where GeoPark has a 50% working interest.

Huillin X 1 nfw. (GeoPark 60% op, ENAP 40%), committed well in Isla Norte block, logged as non-commercial, to P&A. Targets Tobifera + Springhill Fm's. TD=2876m.

CBM appraisal under Mahalo project in ATP 1191-P, Denison Trough, Bowen-Surat Basin, susp. gas at TD 300m on 5 Nov ’18, Silver City 20 rig. Santos (op), partners Comet Ridge + Australia Pacific LNG.

CBM appraisal under Mahalo project in ATP 1191-P, Denison Trough, Bowen-Surat Basin, susp. gas at TD 300m Santos (op), partners Comet Ridge + Australia Pacific LNG.

Kavitam ML, onshore KG Basin, 2019 well to TD ca. 4,000m, tested ab. 13 MMcfg/d.

Gummaturu 1 npw. in Kavitam ML, suspended

Pantheon is setting up a data room with a view to farmout its North Slope holdings in which it holds 75-90%. Two contingent wells are planned this winter, Talitha + Alkaid/Phecda oil prospects S. of Deadhorse.

Pantheon is setting up a data room with a view to farmout its North Slope holdings in which it holds 75-90%. Two contingent wells are planned this winter, Talitha + Alkaid/Phecda oil prospects S. of Deadhorse.

In late November 2017, YPF was reported to be divesting an 11% interest to Pentanova through the signing of a heavy oil development project for the 96 sq km Llancanelo Block, in the Mendoza province portion of the Neuquen Basin. The total investment expected is US$ 54 million for the next 3 years. Argentine operator, Roch had already divested its 10% interest on the block in October 2017. Pentanova also recently acquired Alianza Petrolera, previously owned by Hong Kong's Petro AP. Pentanova in August 2017, completed the acquisition of the 29% stake of Alianza in this block and an additional 11% from YPF for US$ 40 million. Pentanova will now hold 61% total interest in the block though YPF remains as operator and keeps 39% interest as well. This agreement also provided preferred rights to negotiate on the surrounding Llancanelo R Block 1 block which is held 100% by YPF. Llancanelo produces an average of 1,280 b/d of heavy oil. Pentanova expects to complete a US$ 200 million investment plan in various licenses in Argentina in the near future.

Argentina, Llancanelo

SundaGas and Timor GAP were awarded production sharing contract (PSC) TL-SO-19-16, located in the Bonaparte Basin, on 8 November 2019. The PSC has been awarded for a seven year period and will expire, or be eligible for renewal, in November 2026. SundaGas is making its entry into East Timor with the award of 75% interest in the PSC and operatorship. Timor GAP, East Timor's national petroleum company, has been awarded the remaining 25% as joint venture partner. Under the terms of the award, minimum work commitments have been assigned to the block. These include seismic reprocessing, of 800 sq km 3D and 2,000 km 2D in years 1-3, an exploration well and post well studies in years 4 and 5 and in years 6 and 7, development planning, plus two further wells: either exploration or appraisal. The block contains the Chuditch gas and condensate discovery, which was made in November 1988, with reservoir encountered in the Plover Formation. TL-SO-19-16, which covers an area of around 3,571 sq km, was awarded on 8 November 2019. Participants in the PSC are SundaGas (75% + Operator) and Timor GAP (25%).

ANPM signed the PSC contract for Block TL-SO-19-16 with a JV between privately-owned SundaGas and national oil company Timor Gap.

OML 28, central onshore Delta, ops terminated Aug ’18, no results yet. PTD was 5,000m, target HP deep gas. Hilong rig 27. Note: erstwhile designated Epu Deep-1X. Shell (op), partners NNPC, Total + NAOC.

Epu-5 nfw in OML 28 central onshore Delta, ops terminated Aug ’18, no results yet. PTD was 5,000m, target HP deep gas.

On 19 October 2017, Woodside reported that wildcat Khayang Swal 1 in Block AD-7, in deepwater Rakhine Basin, was dry. The well was plugged and abandoned in late September 2017 after encountering water-wet sandstones in the Pliocene turbidite target. Final TD for the well was 3,693 m. Khayang Swal 1 was spudded on 28 August 2017 using Transocean’s “Dhirubhai Deepwater KG2” drillship, at a water depth of 1,487 m. After completing the well, the drillship was released by the operator. The high-impact well was likely targeting a previously undrilled channel complex located at the southern edge of the block, some 25 km south of the significant Thalin 1A discovery. The Khayang Swal prospect was estimated to contain resources in the order of multiple Tcf of gas. PTD of the well was 3,815 m. Khayang Swal 1 was the fifth and final firm well drilled by the “Dhirubhai Deepwater KG2” which was contracted by Woodside for a long-term exploration drilling campaign in blocks AD-7 and A-6. Woodside previously reported plans to drill at least one additional contingent well in block AD-7 in late 2017, and potentially further wells in 2018. However the 2017 campaign has been completed, and the future drilling plan could depend on the full evaluation of results from the latest campaign. The drilling campaign commenced in late February 2017 with appraisal sidetrack well Thalin 1B in block AD-7, followed by the second appraisal Thalin 2. Thalin 1B successfully tested gas at a rate of 50 MMcf/d. Thalin 2 was completed in early June 2017, encountering gas shows in the targeted reservoir. The rig subsequently moved to block A-6 for a two-well programme (Pyi Thit 1 and Pyi Tharyar 1). The rig mobilized to the Khayang Swal 1 location in late August 2017 after the completion of the two wells in block A-6. Woodside has reported an estimated expenditure of around USD 100 million for exploration activities in Myanmar in 2017. A seafloor sampling campaign over blocks AD-7 and A-6 was conducted between around 22 December 2016 and 15 January 2017, using the “Fugro Supporter” MV. Approximately 990 km of MBES data were likewise acquired during the survey. An Environmental Impact Assessment (EIA) for the campaign in Block AD-7 was ongoing in early September 2016 with project report, scoping report and terms of reference submitted to the government. Drilling scoping report for Block A-6 had not yet been submitted as of October 2016. A positive outcome of the 2017 exploration drilling campaign may result into further drilling of up to four wells over 2018 and 2019, subject to the approval of joint venture partners. The Thalin 1A discovery is estimated to contain 2C resources of 1.5 Tcf of dry gas. Development options under consideration include a tie-back to the existing infrastructure at POSCO Daewoo’s Shwe field complex, or a new hub for broader gas aggregation and export. The development concept is expected to be finalized in early 2018, pending approvals from partners and the government. Block AD-7 is jointly operated by POSCO Daewoo with 60% interest (PSC operator) and Woodside Energy Myanmar with 40% (deepwater drilling operator). During the first half of 2016, 3D seismic survey and drilling of the Thalin 1 gas discovery was conducted in block AD-7.

