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Aker BP spudded appraisal well 25/4-14 S at Alvheim in PL 036 C on 28 August 2019 using the Deepsea Stavanger” S/S. The well was drilled to TD at 3,200 m and was plugged on 9 September 2019, with appraisal sidetrack 25/4-14 A being kicked-off the following day. This well reached TD at 3,015 m and on 17 September 2019 a second sidetrack, 25/4-14 B, was kicked-off. The wells are located approximately 1.5 km southwest of the East Kameleon (L) template. On 24 September 2019 Aker BP confirmed that operations have been completed. Results are awaited. Aker BP has been busy exploring south of Alvheim in the last 18 months. In Q1 2018 it made a discovery with its Frosk well 24/9-12 S and it drilled a successful appraisal of Gekko in Q3 2018. In early 2019 the Froskelar well (24/9-14 S) also made a new discovery, as did the subsequent Froskelar Northeast well (24/9-15 S). In July 2019 Rumpetroll (24/9-13) was drilled, making a minor gas discovery. Aker BP ASA operates PL 036 C with a 65% interest. It is partnered by ConocoPhillips Skandinavia AS (20%) and Lundin Norway AS (15%).

025/04-14 S (Alvheim) (Aker BP 65% op, ConocoPhillips 20%, Lundin 15%) in PL 036 C, P&A, results awaited.

On 5 December 2018, the Federal Agency for Subsoil Use held on auction for the Talovskiy block in Saratov Oblast (Volga-Ural Province). Yuggazengineering emerged as the winner with an offer of RUB 0.125 million (USD 0.002 million). The Talovskiy block covers 17 sq km in the Precaspian Basin and encompasses the depleted Talovskoye gas field. Seismic coverage amounts to 150 km. Seventeen wells have been drilled in the block. Gas resources (category D1) of the block are estimated at 21 Bcf. The starting price amounted to RUB 0.1 million (USD 0.002 million).

Government of Russia awards Talovskiy block in Saratov Oblast

Egdon Resources UK Ltd is offering material equity in PL 090 (excluding Waddock Cross oilfield determination) in return for a promoted share cost of a future well. The well will target the Broadmayne prospect which is interpreted to consist of a dip and fault closed tilted fault block. The structure was mapped on 3D seismic which was reprocessed in 2017. The main objective is the Triassic Sherwood sand of which Egdon interpret is oil prone. The reservoir forms the primary reservoir at Wytch Farm. Egdon estimate the Sherwood sand to contain mean prospective resources of 2.8 MMbo. Further potential could exist in the Bridport Sandstone. Estimated dry hole well costs are GBP £2.5m. Interest in PL 090 is held by Egdon Resources UK Ltd (42.5% + operator), Corfe Energy Ltd (20%), United Oil and Gas Plc (18.9583%) and Aurora Energy Resources Ltd (13.5417%). For further details please contact: Martin Durham Email: [email protected]

United Kingdom, PL 090

KG-OSN-2009/2, KG offshore, WD 240m, ops terminated Dec ’17 at TD 4,510m, Essar Wildcat SS released on 24th. A modular dynamic test is believed to have been run in November. ONGC (op), partner Andhra Pradesh Gas Infrastructure Corp.

KGS092NASRI-AD expl India (Krishna-Godavari B.) KGS092NASRI AD op. by ONGC (90.0%, APGIC 10.0%) in KG-OSN-2009/2 block, ops terminated, A modular dynamic test is believed to have been run.

On 29 January 2018, Imetame with 100% working interest was granted official awards by the ANP for the ES-T-354, ES-T-373, ES-T-441, ES-T-477, and ES-T-487 blocks in the onshore Espirito Santo Basin from the ANP Round 14.    

Imetame with 100% working interest was granted official awards by the ANP for the ES-T-354, ES-T-373, ES-T-441, ES-T-477, and ES-T-487 blocks in the onshore Espirito Santo Basin from the ANP Round 14.

According to reports in early-January 2018, PentaNova Energy has finalized the acquisition of participating interest the Sur Rio Deseado Este concession from Roch that was originally reported in May 2017. There are no details available regarding the cash value of the transaction, although the potential of heavy oil development in the block has been mentioned. Sur Rio Deseado Este concession covers approximately 305.48 sq km of onshore land in San Jorge Basin. The concession consists of a 50 sq km production area in the westernmost part where the Estacion Tehuelches, La Frieda, and La Frieda Oeste oil and gas fields are located, and the remaining 255 sq km exploration area where Punta Bauza discovery from 1993 is situated. Specifically, PentaNova acquired 54.14% and operatorship in the production block, and 7.92% in the exploration block where Roch is assumed to remain as the operator. The original agreement was reportedly signed by PentaNova’s subsidiary Patagonia Oil. Furthermore, all of the acquired stakes are assigned to the company’s other subsidiary, Alianza Petrolera Argentina, which was originally purchased from Hong Kong-based Petro AP in August 2017. Other partners in the block are Pluspetrol Black River (16.94%), San Enrique Petrolera (24.92%), and Secra (4%). In addition, PentaNova (via Patagonia Oil) was said to be in discussion to also purchase Secra’s 4% participating interest in the block back in May 2017. However, there is still no new information regarding the status of said plan.

Argentina (San Jorge B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Sur Rio Deseado Este op. by ROCH (54.14%, MERCURIA 24.92%, PLUSPET RS 16.94%, SECRA 4.0%) to be check.

Tri-Star Gilbert Pty Ltd, a wholly owned subsidiary of Tri-Star Petroleum Co, acquired 100% interest and operatorship of six production licence applications, located across the Bowen-Surat and Kumbarilla Ridge basins, on 12 November 2019. Tri-Star acquired the interest from previous holder Australia Pacific LNG Pty Ltd. Tri-Star has acquired interest in PL(A)s 434, 435, 436, 437, 438 and 439, which cover a combined area of just over 1,000 sq km. All six applications were applied for on 29 September 2010 and are pending award. The application areas contain a number of successful gas wells and are located to the west of a number of production coalbed methane (CBM) assets.

Tri-Star Petroleum, acquired 100% interest of 6 production licence applications, located across the Bowen-Surat and Kumbarilla Ridge basins.

Santos Ltd was announced as the preferred tender for block PLR2016/17-1A, located in the Bowen-Surat Basin, on 6 April 2018.  Santos is operating the permit and will hold interest with its GLNG partners and APLNG interest holders.  The permit will be awarded as an Authority to Prospect (ATP) licence, once native title and other regulatory negotiations have been completed. The area lies adjacent to Santos’ Arcadia coalbed methane (CBM) acreage and Santos reported that any development from the asset would be low cost as it could utilise the existing infrastructure. There are three wells located within the block area – Arcadia 1, 3 and 7, two of which encountered gas shows. The PLR2016/17-1A block, also referred to as PLR-2016/17-1-1, was offered in the 2016/17 Queensland State Acreage Release between 11 November 2016 and 20 April 2017.  The block is in the Comet Ridge, Bowen-Surat Basin, around 40 km south of Injune. The area is prospective for coalbed methane (CBM). PLR2016/17-1A was open for competitive tender and required a cash-bidding component. PLR2016/17-1A, which covers an area of 87 sq km, was preliminarily awarded on 6 April 2018.  Participants in the licence are Santos Ltd (22.85% + Operator), APLNG Ltd, a joint venture of Origin Energy, ConocoPhillips and Sinopec, (23.85%), Petronas (20.94%), Total SA (20.94%) and KOGAS (11.42%).

Santos Ltd was announced as the preferred tender for block PLR2016/17-1A, located in the Bowen-Surat Basin,Santos is operating the permit and will hold interest with its GLNG partners and APLNG interest holders. The permit will be awarded as an Authority to Prospect (ATP) licence, once native title and other regulatory negotiations have been completed.

In mid-May 2018, Sonatrach International E & P Corp (Sipex) plugged and abandoned the 96/2 A 1 well in the Area 096 (Block 2) with unreported results. The well had been spudded in April 2014 using the TP 215 land rig and with the Devonian and Ashgillian Memouniat Formation as main objectives. In May 2014 the well was suspended at 2,464 m, before reaching the PTD at 2,530 m. In late December 2017, Sonatrach was performing fishing operations following a re-entry of the well at a depth of 2,464 m. Sonatrach International E & P Corp (Sipex) operates the Area 095-096 (Block2) block with the 50 % of interest and in partnership with the Indian Oil Corporation Ltd (ONGC, 25 %) and Oil India Ltd (OIL) with the remaining 25 %).

A-001-096/2 (Sipex op.50%, ONGC 25 %, Oil India 25 %) in the Area 096 (Block 2), the target was Devonian and Ashgillian Memouniat Fm, P&A with unreported results

One of 6 committed wells in Emir Oil block, onshore Mangyshlak-Central Caspian Basin, TD 4,141m, well positive, test production licence required to determine the commerciality of the well. Two shallower intv’s will also be perforated later. Emir Oil = Reach Energy - MIE Holding 60:40

North Kariman-3 expl One of 6 committed wells in Emir Oil block, onshore Mangyshlak-Central Caspian Basin, TD 4,141m, well positive, test production licence required to determine the commerciality of the well. Two shallower intv’s will also be perforated later. Emir Oil = Reach Energy - MIE Holding 60:40

Congo's phase 2 licensing round has resulted in 3 Coastal Basin blocks being awarded, namely to Eni + Lukoil (Marine XXXI + XXIV) and to Kosmos (Marine XXII), outlined below. Perenco failed to secure the Youbi block it had applied for. It is recalled 18 blocks were on offer in the Coastal + Cuvette (onshore) basins. The latter failed to attract a single bid.