Khayang Swal 1 op. by Posco Daewoo (blk op. 60%), Woodside (well op. 40%) in AD-7 block, P&A, dry after encountering water-wet sandstones in the Pliocene turbidite target.

P15-13 field in block P15a, compl. gas below 4,300m on 13 Dec '19, Maersk Resolute JU. Taqa (op), partners One-Dyas, Dana Petr., RockRose, Wintershall Dea + EBN.

P15-20 (G2) expl/appr in P15-13 field in block P15a, compl. gas below 4,300m on 13 Dec '19, Maersk Resolute JU. Taqa (op), partners One-Dyas, Dana Petr., RockRose, Wintershall Dea + EBN.

Offshore block E, Bay of Gazimagusa, Latakia Basin (Mediterranean), WD 250m, ops terminated late Jan '20, Fatih DS off to Narlikuyu-1. PTD believed ca. 3,300m.

Famagusta 1 nfw (TPAO 100%) in the Block E licence, completed, No well results yet.

Ref. DEA 31 Jan ’19, Talon has acquired EnCounter Oil in a move which involves the Rocket + Skymoos prospects in P2363 + P2392 off Aberdeen. It is recalled EnCounter had been offering equity in return for funding a GBP 9 MM well to test both prospects in the Verbier + Catcher areas. It appears that Talon is pursuing the farmout effort.

Talon has acquired EnCounter Oil in a move which involves the Rocket + Skymoos prospects in P2363 + P2392 off Aberdeen.

ATP 2043-P,  384 sq km in the Bowen-Surat Basin, was awarded 1 Aug ’19 for 6 years, formerly PLR2018-1-8 under the 2018 Queensland acreage releasee. Plans include seismic reprocessing + core hole drilling.

Galilee Energy (100%) , was awarded exploration permit ATP 2043-P.

Word on the street is that Oxy is in talks over a possible sale of assets in Africa and the Middle East to Pertamina in a potentially USD 4.5 bn deal. Involved are Ghana (non-operated interests in the Tullow-operated TEN fields area (Tweneboa-Enyenra-Ntomme) + Jubilee fields) and the UAE (block 3 + various fields) and possibly Algeria and Oman at a later stage.

Ghana (Tano B.) TEN (Dev & Prod) op. by TULLOW (47%), OXY (17%), KOSMOS EN (17%), GNPC (15%), PETROSA (4%)

Južna Srbija (S. Serbia) block SE of Belgrade, drilled Jul-Oct '19, ops terminated, no details.

Bradarac-Maljurevac-2X appr Južna Srbija (S. Serbia) block SE of Belgrade, drilled Jul-Oct '19, ops terminated, no details.

On 30 January 2020, in a two-stage working interest change, the ANP granted ExxonMobil approval to transfer 50% working interest to partner Azibras and for Azibras to transfer 30% working interest to new operator OP Energia in the CE-M-603 contract, in the offshore Ceara Basin. The CE-M-603 block was operated by ExxonMobil with 50% working interest and Azibras held 50%. With the formal approval OP Energia is operator with 30% working interest and Azibras now holds 70% non-operated working interest in the CE-M-603 block. On 15 August 2018, the ANP granted ExxonMobil a 2nd contract extension for its ANP Round 11, CE-M-603 contract, in the offshore Ceara Basin. The ANP granted a 24-month extension to the first period exploration expiry from 10 July 2019 to 10 July 2021 and the final expiry from 10 July 2021 to 10 July 2023. The partners acquired 326 sq km of the PGS Fortaleza multi-client 3D survey concluded in the basin in January 2016. PGS concluded acquisition of a 7,300 sq km Fortaleza multi-client 3D seismic survey in the offshore Ceara Basin over ANP Round 11 awarded blocks during early-January 2016.The survey commenced in early September 2015. On 5 July 2017, the ANP granted ExxonMobil a contract extension for its ANP Round 11, CE-M-603 contract in the offshore Ceara Basin due to delays with the environmental permit for seismic acquisition. The ANP granted a 314-day extension to the first period exploration expiry from 30 August 2018 to 10 July 2019 and the final expiry from 30 August 2020 to 10 July 2021.

ExxonMobil transferred 35% WI in the POT-M-475 and 50% in the CE-M-603 block in the Potiguar and Ceara basins to OP Energia (Ouro Preto Oleo e Gas) and Azibras. Both blocks are undrilled. OP will now be the operator in both blocks with a 30% working interest in partnership with Azibras, which will have 70%.