Congo, Youbi

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%).

Equinor spudded exploration well 35/10-6 on its Gabriel oil prospect in PL 827 S on 29 April 2020 using the “West Hercules” S/S. Both Equinor and the NPD had initially reported that the Gabriel well was 35/10-5, but the NPD has now re-classified that as a shallow gas well and no longer includes it in its list of exploration wells. PL 827 S, which covers a 52 sq km area over the northeastern part of block 35/10, lies immediately north of the company’s recent (late 2018) minor Gnomoria discovery and applies above Top Cretaceous. 35/10-6 was drilled to TD at 1,938 m in the Upper Paleocene Lista Formation. The Paleocene Balder Formation did not contain any sandstone but in the Paleocene Sele Formation there was 40 m of good quality sandstone. However, no hydrocarbons were present and the well was abandoned as a dry hole on 12 May 2020. Gabriel had potential, pre-drill, recoverable volumes of 5-34 MMboe according to partner DNO. The APA 2015 licence was originally awarded to a group consisting of Tullow, Statoil (Equinor) and Shell. Tullow (the original operator) withdrew in March 2017 and then in November 2018 Shell transferred its interest to DNO. In February 2020 DNO increased its equity by acquiring a further 19% from Equinor. Equinor’s Gnomoria well 35/10-4 A confirmed a section of poor reservoir quality sandstone in the Jurassic Heather Formation totalling 122 m. Oil was proven but no OWC was encountered. Estimated recoverable resources are 1.25 – 7.5 MMbo. PL 827 S is operated by Equinor Energy AS (51%). Equinor is partnered by DNO Norge AS (49%).

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

Mitsubishi is selling its 25% stake in the Kangean PSC to Kinross Intl (Bakrie Grp). Kangean covers 4,082 sq km in the East Java Sea, and will be held by Energi Mega Persada (op), partners Japex + Kinross. Background from GEPS.

Mitsubishi is selling its 25% stake in the Kangean PSC (4082km²) to Kinross Intl (Bakrie Grp). (Energi Mega Persada op, Japex ).

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

In early 2020, Octant Energy confirmed it is looking for a farm-in partner for the Block L17/L18. The company is offering interest in the licence in return for a commitment to fund an exploration well prior the end of the current term which is valid until 23 April 2021. Several leads and prospects were identified by a 1,000 sq km 3D seismic survey. Access to the data room can be made available after execution of a confidentiality agreement. Interest in the licence is solely held by Octant Energy Corp. Contacts: Rick Schmitt – [email protected] Richard Higgins – [email protected]

Octant Energy confirmed it is looking for a farm-in partner for the Block L17/L18. The company is offering interest in the licence in return for a commitment to fund an exploration well prior the end of the current term which is valid until 23 April 2021.

PDL 9, Papuan Fold Belt /Highlands, TD 3,820m, target Toro sst logged + cored, hc determined (assumed gas), EWT planned in the Toro, High Arctic rig 104. Oil Search (op), partners ExxonMobil, AMpolex Kumul Petr., Nippon + Gas Res. Juha 1. .

Papua New Guinea (Papuan Fold Belt (Papuan B.)) Juha 1

Gazprom secured 30-year rights to the Tsentralno-Pogranichnyy block (licence ShOM16554NR), 6,320 sq km off N. Sakhalin.  It was awarded auctionless on 1 July.

Gazprom secured rights to the Tsentralno-Pogranichnyy block (licence ShOM16554NR), 6320km².

Wellesley has acquired a 30% interest in PL 829 and a 20% interest in PL 878 from Equinor. The deal was confirmed by the NPD on 5 December 2019 and is effective from 29 November 2019. PL 829 covers parts of blocks 6204/7, 6204/8, 6204/10 and 6204/11 and the decision to proceed with drilling a well was made in November 2019. PL 878 covers parts of blocks 30/2 and 30/3 and a well (30/2-5) will be drilled on the Atlantis prospect to the north of Huldra (the shallow gas pilot hole is expected in Q1 2020). Operatorship of PL 829 will be transferred, in due course, to Wellesley (pending government approval). Wellesley obtained its first 30% interest in PL 829 in 2016 by way of a deal with Point Resources. The licence contains two small gas discoveries made by 6204/11-1 (Statoil 1994) and 6204/10-2 R (Statoil 1997). Shell was a former partner in PL 878 and exited the licence in February 2019, leaving Equinor with 100% interest. The abandoned Huldra field lies in what is now PL 878. Huldra was discovered in 1982 by well 30/2-1 and it came onstream in November 2001. It is a rotated fault block structure with a Middle Jurassic Brent Group reservoir lying between 3,500-3,900 m. The reservoir was initially HPHT but compression was required to aid production from 2007. From the Huldra platform wet gas was transported to Heimdal for further processing and export and condensate was exported through Veslefrikk. Production ceased in 2014. Interest in PL 829 is now (prior to operatorship changing) held by Equinor Energy AS (20% + operator), Wellesley Petroleum AS (60%) and Petoro AS (20%) and interest in PL 878 is divided between Equinor Energy AS (80% + operator) and Wellesley Petroleum AS (20%).

Wellesley has acquired a 30% interest in PL 829 and a 20% interest in PL 878 from Equinor.

The ANP signed the final contract with Guindastes for the SEAL-T-132 block granted under Round 14.  The block covers 31.6 sq km onshore Sergipe-Alagoas Basin. Two contracts remain unsigned from this round, latest details as follows:

The ANP signed the final contract with Guindastes for the SEAL-T-132 block granted under Round 14. The block covers 31.6 sq km onshore Sergipe-Alagoas Basin

The NPD confirmed on 6 February 2019 that OKEA has acquired Shell’s 50% equity and operatorship in PL 958. The deal, which completed on 31 January 2019, follows OKEA’s purchase of Shell’s interests in Draugen (44.56% + operatorship) and Gjoa (12%) in 2018 (see separate article). PL 958 covers block 6408/4 and part of block 6408/7 and contains the Rialto prospect which OKEA believes could hold 300 MMboe (base case, unrisked). A decision must be taken on the licence by June as to whether to acquire 3D seismic. Rialto has an Upper Jurassic Rogn Formation target, with hydrocarbons believed to have been spilled from Draugen. A well would have a 12% chance of success, with charge being the main risk. Despite the transaction Shell retains a significant presence in Norway operating Ormen Lange and Knarr and partnering in Troll, Valemon and Kvitebjorn. It drilled two exploration wells on the NCS in 2018 (Tyttebaer and Coeus) and was offered shares in four licences (two as operator) as part of APA 2018 (see separate article). Following completion of the deal PL 958 is operated by OKEA AS (50%) with Neptune Energy Norge AS (30%) and Petoro AS (20%) as partners.

OKEA has acquired Shell’s 50% equity and operatorship in PL 958.

Aladdin secured sole rights to the E28-C onshore block, 544 sq km in the Pontides (NW Turkey), on 5 Feb '20 for 5 years. Likewise block F28-B1,B2, 290 sq km.

AMEL (Aladdin Middle East Ltd) has been awarded the F28-B1,B2, E28-C onshore exploration licence.

State GOC (Gabon Oil Co.) and Tullow are understood to be exercising their 10% back-in right to the Dussafu Marine block, the Tortue field of which is currently under phas 2 devt and producing 12,000 b/d. The move is subject to govt approval and payment of USD 28.5 MM by GOC equating to its share of back-costs. Partnership would then become BWE (op) 73.5%, partners Panoro 7.5%, GOC 10% + Tullow 10%.

GOC will acquire a 10% and Tullow 9% interest in the in the Dussafu off. licence after exercising back-in rights with BW Offshore (->73,67% op, Panoro Energy 8,33%).

Star Energy has plugged and abandoned wildcat Stella 1X in the onshore area of the Sebatik PSC, located in the Tarakan Basin, North East Kalimantan, as dry. The well was drilled to its final TD of 953 m MD in mid-August 2019. Stella 1X was targeting Lower Miocene sandstones of the Naintupo Formation or equivalent. The well was spudded in late July 2019 and was drilled using PT Bolindo Nusantara’s "BN-03" type 750 HP land rig. Planned total depth for the well was approximately 3,000 feet subsea (914 m TVD SS). Drilling operations were expected to be completed in approximately 15 days. The Stella prospect is located in the western portion of Nunukan Island. Estimated gas in place was around 93 Bcf with potential production capacity of approximately 5 MMcfg/d from the well, in case of success. SKK Migas visited the well site in mid-July 2019, shortly before the expected spud date. Reportedly, well site preparation was completed in late March 2019, but the well was delayed while waiting for the rig and necessary equipment to arrive at the site. Stella 1X fulfilled the firm commitment for the block. The operator has likely received a one-year exploration period extension until 6 October 2019, after the previous exploration period expired in October 2018. The drilling programme has been delayed several times from the previous planned date of late 2016/early 2017. The last exploration activity in the block prior to Stella 1X was the completion of a 510 km 2D seismic survey in the offshore portion in late March 2012. The seismic acquisition commenced in late February 2012 and was conducted by BGP Indonesia. Previous drilling in the Nunukan island took place in 1939-40, with Nunukan 1 and Nunukan 2 drilled by BPM, encountering oil and gas shows. Star Energy holds 100% operating interest in the Sebatik PSC, which was officially awarded on 7 October 2005. Firm commitments include USD 950,000 in G&G studies, acquiring 500 km of 2D seismic data and drilling one exploration well. In February 2019, the Sebatik contract type was converted from cost recovery PSC to gross split. Background Information The Sebatik PSC covers an area of about 1,395 sq km following an area relinquishment in 2009. It lies both onshore, covering portions of the Sebatik and Nunukan islands, and offshore. On the southeast coast of Sebatik island, Star Energy reported oil and gas seeps coincident with the plunging axial trace of the Sebatik anticline. This could suggest fault-controlled migration from source kitchen in the offshore. Main trapping mechanisms expected are rollover anticlines associated with major growth faults, while stratigraphic pinch-outs on the flanks of the rollover anticlines. The main reservoir targets are Middle Miocene to Pliocene deltaic sandstones of the Tabul and Santul formations or their equivalents while Miocene and Plio-Pleistocene carbonates offer secondary objectives. Migration/distance to kitchens could be one of the risks in the area. The area covered by the Sebatik PSC has been leased under several PSCs since 1967. 2D seismic was acquired under all PSCs and five wells were drilled within the block limits. Four of these were drilled by BPM under pre-WWII concessions, including oil shows encountered in Nunukan 1, and oil and gas shows in Nunukan 2. Between 1967 and 1981, Japex, Amoseas and Total held the inshore area of the Tarakan Basin under the Bunyu PSC. Amoseas assumed operatorship in 1975, and in 1977 drilled Mayne 1 (oil and gas shows). Sceptre/Hadson held the Bunyu PSC between 1985-1993 but did not drill within the new Sebatik PSC. Bounded to the north by Sabah (East Malaysia), to the east by PT Petroner's Bengara I PSC, to the south by PT Pertamina/Medco's Simenggaris JOA and PT Medco's Nunukan PSC and to the east by open Indonesian acreage but also block ND 6 of Malaysia, the Sebatik PSC covers onshore areas and water depths to over 200m. There appear to be some slight onshore and offshore overlaps between the Sebatik coordinates provided by Migas and the Malaysian boundary claim. Prior to the 2012 survey, no activities have been conducted since 2006 wherein a 523km 2D seismic survey was shot. The 523km 2D seismic survey was conducted from September to late November/early December 2006. Two wells, Nunukan 1 and Sebatik 1, were planned to be drilled in the block since 2007. Both wells are targeting Middle Miocene deltaic sandstones and have a PTD of 3,500 to 3,800 m.

Indonesia (Tarakan Sub-basin (Greater Tarakan B.)) Bunyu

Iraq’s 11-block E&P round was held yesterday, units located on Iraq’s borders with Kuwait and Iran: Crescent secured the Gilabat, Khidhr Almaa + Khashm Al Amar blocks with bids of 9.21%, 13.75% + 19.99% net revenue (profit oil) share resp. Geo-Jade Petroleum Corp got the Naft Khaneh + Huwaiza blocks (14.67% 7.15%), United Energy Grp the Sindbad block (4.55%). The Zurbatiya, Shihabi, Jabal Sanam, Fao + Arabian Gulf (offshore) blocks failed to attract offers and remain unallocated.

Iraq, not found

Bonasse licence in SW Peninsula (Cedros) acreage, TD 1,412m, preparing to test as of Feb '20. HC's were encountered in the target U, M & L Cruse horizons.

Saffron-1 nfw Bonasse licence in SW Peninsula (Cedros) acreage, TD 1,412m, preparing to test as of Feb '20. HC's were encountered in the target U, M & L Cruse horizons.

On 2 March 2020 Spirit Energy announced the proposed divestment of three licences containing the Hejre and Solsort fields to INEOS. The deal is subject to governmental approval and on 4 August 2020 INEOS confirmed that the deal is expected to close within the year. The HPHT Hejre discovery is in the 5/98 licence (blocks: 5603/24a, 5603/28b, 5604/21b and 5604/25b), which INEOS will hold 100% interest in after it acquires the 15% and 25% interest from Spirit Energy Danmark ApS and Spirit Energy Petroleum Danmark AS. The Solsort discovery is in the 4/98 and 3/09 licences (blocks: 5604/25d, 5604/26a, 5604/29a, 5604/30d, 5604/26a Solsort and 5604/30a Solsort), which INEOS will acquire 30% interest in from Spirit Energy Danmark ApS. The southeast section of the Solsort discovery extends into the neighbouring 7/89 South Arne licence which is operated by Hess. INEOS is evaluating the possible development scenarios for Solsort field with the concept select decisions expected in 2021. INEOS announced the Hejre development concept in June 2020. The Hejre HPHT (1,011 bar and 160 degrees Celsius) oil and gas discovery was made in 2001 by the Hejre-1 well and appraised in 2004 by Hejre-2. The reservoir is in the Upper Jurassic Heno Formation at approximately 5,200 m. The previous operator (DONG) commenced development work on the field using contractors Technip France SAS, partnered by Daewoo Shipbuilding and Marine Engineering Co. Ltd (DSME) for the engineering, procurement, fabrication, hook-up and commissioning assistance of the Hejre wellhead and processing platform. A 8000-tonne jacket was installed in 2014 and five development wells were drilled between and March 2016. The field development ceased in 2016 when DONG terminated the contract for the platform after a dispute with the contractor over delays in the topside and platform. In September 2017 INEOS acquired DONG Energy and took over its 60% interest in the licence and in December 2017 Spirit Energy was formed from the merger of Centrica and Bayern Norge AS to take 40% interest in the licence. The Solsort oil and gas field was discovered by Solsort 1 (6504/26-5) in 2010, the TD was at 3,041 m TVDSS and three sidetracks were drilled with a reach of up to 1.5 km. In 2013 the discovery was successfully appraised by Solsort 2 (5604/26-6) which tested oil and associated gas from the Paleocene Rogaland Group sandstone. Two sidetracks were drilled from Solsort 2 but both were dry.

(Central Graben Province) Spirit Energy announced the divestment to INEOS of three licences (4/98, 3/09 and 5/98 licences) containing the Hejre and Solsort fields. The deal is subject to governmental approval and INEOS confirmed that the deal is expected to close within the year. After completion, INEOS will hold 100% interest in all licences.

On 25 December 2019, IEOC (Eni) and EGPC signed with the Egyptian Ministry of Petroleum two agreements for E&P operations in the Western Desert. The first agreement covers operations in the South East Siwa (Dev) block, Northern Egypt Basin, with minimum investment expenditures of USD 17 million, and a signature bonus of USD 1.2 million for the drilling of 4 wells. The block, which covers an area of 3,015 sq km was granted to IEOC in February 2019 as a part of the Egyptian General Petroleum Corporation (EGPC) 2018 bid round closed on 1 October 2018. Five unsuccessful wells were drilled within the acreage between 1957 and 2013. The second agreement covers operations in the West Razzak (Dev) block, Northern Egypt Basin, with minimum investment expenditures of USD 34 million, and a signature bonus of USD 5 million for the drilling of 13 wells. The West Razzak (Dev) block was initially granted to Agiba, a JV between EGPC, IEOC and Denison Mines in 1989. It covers an area of 80 sq km and includes four producing fields: Aghar, Aghar West, Aghar Southwest and Aghar East.

IEOC (Eni) and EGPC signed with the Egyptian Ministry of Petroleum two agreements South East Siwa (Dev) and West Razzak (Dev) blocks,in the Western Desert.

On 26 June 2019, the Government of Malawi communicated that Block 1 and Block 6 are available for bidders. Interested parties should send their letters of Expression of Interest (EOI) for the two blocks to: The Secretary for Ministry of Natural Resources, Energy and Mining, P. O. Box 350, Lilongwe 3. Email: [email protected] Attention: Mr Cassius Chiwambo Email: [email protected] Background information In 2010, the Government of Malawi proposed six blocks during a licensing round: three on Lake Malawi (Blocks 2, 3, and 4) and three outside the lake (Blocks 1, 5, and 6). The blocks were offered under Malawi’s 1983 Petroleum Exploration and Production Act. Pacific Oil and Gas Ltd relinquished the Block 6 at the end of the summer 2018. The company was awarded the 8,390 sq km licence in October 2013. The block is located the Lower Zambezi and Nkondezi grabens within the Mozambique Basin. Efora Energy Ltd, formerly SacOil Holdings Ltd (SacOil) relinquished its Block 1 in the Nyasa Graben. SacOil was awarded the 12,265 sq km licence in December 2012 and was the sole participant. Countrywide gravity and magnetic data: Exploration activity in Malawi has primarily been restricted to gravity and magnetic surveys during the late 1960s and early 1970s. A low resolution geophysical survey was done between 1984 and 1985. The survey was carried out by Hunting Geology and Geophysics Limited with funding from the United Nations Development Programme (UNDP). The survey was flown at 1 km line spacing, 10 km tie lines and 120 m ground clearance. In early 2013, the Malawi Government contracted Canada’s Sanders Geophysics to execute countrywide airborne geophysical survey, and the contractor worked with the British and Malawian Geological Survey Departments as quality control supervisors. The survey was carried out between September 2013 and August 2014. The survey was flown at 250 m line spacing, 5000 m tie lines and 60 m +/- 20 m ground clearance for Magnet and Radiometric while gravity, which covered selected blocks, was flown at 1000 m line spacing, 5000 m tie line and 60 m +/- 20 m ground clearance. SacOil believed that the analysis of historical exploration results indicated the presence of various sub-basins within Block 1. To date no petroleum resource have been assessed or quantified over Malawi.