S-C part of POT-T-747 block, Potiguar onshore, P&A at TD 625m 11 Dec '19, assumed dry as no shows report. Target L. Cret. Alagamar fm. Geopark (op), partner Geopar-Geosol.

1-MDC-001-RN (1-GPK-5RN) nfw ( Geopark 70% op, Geopar-Geosol 30%) targeting the Mandacaru prospect in block POT-T-747 in the was being plugged and abandoned after non-commercial hydrocarbons logged.

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

Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd have agreed a deal with Rathlin Energy (UK) Ltd (wholly owned subsidiary of Connaught Oil and Gas Ltd) on a proposed farm-in for a 16.667% interest each in PEDL 183. The licence is located in East Yorkshire and contains the West Newton A-1 gas discovery.

As of 26 August 2019, Perupetro announced it will be offering one block for bidding in the Ucayali Basin sometime before the end of 2019. The block will be called Block 201 and located in the central part of the Ucayali Basin north of TEA Area LXVI and just west of the Peru/Brazil border. There have been four wells drilled in the current configuration of the block which have been included in the table below. No official announcement has been made on the timing or details of the offering. Perupetro announced they were in the final stages preparations of base-lines and all relevant information available on the block being offered. Once additional information has been provided the article will be updated accordingly. Previously Drilled Wells               Well Name Operator Name Former Contract Name Td Meter Elev Meter Spud Date Comp Date General Status Bh Age La Colpa 1X Occidental Petrolera del Peru Inc Block 36 2926 318 26-Nov-88 8-Mar-89 P&A/Suspended Oil Mississippian La Colpa 2X Petrominerales Ltd Block 126 2591 270 1-Dec-11 1-Apr-12 P&A/Susp Dry/Shows   Shahuinto 1 Pangaea (Peru) Energy Ltd Block 71 2171 274 5-Nov-98 18-Dec-98 P&A/Susp Dry/Shows Precambrian Sheshea 1X Petrominerales Ltd Block 126 2720 290 19-Jul-12 21-Oct-12 P&A/Suspended Oil   Source: IHS Markit               © 2018 IHS Markit

As of 26 August 2019, Perupetro announced it will be offering one block for bidding in the Ucayali Basin sometime before the end of 2019. The block will be called Block 201 and located in the central part of the Ucayali Basin north of TEA Area LXVI and just west of the Peru/Brazil border. There have been four wells drilled in the current configuration of the block which have been included in the table below.

Central part of Guyane Maritime block, WD ca. 2,000m, now confirmed dry but no further details. Ensco DS-9.

GM-ES-6 (Nasua) nfw, Central part of Guyane Maritime block, WD ca. 2,000m, now confirmed dry, but no further details. (Total 100%)

PEMEX suspended with results unreported the Vinik 1EXP directional new-field wildcat (NFW) in the AE-0047-3M-Agua Dulce-06 (AE-0133-Cuichapa) exploration entitlement block during mid-January 2020. The NFW reached a final total depth (TD) of 4,199 m measured depth (MD) and 3,773 m true vertical depth (TVD). The NFW was spudded on 26 May 2019. The Vinik 1EXP directional NFW had a proposed total depth (PTD) of 4,099 m measured depth (MD) and 3,705 m true vertical depth (TVD) and was targeting the Cretaceous from 3,287 m to 4,099 m on a salt related anticlinal structure. The Vinik 1EXP is located in the south-central area of the block and was previously named the Robusto 1EXP prospect that was located in the AE-0050 block that was incorporated into the AE-0047 block. The well has estimated unrisked prospective resources of 78 MMboe. On 12 April 2019, the CNH approved a PEMEX request to modify the exploration plan for the AE-0047-3M-Agua Dulce-06 exploration entitlement block which included the drilling permit for the Vinik 1EXP. The total budget for the base case exploration program is USD 76.22 million with USD 73.01 million allocated to drilling the two firm commitment wells. The 1,053.63 sq km AE-0047-3M-Agua Dulce-06 exploration entitlement block was granted to PEMEX on 27 August 2014 and was relinquished on 27 August 2019. It has been superseded by the AE-0133-Cuichapa entitlement granted on 28 August 2019 and covers an official area of 1,057.49 sq km.

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

Providence is farming out interest in Frontier Exploration Licence (FEL) 6/14 (blocks 61/13a, 61/14, 61/15, 61/18a, 61/19a, 61/20a, 62/11a and 62/16a). The acreage is located on the margins of the southern Porcupine Basin in the Goban Spur Province approximately 260 km off the southwest coast of Ireland. The acreage was originally awarded to Providence (80%) and Sosina (20%) in October 2011 as LO 11/11 in the 2011 Irish Atlantic Margin Licensing Round. In April 2014, LO 11/11 was converted to 15 year FEL 6/14 and kept the same working interests. Providence is looking for a partner to drill exploration well 62/11-A targeting the Newgrange prospect. As of October 2018, Providence was still in discussion with potential farminees, drilling could take place in either 2019 or 2020 (subject to regulatory consent). The latest internal well cost estimate is less than USD  15 million, exclusive of mobilisation. On 18 June 2018, two months ahead of schedule, Providence reported that Gardline had mobilised the M/V Kommandor vessel to complete a site survey. On 11 July 2018, Providence announced the site survey vessel has commenced demobilisation following the acquisition of data suitable for input to an application for the permitting of a Newgrange exploration well. Initial analysis of the seabed data over the proposed Newgrange well location confirmed the presence of more than 100 seabed pockmark features. On 15 October 2018, Providence announced that after a third party evaluation of the data collected in July 2018, 262 pockmarks were identified. Geochemical analysis of seabed samples has confirmed the presence of both biogenic and thermogenic hydrocarbon sourcing signatures indicating the pockmarks are possibly related to hydrocarbon migration. In addition, high resolution sub-bottom 2D data has revealed buried pockmark fields up to c. 100 m beneath the seabed possibly indicating active hydrocarbon migration over a prolonged period. The Newgrange prospect is calculated to have Pmean in-place resources of 13.6 Tcf GIIP or 9.2 Bbo STOIIP. The Newgrange prospect consists of two large stacked four-way structural closures at both Base Cenozoic and Base Cretaceous covering an area of 1,204 sq km. Newgrange is similar to the Dunquin North residual oil accumulation which targeted a Lower Cretaceous Carbonate play type The prospect is likely to have good carbonate reservoir facies from facing the paleo wind direction during deposition. The top seal has been identified as the key risk due to its thin nature. Providence undertook seal capacity analysis in 2016 where the top seal was estimated to potentially contain a ~350 m hydrocarbon column. Additional vertical stacking prospectivity has been identified from the underlying Jurassic clastics. The Newgrange prospect is located in ~1,000 m water depth with the crest of the Cretaceous target ~500 m BML. The presence of a working hydrocarbon system is proven from the adjacent 62/07-1 exploration well drilled by ESSO in 1982. The well encountered an Eocene Top Seal supported by an 8 m Aptian ‘Drowning Shale’. Thick, high porosity Cretaceous Carbonate facies and a 30 m high quality Jurassic reservoir were also penetrated. The source was interpreted as a 170 m thick, low TOC, Low HI and early mature gas prone source. Interest in FEL 6/14 is held by Providence Resources plc (80% + operator) and Sosina Exploration Limited (20%). For further information please contact: John O'Sullivan Email: [email protected]

Providence is farming out interest in Frontier Exploration Licence (FEL) 6/14 (blocks 61/13a, 61/14, 61/15, 61/18a, 61/19a, 61/20a, 62/11a and 62/16a). The acreage is located on the margins of the southern Porcupine Basin in the Goban Spur Province approximately 260 km off the southwest coast of Ireland.

On 6 June 2018, Zhongman Petroleum and Natural Gas Group was officially awarded exploration license Wensu Block in the onshore Tarim Basin. Wensu Block covers approximately 1,086 sq km and was offered in the 2017 Xinjiang Oil & Gas Bid Round. Zhongman won the right to explore the block with a winning bid of 866.87 million RMB (~ US$ 136 million) for an initial five year exploration period. Zhongman is the operator and sole rightholder of the Wensu Block.

China, Wensu

Petronas Carigali has plugged and abandoned new field wildcat Nuri 1 in block ND-4, situated in the ultra-deep water Northwest Sabah Platform, on or around 19 December 2019. Result have not been released. The well, spudded on 19 September 2019, was drilled using the Seadrill "West Capella" D/S and targeted the Lower Oligocene clastics. Nuri 1 is located approximately 40 km north of Tepat 1 gas discovery, drilled by Total in 2017. Falkon 1 (2016) was the last well drilled in the block. The well, spudded on 15 September 2019, was drilled using the Noble "Noble Bully II" D/S and it likely tested the Upper Eocene to Oligocene clastics and Lower to Middle Miocene limestone sequence targets. The well was plugged and abandoned as a dry hole on 18 November 2016. Farm-in opportunity still exist for the block. Block ND-4 is 100% held and operated by Petronas Carigali. Background Information The block is covered with extensive 2D and 3D seismic data, electromagnetic and CSEM acquired by previous and current operators of the block. A 11,000 line km 2D seismic survey was acquired in 2008 followed by Controlled Source Electromagnetic (CSEM) survey between June 2010 and September 2010 using the EMGS "Boa Galatea" S/V. Two 3D seismic surveys were acquired in block ND-4 and ND-5. The first survey, approximately 6,000 sq km survey covers an area within both operated blocks, ND4 and ND-5 on the northern part was acquired between September 2014 and February 2015 with CGG "Alize" S/V. The 5,200 sq km survey was acquired by PGS "Ramform Sovereign" S/V between October 2016 and December 2016. The second survey was part of the Sabah Multi-Client 3D (Sabah MC 3D). The electromagnetic (EM) survey acquired between October and December 2015 using the EMGS "Boa Thalassa" S/V. Two wells were drilled in the block between 2012 and 2016. Rajawali 1 (2012) did not reached its primary target, the Oligocene clastic at prognosed depth of 2,200 m due to severe mud loss while drilling through the Middle Miocene carbonate sequence. Falkon 1 (2016) was drilled approximately 30 km east of Rajawali 1. Both wells targeted the Upper Eocene to Oligocene clastics and Lower to Middle Miocene limestone sequence. The wells were plugged and abandoned as dry holes. Block ND 4 and ND 5 was awarded to Petronas Carigali (100%) as the operator on 29 July 2005. Block ND 4 is approximately 10,500 sq km in size and located in water depth of 1,000 m to 3,000 m. The ultra deepwater areas of North West Sabah are likely to be predominantly gas provinces and include an undrilled synrift play, carbonate buildup equivalent to the Oligocene Nido carbonate play in the Philippines as well as the possible distal extensions of the Upper Miocene turbidite plays similar to Petronas's Hebat and Kental discoveries, located in Block 3K.

Nuri 1 nfw. (Petronas 100%) in ND-4, ultra-deepwater NW Sabah Platform, P&A results n/a. Target L. Oligocene clastics. The wholly-owned block is open for farmin.