On 26 June 2019, the Government of Malawi communicated that Block 1 and Block 6 are available for bidders.

Shale gas appraisal in Hubei Uplift / province, Upper Yangtze Platform, TD 5,200m (Pre-Cambrian Doushantuo fm), 1,410m horiz leg, 1,686m of shale gas layers logged, ops completed 3 Apr ‘18.

Shale gas appraisal in Hubei Uplift / province, Upper Yangtze Platform, TD 5,200m (Pre-Cambrian Doushantuo fm), 1,410m horiz leg, 1,686m of shale gas layers logged, ops completed 3 Apr ‘18.

Ref. DEA 17 Jun '20, QP did indeed approach ExxonMobil for a stake in PEL 86 (block 1811A), PEL 89 (block 1711, 11,000 sq km together) and PEL 95 (block 1710 + 1810, 20,000 sq km) in shelf + deepwaters of the Namibe Basin. The company's approach was however back in 2019, and it was declined by Exxon, contrary to some recent media reports. PEL 86 + 89 continue being run by Exxon in partnership with Namcor, and 1710-1810 by Exxon + Namcor, 5% of Exxon's interest to be assigned to a local company.

QP did indeed approach ExxonMobil for a stake in PEL 86 (block 1811A), PEL 89 (block 1711, 11,000 sq km together) and PEL 95 (block 1710 + 1810, 20,000 sq km) in shelf + deepwaters. PEL 86 + 89 are run by Exxon in partnership with Namcor, and 1710-1810 by Exxon + Namcor, 5% of Exxon's interest to be assigned to a local company. The company's approach was however back in 2019, and it was declined by Exxon, contrary to some recent media reports

Dominion Energy has sold its natural gas transmission business to Berkshire Hathaway for USD 4 bn + debt, and cancels the cost-soaring 1.5 Bcf/d Atlantic Coast pipeline project while marking a move towards cleaner energy (net zero by 2050) for the US while shifting from gas transport and storage – despite holding on to an interest in Cove Point LNG facility. Much of the company's future operating earnings will be from its utility business. The company plans to invest up to USD 55 bn in ways to reduce emissions, including renewable gas, and the retirement of oil and coal-fired power plants. Through this deal, Buffet's Berkshire takes on nearly 13,000km of gas transmission lines and 21 Bcf/d capacity.

United States, Dominion Energy has sold its natural gas transmission business to Berkshire Hathaway for USD 4 bn + debt, and cancels the cost-soaring 1.5 Bcf/d Atlantic Coast pipeline project while marking a move towards cleaner energy (net zero by 2050) for the US while shifting from gas transport and storage – despite holding on to an interest in Cove Point LNG facility. Much of the company's future operating earnings will be from its utility business. The company plans to invest up to USD 55 bn in ways to reduce emissions, including renewable gas, and the retirement of oil and coal-fired power plants. Through this deal, Buffet's Berkshire takes on nearly 13,000km of gas transmission lines and 21 Bcf/d capacity.

In early November 2018, Lukoil Zapadnaya Sibir obtained a new exploratory license in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). The company has five years to explore the Terpeyevskiy block located in the Ural-Frolov Province. The area covers 222 sq km and encompasses the Terpeyevskaya-2 prospect with oil resources estimated at 14 MMbbl. Three wells have been drilled in the block.

Lukoil secured sole rights to the Terpeyevskiy block (222km²) in the Khanty-Mansiysk AO.

In late November 2017, YPF was reported to sign an agreement with Argentine company, Oilstone Energia, to cede its 100% interest on the 250 sq km Cerro Bandera license, Neuquen Basin. Oilstone has already been operating the block through a service contract since 2011. The contract was renegotiated in 2015 and will expire in November 2027. The company will be the new official operator but has agreed to grant rights to YPF for new exploration and the possible development of unconventional targets like Vaca Muerta and Los Molles formations, as well as a gas project in the northern area of the block. Oilstone has been extracting oil and gas from wells with conventional targets in the Lajas Sandstone in this block.

Argentina, Cerro Bandera

Terra Tasmania bagged explo permit EL3/2017,  2,894 sq km in Tasmania, on 6 Dec ’17 for 5 years. This tags on to Terra’s existing EL 30/2011, both wholly-owned and sole Tasman onshore rights.

Terra Tasmania awarded explo onshore permit EL3/2017 (2894km²).

A consortium of Premier Oil, Mubadala Petroleum and KrisEnergy has been awarded the Andaman II block, located in the offshore area of the North Sumatra Basin, on 31 January 2018. The block was offered as part of the Conventional Oil and Gas Bidding First Round 2017 under the Direct Offer mechanism. Premier Oil will operate the block with 40% interest while Mubadala and KrisEnergy will hold 30% participating interest each. The block will be operated under the new Gross Split fiscal terms. The base government/contractor split under Gross Split terms is 57%/43% for oil and 52%/48% for gas, subject to modifiers depending on the specific situation of the block. Signature bonus for the block was USD 1 million. The minimum exploration commitments for the first three-year exploration period include one G&G study and 1,850 sq km of 3D data including Pre-Stack Depth Migration (PSDM), shipborne gravity & magnetic data, for a total value of USD 7.55 million. The Andaman II block covers an area of approximately 7,400 sq km with water depth ranging from 250 m to 1250 m. Data available for this area consist of 9,310 km of 2D seismic data (ranging from year 1983 to 2008) and four wells. The block has been estimated by Migas to have prospective resources of 196 MMbo and 844 Bcfg. The offshore deepwater part of the area is relatively under-explored. One dry well, Bayu Laut Dalam 1, was drilled in this block by Inpex in 1994 under the North Aceh PSC. Several potential plays have been identified in this block, primarily targeting sandstones of the syn-rift stage (Parapat, Bampo formations) and post-rift stage (Peutu or equivalent, Baong and Keutapang formations). The main structural trends in the area are in N-S and NW-SE orientation. Directly south of the Andaman II block lies the Krueng Mane PSC, where the Jambu Aye Utara field is planned to be developed with first gas potentially in 2022. The Jambu Aye Utara 1 discovery successfully tested two sandstone zones within the Middle Miocene Baong Formation.

Indonesia (North Sumatra B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Jambu Aye Utara op. by HYOIL (85.0%, KOGAS 15.0%) to be check.Krueng Mane op. by HYOIL (85.0%, KOGAS 15.0%) to be check.

OMV Petrom continues to expand its operations in the Black Sea region Exploration block covers a total area of 5,282 square km OMV Petrom has been selected as the winner of the open international tender held by the Ministry of Economy and Sustainable Development of Georgia for the Offshore Block II. Peter Zeilinger, member of the Executive Board, responsible for Upstream, said: 'We continue our plans to expand our upstream activities in the Black Sea region. This is another milestone, after signing a contract to enter the Han Asparuh exploration license in offshore Bulgaria. It is a natural continuation of our more than 40 years of experience in the Romanian Black Sea waters.' The block will be formally awarded only if negotiation of a Production Sharing Contract is successfully finalized. If so, OMV Petrom will obtain the rights to conduct oil and gas exploration activities in Block II, located on the shelf and within the economic zone of the Georgian offshore Black Sea. OMV Petrom in the Black Sea Exploration in the Romanian continental shelf of the Black Sea started in 1969. The first hydrocarbon discovery was in 1980, and the first production in the Black Sea started in 1987. Currently, OMV Petrom has exploration, development and production operations in the shallow waters (Istria block) and exploration activities in partnership with ExxonMobil in deep-water areas (Neptun Deep). Oil and gas production in shallow waters (Istria block) amounts to approx. 25,000 boe/day. In 2019, it accounted for around 17% of the Group’s domestic production. Original article link Source: OMV Petrom

(Black Sea) OMV has been declared the winner of a tender for offshore block II, 5,282 sq km on the shelf.

Ras Al Khaimah Petroleum Authority (RAKPA) assisted by national oil company RAK Gas LLC is re-offering the 769 sq km onshore Block 6 with extensive mountain front acreage contiguous to Oman and 430 sq km inland onshore Block 7 for participation. Existing vintage 2D seismic and Full Tensor Gravity (FTG) data is in the process of being supplemented by two new 2D & 3D surveys which are scheduled for completion during 1Q 2020. Interested parties should contact [email protected] for additional details. Blocks 6 and 7 were originally included in the Ras Al Khaimah License Round 2018 (also termed the RAK-2018 Bid Round) which launched on 1 March 2018 and closed in mid-November 2018. PGNiG was subsequently awarded one block (Block 5) as part of the formal bid round, while Eni reached an agreement to acquire consolidated offshore acreage (Blocks 1-4) following the closure of the round. Bid round data rooms had been opened in Ras Al Khaimah and Henley-on-Thames (ERCL UK offices) on 1 January 2018. Ras Al Khaimah is one of the seven emirates that comprise the United Arab Emirates (UAE).

Ras Al Khaimah Petroleum Authority (RAKPA) assisted by national oil company RAK Gas LLC is re-offering the 769 sq km onshore Block 6 with extensive mountain front acreage contiguous to Oman and 430 sq km inland onshore Block 7 for participation.

On 18 October 2019, Egyptian Natural Gas Holding Co. (EGAS) confirmed the organization of a licensing round including 11 blocks in Western Mediterranean Sea in Q1 2020. New acquired seismic and processed legacy seismic will be available. It is understood that 4 blocks might also be offered in the Eastern Mediterranean Sea. In Western Mediterranean Sea the area includes several structural domains namely the Northern Egypt Basin and its Matruh Sub-basin, the Herodotus Basin and the Mediterranean Ridge. The area is under-explored with only two offshore exploration wells: Kiwi 1 was P&A, dry by Equinor (Statoil) in 2010 in 2,706 m of water. The objective was the Upper Miocene sandstones (4,500 m). The well failed to find these Upper Miocene sandstones but good reservoir properties were found in the Oligocene (Rupelian) series. Sidi Barani 1 was P&A as a dry hole by Phillips in 1976 at a WD of 50 m. The well reached a TD of 4,394 m. Objective were in the Cretaceous and Jurassic series. Seismic data acquired and reprocessed by PGS indicate that the West Mediterranean area has the potential to be the western extension of the Nile Delta gas trend in the Herodotus basin. PGS revealed that sediment thickness is significant in several areas and about 240 potential leads have been identified. In deeper water, the region has been divided into two parts: the Mediterranean Ridge and the Herodotus Basin. Multiple potential plays have been identified, including Pliocene deep marine clastics plus Oligocene and Miocene pre-salt clastics, both of which have been proven in the Nile Delta. A Cretaceous carbonate play has been mapped along the northern boundary of the Northern Egypt Basin with structures longer than 150 sq km. The shelf area contains also a possible extension of the proven onshore Western Desert plays which are centred on Cretaceous and Jurassic clastics and carbonates. Cretaceous traps are expected in the Herodotus basin.

Egypt, Nile Delta (Dev)

Inpex Browse E&P Pty Ltd was awarded exploration permit WA-532-P, located in the Leveque Shelf, Browse Basin, on 2 November 2017.  The permit has been awarded for a period of six years and will expire, or be eligible for renewal, on 1 November 2023. Work commitments have been assigned for the duration of the permit’s validity and include acquisition of 7,185 km new 2D seismic data, 600 sq km new 3D seismic data as well as processing of both datasets and reprocessing of existing datasets in years 1 – 3, and the drilling of an exploration well, at an estimated cost of AUD 30 million in year 5.  Geotechnical studies are also planned throughout the work programme.  The total cost of the work programme is estimated at around AUD 58 million.  The first three year term work programme, to be completed by November 2020, is committed, with the following terms to be committed to on a year by year basis. The permit was applied for after being offered as block W16-4 in the 2016 Offshore Federal Acreage Release.  The block, at 26,313 sq km, is the largest offshore block to be offered in an Australian bid round. The block lies to the south of the Ichthys gas and condensate field, which is being developed by Inpex for LNG exports via an 800+ km pipeline to a Darwin processing plant and expected to come onstream in Q1 2018. Inpex reported on the proximity of its Ichthys field to the new block, with the possibility of getting additional future value from the project via new discoveries. A number of historical wells are located within the permit area, Carbine 1, Eupheme 1, Leveque 1 and Psepotus 1.  All were exploration wells but failed to make any discoveries with the former two being dry and the latter two exhibiting only gas shows. WA-532-P, which covers an area of 26,313 sq km, was awarded on 2 November 2017.  Inpex Browse E&P Pty Ltd holds 100% interest and operatorship of the permit.  

Inpex has been awarded WA-532-P (ex-Hunt WA-413-P) block (26 312km²).

According to local media reports on 5 July 2020, quoting SKK Migas's Deputy for Operations, Shell is selling its 35% participating interest (PI) in the Masela PSC, located in Timor Sea. Reportedly the block operator, Inpex, is currently in discussion with Shell for a potential takeover of the latter's PI in the PSC. The operator may opt to look for a new partner in the near future to take up a portion of PI and share the development cost of the Abadi field in the PSC. With the exit of Shell as partner for the PSC plus the low demand of commodities due to coronavirus disease 2019 (COVID-19) pandemic, the onstream date of the Abadi field could potentially be delayed from the current planned date of 2027. In early June 2020, the Regional government of Maluku approved the Governor Decree No. 96/2020, which lead to the implementation stage of after land acquisition. In mid-June 2020, the operator selected contractors for subsea FEED work in the field. The Abadi project was initially envisioned by Inpex as a Floating LNG (FLNG) development due to the remote location of the field, in deep water and away from existing infrastructure. However, in March 2016, the President of Indonesia instructed the operator to change the FLNG scheme to an onshore LNG (OLNG) development, in order to maximize the benefit for local communities. The revised Abadi Plan of Development (POD) consists of four main elements: OLNG plant, with a processing capacity of 9.5 MTPA of LNG. FPSO to support production of up to 150 MMcfg/d and 35,000 bc/d. Subsea drilling manifolds with the related umbilicals, risers and flowlines, at maximum water depth of approximately 800 m. Gas export pipeline with a length of 160 km, to deliver gas from the FPSO to the OLNG facility.

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

Murphy has agreed to acquire deepwater assets accounting for 38,000 boe/d from LLOG Exploration and LLOG Bluewater. The deal closes 2Q ’19 and will be retro-effective 1 Jan ’19. Assets include 26 blocks with 7 producing fields + 4 devt projects essentially in the Mississippi Canyon.  Murphy thus increases its GoM presence from 95 blocks to 121, production from 52,000 boe/d to 90,000, and 1P reserves from 102 MMbo to 148,000.  Acquired assets are Breton S. 25, Calliope, Khaleesi/Mormont, Kodiak, Marmalard, Marmalard E., Nearly Headless Nick, Neidermeyer, Otis, Ourse,  Powerball + Son of Bluto II.

Murphy has agreed to acquire, for US$1,37 billion, DW assets accounting for 38 000 boe/d from LLOG Exploration and LLOG Bluewater. Assets include 26 blocks with 7 producing fields + 4 devt projects essentially in the Mississippi Canyon. Murphy thus increases its GoM presence from 95 blocks to 121, production from 52 000 boe/d to 90 000, and 1P reserves from 102 MMbo to 148 000.

Mexican President Enrique Pena Nieto on 3 November 2017 said that the Ixachi 1 NFW, in the AE-0032-M-Joachin-02 contract area, discovered initial gross original in place estimates of 1.5 billion boe. The well was reported by Pemex as being the company's largest onshore light oil, gas and condensate discovery in the last 15 years with 3P recoverable reserves that could reach 350 MMboe. Ixachi 1 is located 4km NW of the Mocarroca 1 NFW that discovered oil in 2005. The well should be able to be brought on line quickly, as it is located near existing infrastructure. The Vera Cruz Basin NFW was spudded on 25 January 2017 with a PTD of 7,728m. The well had targets in the Cretaceous. It was spud to explore a possible extension of the Faja de Oro play on Mexico's Gulf Coast. Pena Nieto also said that Ixachi is similar in size to the Talos-operated Zama-1 (Zama-1SON) discovery also made in 2017, located on Block 7 (Contracto CNH-R01-L01-A7/2015). That well tested 28-30 deg API oil & some associated gas and discovered initial gross original oil in place estimates in the range of 1.4 Bbls to 2 Bbls.

Ixachi 1 op. by Pemex (100%) in A-0269-M-Campo Perdiz block, estimated to contain original volumes in place of up to 1,5 billion boe, which could represent recoverable resources of 350 MMboe. Largest Mexican onshore oil find in 15 years.

The ANP has cleared a 50% interest transfer by Petroil to Oil & Gas - Exploração & Produção in the marginal Tigre field lease, 20 sq km in the onshore Sergipe-Alagoas Basin. Partnership now 50:50.

The ANP has cleared a 50% interest transfer by Petroil to Oil & Gas - Exploração & Produção in the marginal Tigre field lease, 20 sq km in the onshore Sergipe-Alagoas Basin. Partnership now 50:50.