On 1 September 2018 Tailwind Energy completed the acquisition of Shell’s and ExxonMobil’s interest in the Triton Cluster in the Central North Sea. Under the deal Tailwind has acquired 29.26% in licence P361, 64.63% in the unitised Bittern licence, 100% interest in licences P1792 and P233 blocks (029/01a Bittern Area), P013 (021/25a Guillemot W / NW (Upper), 021/30a Guillemot W / NW (Upper), Gannet E and 50% interest in P215. The Triton Cluster comprises of Guillemot NW, Guillemot W, Bittern and Gannet E. Bittern was developed jointly with Guillemot West and Guillemot Northwest as part of the Triton project. The Triton project was initially a subject of controversy as the respective operators of the two blocks it straddled failed to agree on a development scheme. A joint development scheme for the field was finally agreed on 5 November 1997. The solution involved the development of Bittern jointly with Guillemot West and Guillemot Northwest as a subsea development tied back to a new-built FPSO vessel, moored mid-way between the fields. Bittern came on stream on 15 April 2000 and production commenced from the Guillemot Northwest and Guillemot West fields on 20 April 2000. Gannet E is in the process of being redeveloped via a tie-back to three existing wells to the Gannet Alpha platform and then on to the Titron FPSO. Gannet E was shut in, in 2011, but is expected back onstream later in 2018. Following the completion of this deal interest in P361 is held by Dana Petroleum (E&P) Ltd (65.90% + operator), Tailwind Energy Ltd (29.26%) and Endeavour North Sea Ltd (4.84%). In the Bittern unitised licence the interest is held by Dana Petroleum (E&P) Ltd (32.95% + operator), Tailwind Energy Ltd (64.63%) and Endeavour North Sea Ltd (2.42%). In Licences P1792 + P233 (029/01a Bittern Area), P013 (021/25a Guillemot W / NW (Upper) + 021/30a Guillemot W / NW (Upper) + Gannet E, Tailwind holds 100% interest. Lastly in P215 interest in the licence is now held by Dana Petroleum (E&P) Ltd (50% + operator), Tailwind Energy Ltd (50%).

Tailwind Energy has agreed to acquire the entire UK business of EOG Resources, which include 100% in the Conwy field and 110/12a-1 Corfe discovery in the East Irish Sea, a 25% interest in the Columbus gas development and also interest in number of Southern North Sea licences.

As announced on 7 July 2020, Zenith Energy Ltd. (Zenith) has entered into a joint venture agreement with a local oil & gas company in the Republic of the Congo. The primary objective of the agreement is the potential acquisition of an unspecified onshore oil production licence. According to the release the field that Zenith is targeting last producing at a rate of roughly 300 bo/d from the regionally proven Mengo formation as recently as 2019. Production has suspended pending the assignation of a new licence. The potential acquisition is in the Kouilou region of the Republic of the Congo in proximity of Pointe-Noire. Under the terms of the Agreement, Zenith and its local partner will jointly apply to the relevant authorities in the Republic of the Congo, including the Ministry of Hydrocarbons, for the award of a new licence. In accordance with the agreemnt, it is stipulated that Zenith shall have the role of joint operator and majority partner in the event a new licence is successfully obtained. Following preliminary technical analysis, as part of the due diligence activities conducted prior to entering into the agreement, Zenith is confident that profitable oil production operations can be achieved following the reactivation of the field and the performance of targeted reached following low-intensity workover activities. Background information In May 2020, Zenith completed the acquisition of Anglo African Oil & Gas Congo S.A.U (AAOGC) a wholly owned subsidiary of Anglo African Oil & Gas plc and hence holds a 56% interest in the Tilapia permit.

Congo (Lower Congo B.), as announced on 7 July 2020, Zenith Energy Ltd. (Zenith) has entered into a joint venture agreement with a local oil & gas company in the Republic of the Congo. The primary objective of the agreement is the potential acquisition of an unspecified onshore oil production licence.

Petrobras intends to hold preferential rights in the 5th PSC Pre-Salt round, focusing on the 125-sq km Sudoeste de Tartaruga Verde block with at least 30%.  That would leave the Pau Brasil, Saturno, and Tita blocks available for operatorship to any other company.   Maps + more details/background from GEPS.

Petrobras intends to hold preferential rights in the 5th PSC Pre-Salt round, focusing on the 125-sq km Sudoeste de Tartaruga Verde block with at least 30%. That would leave the Pau Brasil, Saturno, and Tita blocks available for operatorship to any other company.

Lufeng Sag in PRMB, South China Sea, WD 120m, ops terminated late Mar '20, results n/a, Nanhai 2 SS. Target Mio-Oligocene clastics.

Lufeng 7-8-1 (LF 7-8-1) Lufeng Sag in PRMB, South China Sea, WD 120m, ops terminated late Mar '20, results n/a, Nanhai 2 SS. Target Mio-Oligocene clastics.