The NPD confirmed on 5 July 2018 that Equinor has acquired M Vest’s 20% interest in PL 796 (effective from 29 June 2018). The APA 2014 licence covers an area of 253 sq km over parts of blocks 6407/2, 6407/3, 6407/5 and 6407/6, lying to the north, east, south and southwest of Mikkel. It contains the 2011 Cortina gas discovery made by OMV. Equinor will drill a well on the Lanterna prospect in PL 796 in 2019. OMV’s exploration well 6407/5-2 S targeted the Chamonix and Cortina stacked prospects in what was then PL 471. Although the main stratigraphic Chamonix prospect (Upper Cretaceous Lysing Formation) was found to contain tight sandstones, the well proved a gross gas column of 40m in the secondary Cortina target (Upper Jurassic Rogn Formation) and the Middle Jurassic Garn Formation also contained gas. At the time of drilling it was reported that the partners were assessing potential tie-back options but PL 471 was relinquished in 2013. Interest in PL 796 is now divided between Equinor Energy AS (60% + operator), Edison Norge AS (20%) and Point Resources AS (20%).

Equinor has acquired M Vest’s 20% interest in PL 796 (

N-C part of PN-T-103 block, Parnaíba onshore basin, assumed P&A dry (no shows report) during Oct ’18. PTD was 1,633m, targets Cabeças + Poti fm’s.

Brazil, PN-T-103

OMNIS will launch the Madagascar 2018 round tomorrow 7 Nov ’18 at Africa Oil Week (5-9 Nov ’18 in Cape Town).  The round is held in partnership with BGP + TGS.  44 offshore blocks are being offered in the Morondava Basin off the west of the island between Cap St André and Morombe. Roadshows will be held in Houston on 19 Feb ’19 and London on 26 Feb ’19, data access at TGS premises in both cities. http://www.omnis.mg, http://www.tgs.com, http://www.bgp.com.cn.

OMNIS will launch the Madagascar 2018 round tomorrow 7 Nov ’18 at Africa Oil Week (5-9 Nov ’18 in Cape Town). The round is held in partnership with BGP + TGS. 44 offshore blocks are being offered in the Morondava Basin off the west of the island between Cap St André and Morombe. Roadshows will be held in Houston on 19 Feb ’19 and London on 26 Feb ’19, data access at TGS premises in both cities.

Canadian Encana has agreed to acquire US Newfield Exploration in an all-stock transaction valued at USD 7.7 bn including debt, completion expected 1Q ‘19. Involved are Anadarko, Permian and Montney basin assets, which will enhance Encana’s production by nearly 55% and proven reserves by ab. 85%, thereby setting the company as North America’s 2nd-largest unconventionals producer.

United States, not found

Shell concluded the sale of 45% operator share in Corrib gas field to the Canadian Pension Plan Investment Board (CPPIB) on 30 November 2018. CPPIB's local subsidiary Nephin Energy has acquired Shell E&P Ireland Ltd for US$ 958 million (EUR 840 million) cash consideration, with further contingent payments of US$ 285 million (EUR 250 million) based on commodity prices and field performance during 2018-25, and the transaction will be backdated to 1 January 2017. Partner Vermilion has assumed the role of operator and will shortly acquire 1.5% interest in the field from Nephin for EUR6 million (US$ 6.8 million) after adjustments for back-dated production (EUR 19.4 million gross transaction value), with government approvals already in place by 30 November 2018. Both deals were first announced on 12 July 2017. Corrib is located in 350m WD, 85 km W of the County Mayo coastline in Ireland, and was discovered with the deviated NFW 18/20-1 (1996, Enterprise, 4,372m). The field has estimated reserves of 1 Tcfg and the development plan was first approved in 2002. Regulatory hurdles and environmental issues postponed first gas flow until 30 December 2015, and output has been at or near plant capacity since Q2 2016, averaging 282 MMcfg/d during 2018. Corrib gas is produced from six wells, and transported to the Bellanaboy Bridge Gas Terminal in NW County Mayo for processing, then transferred to the national gas grid for distribution to Irish gas consumers. At peak production, the field has the potential to meet up to 60% of Ireland's gas needs. The Corrib petroleum lease was awarded on 15 November 2001, and revised partners are Vermilion Energy Ireland Ltd (18.5% + Op), the Canadian Pension Plan Investment Board via Nephin Energy Holdings Ltd (45%), and Equinor Energy Ireland Ltd (36.5%).

Shell concluded the sale of 45% operator share in Corrib gas field to the Canadian Pension Plan Investment Board (CPPIB) on 30 November 2018. CPPIB's local subsidiary Nephin Energy has acquired Shell E&P Ireland Ltd for US$ 958 million (EUR 840 million) cash consideration,

Further to DEA 8 Aug ’17, Chevron has reportedly decided to sell its 25% in the multi-block, 11,374-sq km, South Natuna Sea block B PSC (in purple below), to operator Medco. PT Bumi Hasta Mukti (BHM) was earlier reported to be the buyer. The deal would result in Medco being 100% block holder.

Chevron has reportedly decided to sell its 25% in the multi-block (1374km²) South Natuna Sea block B PSC, to operator Medco. PT Bumi Hasta Mukti (BHM) was earlier reported to be the buyer.

In the second quarter of 2018, CNOOC made two new oil discoveries in the offshore Beibuwan Basin. Discovery well Weizhou 10-3E-1 is in the CNOOC operated Yulin 35 Block and Wushi 23-5N-1 is in the CNOOC operated Weizhou 12 Block. CNOOC is the operator and sole rightholder of both discoveries.

In the second quarter of 2018, CNOOC made two new oil discoveries in the offshore Beibuwan Basin. Discovery well Weizhou 10-3E-1 is in the CNOOC operated Yulin 35 Block and Wushi 23-5N-1 is in the CNOOC operated Weizhou 12 Block. CNOOC is the operator and sole rightholder of both discoveries.

Eni spudded exploration well 22/19c-7 in licence P1620 (block 22/19c) targeting the HP/HT Rowallan prospect on 31 December 2018. Rowallan was thought to be a large structural closure and estimated to hold P50 gross prospective resources of 220 MMboe. It was thought to be an analogue to the large Culzean field. The company used the “Ensco 121” for operations. On 4 April 2019 partner Serica announced that the well was drilled to a TD of 4,641 m and encountered a 182 m section of sandstones and shale but no hydrocarbons were encountered. The well was plugged and abandoned and as of 11 May 2019 and the rig had left location. Serica was officially awarded the licence under the 25th Offshore Licensing Round back in 2010. Following a deal in 2012 with JX Nippon, the Japanese company farmed in taking an 85% interest operatorship. Then in May 2014 Eni farmed into the licence taking a 50% interest and operatorship. The licence is located near the Eastern Trough Area Project (ETAP) which involves the joint development of the Marnock, Skua, Egret, Heron, Machar, Mungo, Madoes and Mirren fields. Interest in the licence is held by ENI UK Limited (32% + operator), JX Nippon Exploration and Production (U.K.) Limited (25%), Mitsui E&P UK Ltd (20%), Serica Energy (UK) Limited (15%) and Equinor (UK) Ltd (8%).

Eni SpA P1620 - 22/19c-7 (Rowallan) - exploration well - Plugged and abandoned, dry hole

On 17 October 2019, the Argentine government granted an exploration permit for MLO-124 block to a consortium of Eni, Tecpetrol, and Mitsui & Co through the publication of Resolution 645/2019 in the nation’s official gazette following the preliminary award of the block in May 2019 as a result of the Argentina Round 1 offshore bid round. Work program in the first exploration period of four years consists of 2D seismic acquisition of 867 km, 3D seismic acquisition of 4,418 sq km, and 2D gravimetry and magnetometry acquisition of 6,500 km, followed by a drilling commitment for one well in the second exploration period of another four years. An optional third exploration period of five years is possible, although accompanied by a 50% partial relinquishment. Eni operates the block with 80% interest, followed by partners Tecpetrol and Mitsui with 10% stake each. MLO-124 covers 4,421 sq km of deepwater area (as designated by the Argentine Secretary of Energy) in Malvinas Basin with approximated water depth below 200 m. Exploration target for the blocks in the area is expected to be oil and gas in the Springhill Formation, which has not produced from any fields on the Malvinas Basin side in comparison to the adjacent Austral Basin side where several offshore gas fields are currently producing. The consortium lead by Eni won the rights for MLO-124 after submitting an offer of USD 67.605 million with a bonus of USD 5 million to edge out another offer by a partnership of Equinor and state company YPF of USD 27.185 million in Round 1 of the country’s offshore bid round that ended on 16 April 2019. The concession is marked as Eni’s second offshore asset in Argentina after the Tauro-Sirius block in Austral Basin, where the company holds a 30% non-operating stake. Background Information The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. Granting of exploration permits from the round was originally expected to be published in early-August 2019 with signing of the permits to follow within 15 days.

Argentina, MLO-124

PA_1OGX066MA_PN-T-67 discovery evaluation plan area within BT-PN-007 contract, PN-T-067 block, Parnaíba Basin, drilling completed late ’17 and now assumed P&A dry due to no oil shows report to ANP.  PTD was 1,674m, targets Cabecas + Poti fm’s.

Brazil (Parnaiba B.) 4-PGN-SESAORAIMUNDO-MA op. by PARNAIBA (100.0%) in PN-T-067 Block 1

Megiddo-Jezreel (401) licence in NE Israel, TD 5,060m, a short stimulation was followed by swabbing, some 90-110 bo/d flowed from between 5,003-5,019m, but results appear at this point inconclusive as to whether the well will flow naturally. Daflog F-400 rig.