BP preparing to drill El Basant South 1 exploration block in the El Matariya Onshore exploration block, Nile Delta.  The primary objectives in the area are the Miocene sands. The well will be drilled south of the Dana Gas’ El Basant gas and condensate field that was discovered in 2008 by Centurion Petroleum and started producing in 2009 from the Qawasim Formation. The El Basant field is a part of the same gas accumulation as the Abu Zahra Northeast field on a neighboring concession and a commercial arrangement had been put in place between the two owners to allow Melrose to produce the field until its share of the reserves had been depleted. BP operates the El Matariya Onshore block with a 50% interest, while Dana Gas holds the remining 50%. The El Matariya Onshore Concession Area is located onshore Nile Delta adjacent to Dana Gas’s existing West El Manzala and West El Qantara Development Leases and the recently acquired North El Salhiya (Block 1) Concession Area. Background information On 29 December 2008, Dana Gas PJSC found gas in El Basant 2 outpost in the West Manzala exploration block after encountering 37m of net sand pay with good porosity and permeability in the Messinian Qawasim Formation. The well, located 1.5km northeast of the El Basant 1 gas discovery (previously known as Al Tawil 1), was spudded on 6 December 2008 and drilled to TD of 3,050m. On 2 June 2015, Dana Gas announced that it had finalized an agreement with BP for the drilling of an exploration well in the onshore El Matariya (Block 3), Nile Delta. Under the terms of the agreement, BP as the operator will carry Dana Gas for its 50% share of the cost of the well, subject to an agreed cap of USD 39 million. In Early March 2017, BP abandoned Mocha 1 wildcat in the onshore El Matariya (Block 3), Nile Delta after encountering non-commercial quantities of gas in the Oligocene, which was the target. The well was spudded in early May 2016 and drilled to a TD of 5,940 m. It has the Oligocene layer as the objective and a planned TD at around 6,000 m. Wet gas was encountered in the Messinian layer during drilling. In early February 2018, BP abandoned the Khairat Downthrown 1 (Jd 64-7) exploration well in the onshore El Matariya (Block 3), Nile Delta after the well penetrated a good Messinian reservoir interval but was water wet. The well was spudded on 31 December 2017 with the “EDC-9” land rig and drilled to a TD around 3,300 m. It has objectives in the Miocene layer and a planned TD of 3,306 m. In April 2018, BP suspended the Nafahat West 1 wildcat in the onshore El Matariya block (Block 3), Nile Delta basin. The well was spudded on 26 February 2018 with the “EDC-9” land rig. It has the Messinian sands as the objective and a planned TD of 3,500 m.

Egypt (Kattaniya-Qantara High - Nile Delta B.) Qantara

As of early March 2020, Kosmos Energy Namibia (Kosmos) a partner to Shell Namibia Upstream B.V. (Shell) in the Orange Sub-basin PEL 39 (Blocks 2913A, 2914B) is understood to be looking to farm out a stake in the licence prior to drilling in early 2021. On 5 November 2019, during the Africa Oil Week conference Colette Hirstius, vice president exploration, Middle East & Africa at Shell Upstream mentioned that the company was looking to drill within PEL 39 (Blocks 2913A, 2914B) in late 2020 or early 2021. One of three prospects will be targeted – Graff, Cullinan or a third yet unnamed prospect that the company is working on. All the prospects are located at a water depth of around 2,000 m and all are different plays. The interests in the Licence are as follows: Shell operates the licence with a 45% interest, Kosmos holds a 45% stake and NAMCOR holds the remaining 10%.

Kosmos is looking to dilute its 45% in Shell-operated PEL 39 / blocks 2913A & B, 12,628 sq km in Orange Basin deepwaters, drilling planned in early 2021. Prospects Graff, Cullinan and unnamed could be targeted. Shell (op), partners Kosmos + Namcor.

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

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

As announced on 4 February 2018, Strata-X Energy Ltd was awarded prospecting licences (PL018-2018 and PL019-2018) covering previously operated licences (PL352/2008 and PL353/2008). The licence periods are as follows: Initial period three years, followed by two two year periods (3+2+2). Strata-X via its subsidiary Strata-X Australia Pty Ltd created a new Botswanan subsidiary Sharpay Enterprises Pty Ltd (Sharpay) holds the aforementioned licences. PL018-2018: includes the following blocks: PL018-2018a, PL018-2018b, PL018-2018c these were previously held as PL352/2008a, PL352/2008b and PL352/2008c. PL019-2018: includes the following blocks: PL019-2018a, PL019-2018b and PL019-2018c these were previously held as PL353/2008a, PL353/2008b and PL353/2008c. Strata-X via its subsidiary Strata-X Australia Pty Ltd holds a 100% interest in Sharpay. Sharpay holds the aforementioned licences with a 100% interest.

Botswana (Nama-Kalahari B.s) (It's a petroleum rights. Please summarize by yourself). In IHS database: PL353/2008c op. by RHINO CBM (100.0%) to be check.PL353/2008b op. by RHINO CBM (100.0%) to be check.PL353/2008a op. by RHINO CBM (100.0%) to be check.PL352/2008b op. by RHINO CBM (100.0%) to be check.PL352/2008c op. by RHINO CBM (100.0%) to be check.PL352/2008a op. by RHINO CBM (100.0%) to be check.

Add. DEA 16 Dec '19 (conversions): Commitments to the new EPSAs call for the drilling of 2 explo wells in Area 107 + 1 in Area 91. USD 100 MM signature bonus + USD 50 MM over 10 years for corporate social responsibility. The EPSAs have been made retro-effective 1 Jan '08. Release here.

Add. DEA 16 Dec '19 (conversions): Commitments to the new EPSAs call for the drilling of 2 explo wells in Area 107 + 1 in Area 91. USD 100 MM signature bonus + USD 50 MM over 10 years for corporate social responsibility.

Jadestone has agreed to take over a 69% stake + operatorship from OMV in the Maari project in PMP 38160, offshore Taranaki Basin, for USD 50 MM cash. The deal includes the Maari + Manaia oilfields, an FPSO, plus 4,000-4,500 bo/d net. The deal will be made retro-effective 1 Jan '19.

New Zealand (South Inversion Zone (Taranaki B.)) Manaia

21/97/p Lubaczow-Zapalow block, Outer Carpathian Foredeep in SE Poland, P&A dry at TD 630m (Jurassic) in mid-May, Cooper LTO 550 rig. Main target Sarmatian-Badenian clastics.