Megiddo-Jezreel-1 (MJ) nfw Megiddo-Jezreel (401) licence in NE Israel, TD 5,060m, a short stimulation was followed by swabbing, some 90-110 bo/d flowed from between 5,003-5,019m, but results appear at this point inconclusive as to whether the well will flow naturally.

PT Medco Energi has completed Tala 2A and Tala 2C from its three-well exploration drilling campaign in the Rimau PSC, located in onshore South Sumatra, at end-December 2017. The wells were drilled at the Iliran High structure. Fluid sample testing is yet to be carried out on the two wells. The company plans to proceed with the third well, Tala 2B, likely in Q1 2018. The wells could be targeting heavy oil in shallow sandstone reservoirs of the Middle Miocene Telisa Formation. The operator previously spudded Tala 3 on 22 July 2012. The well was drilled to a TD of 115 m, with bottom-hole in the Pre-Tertiary Basement. The well encountered water and was abandoned in early August 2012. It was the sixth shallow well drilled within the Iliran High since September 2011, targeting heavy oil in the area. The previous wells in the campaign were Shallow Heavy Oil (SHO) 2, Tala 1, Tala 2, Taba 2 and Taba 1. Stratigraphic test well SHO 2 was abandoned in April 2012, with results unreported. The well was drilled to a TD of 555 m and may have targeted sandstones of the Upper Oligocene to Lower Miocene Talang Akar Formation, carbonates of the Lower Miocene Batu Raja Formation and sandstones of the Telisa Formation. Tala 1 was spudded on 27 February 2012, located 2.2 km east-southeast of the Tala 2 well and with a PTD of 103 m. The well was suspended with oil shows. Tala 1 was the fourth shallow well drilled within the Iliran High since September 2011. Tala 2 was likely suspended with oil shows in January 2012. The well, located about 3.8 km southeast of the Taba 2 well, was spudded on 4 December 2011 and was drilled to a TD of 94 m. The first two exploration wells that were drilled at the same structure were Taba 1 and Taba 2. Both possibly encountered heavy oil as cyclic steam injection/stimulation were conducted. All the shallow wells drilled on the Taba and Tala structures were likely targeting the Middle Miocene Telisa shallow marine sandstones trapped in a faulted anticline structure, and were drilled using land rig “EMSCO”. Rightholders of the block are Medco (95%, operator) and Perusahaan Daerah Pertambangan Energi (5%).

Indonesia (South Sumatra B.) ? op. by MEDCO RM (95.0%, PDPDE 5.0%) in Rimau block

In January 2020, Perenco Exploration & Production Congo Ltd's (Perenco) Production sharing Contract for the Marine XXVIII (understood to include both XXVIIIA and XXVIIIB) was approved. The 280 sq km area sits atop the shelf within the Lower Congo Basin. It plays host to the 1992 Likoufou Marine 1 oil and gas discovery, the 1992 Likoufou Sud Marine 1 oil and gas discovery, the 1991 Nongo Nord Marine 1 oil and gas discovery and the 1980 Nongo Marine 1 oil discovery. Likoufou Marine 1 is estimated to hold some 30 MMbo and 5,000 MMscf gas. Likoufou Sud Marine 1 is estimated to hold some 1.2 MMbo and 1050 MMscf gas, Nongo Nord Marine 1 is estimated to hold some 6.6 MMbo and 50 MMscf gas and Nongo Marine 1 is estimated to hold less than 1 MMbo. The effective date for the start of the of the PSC was January 2019. Perenco operates the licence with a 75% interest, Societe Nationale des Petroles du Congo holds the remaining 25% stake. Background information Perenco’s bid for the block was opened on 29 March 2017. On 21 November 2018, the Council of Ministers met and agreed to award Marine XXVII to SNPC and Perenco. (it was previously though that the split was 85% Perenco and 15% SNPC however, this was incorrect). The licence was awarded for a period of two years and in non-renewable.

Perenco Exploration & Production Congo Ltd's (Perenco) Production sharing Contract for the Marine XXVIII (understood to include both XXVIIIA and XXVIIIB) was approved.

Hot on the heels of the 54 leases awarded in October, 88 Energy, via its local subsidiary Burgundy Xploration, was formally awarded an additional 76 contiguous North Slope leases on 1 November 2017: ADLs 393273-393274, 393279-393290, 393292-393294, 393303-393310, 393385-393415, 393478-393486, 393488, 393490-393498 and 393500. 88 Energy recently stated that its H2 2017 North Slope lease awards have been driven, in part, by the company's ongoing confidence in the potential of the HRZ shale play, which has laid largely untouched since Alaska's oil boom in the 1970's. In a statement, Managing Director, Dave Wall, said: "The Joint Venture remains committed and confident in the HRZ shale play. The leasing strategy has been designed to strike a balance between this confidence and available capital whilst we build towards completion of the flowback and production testing of the Icewine#2 well in H1 2018." 88 Energy, via its local subsidiary companies Accumulate Energy Alaska and Burgundy Xploration, was awarded 54 contiguous North Slope blocks by the Alaskan Division of Oil and Gas, effective as of 1 September 2017. These 54 leases are located 25km southwest from 88 Energy's recent Icewine discovery (ADL 392301). The company had completed initial drilling activities in NFW Icewine 1 by early June 2017, at a final TD of 3,490m. The closely watched appraisal well, Icewine 2, was spudded on 24 April 2017, utilising the Doyon Drilling's "Arctic Fox" drilling rig. Flow testing in this appraisal well recommenced in late August 2017. Following these 76 awards, Burgundy Xploration is now the operator and sole interest-holder (100% WI + Op) of ADLs 393201, 393303-393306, 393308, 393310, 393400-393403, 393405, 393407, 393409, 393411-393415, 393486, 393488, 393490-393498, 393500. Equity in the remaining 46 ADLs is now shared between Burgundy Xploration (22.45088% WI + Op) and Accumulate Energy Alaska (77.54912%).

Not Found

Block 42, Guyana Deepsea Basin, WD 2,497m, P&A’ing dry at TD 6,194m, Ensco DS-12. Target play similar to ExxonMobil’s nearby Turbot + Longtail discoveries. Kosmos (op), partners Chevron + Hess.

Pontoenoe 1 (Kosmos 33,4% op, Hess 33,3%, Chevron 33,3%) in Block 42, P&A, encountered high quality reservoir, testing did not discover commercial hc and the primary exploration target proved to be water bearing, tested late Cretaceous reservoirs in a stratigraphic trap charged from oil mature Albian and Cenomanian-Turonian source kitchens. It added it believed the prospect failed due to a lack of trap but provided evidence of a working source kitchen. WD=2497m, TD=6194m.

Galp has agreed to farmout a 40% stake to ExxonMobil in deepwater PEL 82 (blocks 2212A + 2112B), 11,444 sq km in the Walvis Basin.  Upon conclusion of the deal, Partnership will be Galp (op), Exxon, Custos + Namcor 40:40:10:10.

ExxonMobil has taken a 40% stake to in DW PEL 82 (blocks 2212A + 2112B, 11444km²) from Galp (->40% op, Custos 10%, Namcor 10%).

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

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

In mid-July 2020, Shell Offshore acquired 100% WI and operatorship in Mississippi Canyon Block MC 476 from LLOG Exploration Offshore. The transaction is effective as of 1 April 2020. The block lies adjacent to MC 475, the site of Shell’s 2016 G35335 1 NFW, targeting the Leesburg prospect, believed to be part of the Norphlet play. The company reportedly encountered only residual oil in the well. Following completion of the transaction, Shell Offshore is now the operator and sole interest-holder (100% WI + Op) in MC 476.

(GOM b.) Shell Offshore acquired 100% WI and operatorship in Mississippi Canyon Block MC 476 from LLOG Exploration Offshore.

Oilex and partners are looking to settle the issue of the 1,871-sq km JPDA 06-103 PSC in the Bonaparte Basin, following its cancellation in 2015. A commercial settlement will be sought. Oilex (op), partners GSPC, Bahrat Petr., Pan Pacific Petr. + Japan Energy. Full story in GEPS.

Timor Sea JPDA, not found

On 8 June 2019, it was announced that Turkiye Petrolleri A.O. (TPAO) has been awarded the M41-B onshore exploration licence in the Zagros Province towards southeast of the country on 28 May 2019. The licence covers around 445 sq km area and it has been granted for a five-year term with an expiry date of 27 May 2024. TPAO is 100% owner and operator of the licence. TPAO had filed the application for M41-B exploration licence on 10 October 2018.