Sosnina 1 (PGNiG 100%) in 21/97/p Lubaczow-Zapalow block, P&A dry.

As of mid-March 2019, Divine Inspiration Group Ltd (DIG Oil) is still understood to be looking for partners to explore its onshore Mopongo permit, in Cuvette Centrale Basin. Congo Authorities granted the block to DIG Oil as operator with 80% working interest (WI), Société Nationale des Pétroles du Congo (SNPC) hold 10% WI and a local partner has a 10% interest. The 12,700 sq km Block Mopongo is located at the country northeastern extremity, over the Carnot and Busira Sub-basins, in the northwestern sector of the Cuvette Centrale Basin (Congolese name of the Zaire Basin, also known as Central Basin or Interior Basin in Congo, or Kassanje Basin in Angola). The Zaire Basin is a large frontier area where only four new-field wildcats have been drilled to date. Source and reservoir units are considered to have potential to offer several hydrocarbon generation, migration and entrapment possibilities. Trap breaching may have caused the loss of significant quantities of hydrocarbon. Secondary migration is believed to have played a determining role on the location where any present-day accumulations of oil or gas.

Divine Inspiration Group Ltd (DIG Oil) is still understood to be looking for partners to explore its onshore Mopongo permit, in Cuvette Centrale Basin. Congo Authorities granted the block to DIG Oil as operator with 80% working interest (WI), Société Nationale des Pétroles du Congo (SNPC) hold 10% WI and a local partner has a 10% interest.

Petrobras has issued a teaser for the sale of 50-100% of its 80% operating stake in BM-S-051, 698 sq km in the Santos pre-salt polygon, WD 350-1,650m off São Paulo. Partner Repsol Sinopec.

Brazil (Santos B.) BM-S-051 op. by PETROBRAS (80%), REPSOL (12%), SINOPEC (8%)

CNH-RO1-LO2-A1/2015 (aka Area 1) contract, ab. 1.5km NE of discovery in WD 33m, offshore Sureste Basin / Campeche Bay, TD 4,220m, 40m net oil pay in the Orca fm, excellent sst reservoir, 27m net oil again in the deeper Cinco Presidentes fm, testing planned after which the well will be suspended. West Castor JU.  Amoca, Miztón and Tecoalli now vouch for 1.4-2 Bboe in place in Area 1, 90% oil. The PoD for Area 1 will soon be submitted to the CNH for approval. Production target 1H ‘19.

Tecoalli 2DEL appraisal well by Eni (100%) in Area 1 (CNH-R01-L02-A1/2015), 40m of net oil pay in the Orca fm, characterized by excellent quality sst. reservoirs. The well was then deepened to the Cinco Presidentes fm. explo. target, finding further 27m of net oil pay. Thanks to the results of this well and the revision of the reservoir models of the Amoca and Miztón fields, the hc in place estimate for Area 1 is boosted from 1,4 to 2,0 Bboe, of which approx. 90% is oil and the remaining associated gas.

Harcourt secured ATP 2027-P,  505 sq km in the Nebo Syncline, Bowen-Surat Basin, on 13 Nov ’17 for 5 months to 30 Apr ‘18. It replaces ATP 564-P with CBM local targets. Harcourt (op), partner Mitsui.

Australia (Bowen - Surat B.s) (It's a petroleum rights. Please summarize by yourself). In IHS database: ATP 564-P op. by PETROCHINA (67.12%, MITSUI 32.88%) to be check.ATP 2027-P op. by HARCOURT (33.56%, HARCOURT Q 33.56%, MITSUI 32.88%) to be check.

Tap Oil Ltd reported on 30 September 2017 that it commenced the process to withdraw from retention lease WA-49-R, located in the North Carnarvon Basin. Withdrawal was subsequently completed in May 2018. In doing so, the farm-in opportunity which was being offered by Tap is no longer valid. Tap had reported that was seeking to sell its 10% interest in the permit, which covers an area of 107 sq km over the Zola, Bianchi and Antiope discoveries. Tap stated that although discoveries are located in the permit, Tap’s share price has not seen the value from these and there are no immediate development plans for the assets. Therefore Tap has been looking to monetise the assets through a sale of its interest. The Zola discovery, which was made by the current Joint Venture in April 2011.  Zola is a gas condensate discovery, with estimated 2P recoverable reserves of 346 Bcfg and 4 MMbc. The Bianchi discovery also extends into WA-49-R, a further gas condensate discovery with 2P recoverable reserves of 150 Bcfg and 2.5 MMbc.  The Antiope and Lauda discoveries are also in the block, made in January 2000 and April 2005 respectively. These have 2P recoverable reserves of 120 Bcfg with 120 Mbc and 9 MMbo respectively.  It was previously reported that Zola and Antiope could be developed together. Operators Quadrant Energy acquired over 200 sq km of new 3D seismic survey data over WA-49-R and adjacent exploration permit WA-290-P (from which WA-49-R was established). The survey was completed in 2017 and the data, which is currently being processed, will aim to provide further information on the Triassic Mungaroo prospects in the region which, in the case of success, could provide a viable development scheme for the WA-49-R fields. Tap continues to also look at selling its remaining non-core asset interests in four other licences/permits within the North Carnarvon Basin: with WA-8-L, WA-33-R, TL/2 and TP/7. On 14 June 2017 Tap reported that it has entered into a sale and purchase agreement with a private E&P company for the sale of its 20% interest in WA-08-L. The interest is being sold for AUD 800,000 to an undisclosed party at this stage. Operator Santos Ltd and joint venture partner Kufec Australia are also looking to exit the permit along with the neighbouring Exeter/Mutineer/Fletcher/Finucane fields, to focus on core assets, which does not include Western Australia oil (Santos). WA-08-L contains the Talisman and Amulet oil fields. At the time of the initial farm-in offer, Tap was also offering interest in WA-351-P, which covered the Tallaganda discovery. However, on 11 April 2016, operator BHP was awarded retention lease WA-72-R over the field. Upon the award of WA-72-R, the joint venture decided not to renew WA-351-P which will expire in June 2016. The Tallaganda gas discovery (2012) has estimated 2P recoverable reserves of 231 Bcfg and 1.1 MMbc within the Triassic Mungaroo Formation. Companies interested in pursuing opportunities with Tap Oil were to contact: Silvano Pagnozzi, Senior Geophysicist Tap Oil Limited, Level 1, 47 Colin Street, West Perth, WA 6005 Phone: +61 8 92267835 Email: [email protected]

Australia, WA-49-R

RockRose Energy announced on 3 August 2017 that it had agreed a sale and purchase agreement to acquire the entire issued share capital of Sojitz Energy Project Limited for a consideration of USD 2.5 million. The company will receive USD 1.7 million at completion of the deal to reflect an effective economic date for the transaction of 1 January 2016. The deal completed on 22 December 2017. The assets involved in the deal include a 15% interest in the Tors field unit area which includes the Kilmar (P683) and Garrow (P1034) fields which are linked to the Trent field. A 7.5% interest in the Grove field unit area (P083 and P901) and a 10% interest in the Seven Seas field (P1354). Sojitz Energy Project Limited also held a 13.5% interest in the Gryphon field but this is understood to not be part of the deal and will likely be awarded to a different Sojitz subsidiary. RockRose’s strategy is to build a portfolio of mature producing assets with a view to extend the field life giving the company access to significant tax losses. The recently established company has undertaken deals with Egerton Energy, announced in March 2017, to acquire Egerton’s interest in the Galahad and Mordred fields in the Southern North Sea and also agreed a deal with Maersk in December 2016 to acquire its interest in the Scott and Telford fields.

RockRose Energy has agreed to acquire entire issued share capital of Sojitz Energy. The assets involved in the deal include a 15% interest in the Tors field unit area which includes the Kilmar (P683) and Garrow (P1034) fields which are linked to the Trent field. A 7,5% interest in the Grove field unit area (P083 and P901) and a 10% interest in the Seven Seas field (P1354).

On 29 January 2018, Geopark with 100% working interest was granted an official award by the ANP for the POT-T-785 block in the onshore Potiguar Basin from the ANP Round 14.   

Geopark with 100% working interest was granted an official award by the ANP for the POT-T-785 block in the onshore Potiguar Basin from the ANP Round 14.

During Q4 2019, Occidental Petroleum Corp (Oxy) plugged and abandoned the Hafar South 1 NFW well on Block 62 (Habiba) in northern Oman. The well was spudded in mid-October 2019 by Abraj Energy Services' "Rig 206" around 5.6km south of the Hafar 1 NFW on Block 30 (Hafar), which is also operated by Oxy. It reached a final TD of around 1,150m in the Cretaceous Lekhwair Formation and is assumed to be dry. The Hafar 1 NFW was drilled in 1985 and discovered gas in the Cretaceous Shuaiba Formation after reaching a TD of around 1,793m. It is understood that in addition to the Shuaiba Formation, Hafar South 1 also targeted the Cretaceous Natih Formation.<P />Oxy (48%, op), Mubadala (32%) and Oman Oil (20%) signed an Exploration & Production Sharing Agreement (EPSA) for Block 62 (Habiba) in November 2008. The non-associated gas licence covers an area of 2,269 sq km in the Governorate of Ad Dakhiliyah and is valid for a 20-year term. It allows for both development and exploration of gas and condensate resources. In 2014, Oxy signed a five-year extension for the initial phase of the EPSA and acquired Mubadala's entire 32% stake. First production from the acreage was achieved in 2016. For 2019 Oxy's share of production from the block stood at 22,000 boe/d.

Hafar South 1 nfw on Block 62 (Habiba) in northern Oman, it reached a final TD of around 1,150m in the Cretaceous Lekhwair Formation and is assumed to be dry.

Hither to unreported in July 2018, Petroleum Oil and Gas Corporation of South Africa (PetroSA) and Sasol abandoned its right to secure an Exploration Right (ER) for Block 3A/4A, hence an ER was not executed. The 25,577 sq km block is located towards the northeast of Saldanha Bay, in water ranging in depths between 50 m and 300 m. To date eight wells have been drilled within the area that makes up Block 3A/4A, of the eight two were P&A with gas shows (A-C 2 and A-L 1). In addition, in 2001, 303 sq km of 3D seismic data was acquired within the block.  Blocks 2A and 2B are located adjacent to the north of the block hosting the Ibhubezi gas field and A-J1 oil discovery respectively. The right to negotiate for an ER was granted in 2015 to PetroSA and Sasol’s subsidiary Sasol Africa (Pty) Ltd. Interests in the right were PetroSA 50% and Sasol Africa (Pty) Ltd 50%.

South Africa PetroSA and Sasol abandons its right to secure exploration rights for Block 3A/4A

On 29 March 2018, the consortium of Chevron with 40% working interest, Repsol with 40%, and Wintershall with 20%, was granted a preliminary award for the S-M-764 block in the offshore Santos Basin through the ANP Round 15. For the S-M-764 block the consortium offered a bonus of USD 39.86 million and 225 work units.  There were no other bids for the block.  

The consortium of Chevron with 40%, Repsol 40%, Wintershall 20%, was granted preliminary awards for the block S-M-764, C-M-821 & 823 through the ANP Round 15.