TPAO has been awarded the M41-B onshore exploration licence in the Zagros Province towards southeast of the country

The Ministry of Hydrocarbons, Energy and Mines (Ministère des Hydrocarbures, de l’Energie et des Mines) is the licensing authority. Contracts are signed by the state, as represented by the Minister of Hydrocarbons, Energy and Mines. The Directorate General of Hydrocarbons (Direction Générale des Hydrocarbures) is responsible for the supervision of petroleum operations. Interested parties should contact: Ministère des Hydrocarbures de l’Energie et des Mines Direction Générale des Hydrocarbures Directeur : Moustapha BECHIR Tel : +222 422 101 28 E-mail : [email protected]   It is also possible to contact the Socété Mauritanienne des Hydrocarbures et du Patrimoine Minier (SMHPM). Department of Exploration and Promotion Director : Lemrabott Taleb As of July 2020, it is understood that the blocks listed in the table below were available for licensing. Sixty six blocks were available. There was one change in the list compared to the previous one. The C-7 block was relinquished by Total and is understood to be available. Total open acreage amounts to 777,962 sq km of which 681,508 is onshore and 96,454 is offshore.    Open blocks       Block Name Area (sq km) Situation Block Basin C-1 3,056 offshore Senegal (M.S.G.B.C.) Basin C-2 3,874 offshore Senegal (M.S.G.B.C.) Basin C-3 7,352 offshore Senegal (M.S.G.B.C.) Basin C-4 9,037 onshore Senegal (M.S.G.B.C.) Basin C-5 11,153 onshore Senegal (M.S.G.B.C.) Basin C-7 7,294 offshore Senegal (M.S.G.B.C.) Basin C-9 7,589 offshore Senegal (M.S.G.B.C.) Basin C-16 9,014 offshore Senegal (M.S.G.B.C.) Basin C-20 10,175 offshore Senegal (M.S.G.B.C.) Basin C-21 14,819 offshore Senegal (M.S.G.B.C.) Basin C-23 6,349 offshore Senegal (M.S.G.B.C.) Basin C-24 8,479 onshore Senegal (M.S.G.B.C.) Basin C-25 10,946 onshore Senegal (M.S.G.B.C.) Basin C-26 11,043 onshore Senegal (M.S.G.B.C.) Basin C-27 11,760 onshore Senegal (M.S.G.B.C.) Basin C-30 3,147 offshore Senegal (M.S.G.B.C.) Basin C-32 2,475 offshore Senegal (M.S.G.B.C.) Basin C-33 2,546 offshore Senegal (M.S.G.B.C.) Basin C-34 2,472 offshore Senegal (M.S.G.B.C.) Basin C-35 1,824 offshore Senegal (M.S.G.B.C.) Basin C-36 3,316 offshore Senegal (M.S.G.B.C.) Basin Onshore Block 11 15,133 onshore Senegal (M.S.G.B.C.) Basin Ta-01 10,428 onshore Taoudeni Basin Ta-2 13,476 onshore Taoudeni Basin Ta-3 14,354 onshore Taoudeni Basin Ta-4 11,746 onshore Taoudeni Basin Ta-5 11,510 onshore Taoudeni Basin Ta-6 11,725 onshore Taoudeni Basin Ta-7 14,384 onshore Adrar Sub-basin (Taoudeni Basin) Ta-8 14,033 onshore Adrar Sub-basin (Taoudeni Basin) Ta-9 12,141 onshore Taoudeni Basin Ta-10 14,456 onshore Taoudeni Basin Ta-11 13,579 onshore Hodh Sub-basin (Taoudeni Basin) Ta-12 13,286 onshore Hodh Sub-basin (Taoudeni Basin) Ta-13 14,556 onshore Taoudeni Basin Ta-14 11,502 onshore Taoudeni Basin Ta-15 10,418 onshore Taoudeni Basin Ta-16 12,664 onshore Taoudeni Basin Ta-17 13,213 onshore Taoudeni Basin Ta-18 20,105 onshore Taoudeni Basin Ta-19 20,720 onshore Taoudeni Basin Ta-20 21,608 onshore Taoudeni Basin Ta-21 16,507 onshore Hodh Sub-basin (Taoudeni Basin) Ta-22 21,622 onshore Taoudeni Basin Ta-23 17,612 onshore Hodh Sub-basin (Taoudeni Basin) Ta-24 20,667 onshore Hodh Sub-basin (Taoudeni Basin) Ta-25 21,156 onshore Taoudeni Basin Ta-26 15,664 onshore Taoudeni Basin Ta-27 18,144 onshore Taoudeni Basin Ta-28 13,487 onshore Taoudeni Basin Ta-29 12,503 onshore Taoudeni Basin Ta-30 5,583 onshore Adrar Sub-basin (Taoudeni Basin) Ta-31 15,095 onshore Taoudeni Basin Ta-32 10,250 onshore Taoudeni Basin Ta-33 12,197 onshore Taoudeni Basin Ta-34 9,179 onshore Taoudeni Basin Ta-35 14,066 onshore Eglab-Reguibat Massif Ta-36 14,945 onshore Adrar Sub-basin (Taoudeni Basin) Ta-37 19,272 onshore Adrar Sub-basin (Taoudeni Basin) Ta-38 9,341 onshore Adrar Sub-basin (Taoudeni Basin) Ta-39 8,899 onshore Adrar Sub-basin (Taoudeni Basin) Ta-40 10,530 onshore Taoudeni Basin Ta-41 11,511 onshore Eglab-Reguibat Massif Ta-42 11,594 onshore Taoudeni Basin Ta-43 11,958 onshore Taoudeni Basin Ta-44 13,423 onshore Taoudeni Basin

(M.S.G.B.C. b.) Total open acreage amounts to 777,962 sq km of which 681,508 is onshore and 96,454 is offshore.

On 27 July 2020, the Ministry of Natural Resources added four areas to a list of blocks planned for auctions in 2020. The added blocks, located in Volga-Urals, Western and Eastern Siberia, will be auctioned in the third and fourth quarters of 2020. The Privolzhskiy block (Volga-Urals Basin) covers 45 sq km in Saratov Oblast and encompasses the Privolzhskoye oil discovery with 2P reserves estimated at 3 MMbbl. Oil resources of the block are estimated at 1 MMbbl. The Yelleyskiy-3 block (Kaymys-Vasyugan Basin) covers 1,982 sq km in Tomsk Oblast (Western Siberia) and encompasses the Ostrovnaya and Sredneyulzhavskaya prospects with combined oil resources estimated at 27 MMbbl. Hydrocarbon resources of the block are estimated at 147 MMbl of oil and 284 Bcf of gas. The Olguydakhskiy Severnyy block (Tunguska Basin) covers 7,517 sq km in Yakutia (Sakha) Republic (Eastern Siberia). Its hydrocarbon resources are estimated at 363 MMbbl of oil and 3.4 Tcf of gas. The Berezovskiy Yuzhnyy block (Predpatom Basin) covers 847 sq km in Yakutia (Sakha) Republic. Hydrocarbon resources of the block are estimated at 29 MMbbl of oil and 1.2 Tcf of gas.

Russia (Volga-Urals B.) Severnyy op. by ROSNEFT (100%)

KrisEnergy continued offering a farm-in opportunity in the Udan Emas PSC, onshore West Papua, in April 2019. The company is offering up to 49% interest in the block, in return for pro-rata share of back costs and for full carry on a discretionary exploration well to be drilled by 2020. KrisEnergy holds 100% operating interest in the block, which was awarded in July 2012. The PSC exploration period has been extended with the final four-year term until July 2022. The block covers an area of 1,070 sq km following the final partial area relinquishment. The firm exploration commitments for the first three-year exploration period have been fulfilled after the completion of a 300 km 2D seismic survey in June 2015. Aside from the newly acquired seismic data, the operator also completed a 12,210 sq km airborne gravity and magnetic survey in late April 2015. The Udan Emas block straddles the Bintuni Basin and the Lengguru Fold Belt. The block is estimated to hold nearly 4.9 Tcfg in place, with several large structures identified on 2D seismic data and potential play type analogue to BP’s Tangguh project and Genting Oil’s Kasuri PSC. The largest prospect in the block, Prospect B, is estimated to hold a potential of 2 Tcf of gas in place within a structural trap of the Upper and Lower Kembelangan Group (Jurassic Roabiba Formation and Cretaceous Ekmai Formation). The prospect is made up of four stacked closures with depths ranging from 3,500 to 4,500 m TVDSS, each with an area of approximately 65 sq km. Additional resources potential of approximately 4 Tcf of gas has also been identified in potential leads along the fold belt areas where seismic coverage is little or absent. The Bintuni Basin is gas-prone, as proven by the Tangguh LNG complex. Hydrocarbons are likely sourced from Permian-Jurassic carbonaceous shales and coals. The farm-in opportunity was previously offered in August 2015, aiming at finding new partners to fund future exploration in the PSC. For further information, or to arrange for viewing the data room, interested parties may contact: Mike Whibley Vice President, Technical (Corporate) [email protected] Dr. Gadjah E. Pireno Vice President, Exploration (Indonesia) [email protected] Background Information The northeastern part of the Udan Emas block covered the area that used to be covered by the Arguni East PSC. The eastern part of the block used to be covered by the West Lengguru PSC and the Bintuni PSC. The western part of the block used to be covered by Bomberai PSC and Babo PSC. The main exploration target in the Bintuni Basin is the Jurassic Roabiba sandstone play. In the nearby Kasuri PSC, Genting drilled the Asap 1XST1 gas with condensate discovery from 2010 to early 2011. Three DSTs were conducted in Roabiba sandstones and flowed a cumulative rate of about 100MMcfg/d plus condensate. One DST reportedly flowed 23 MMcf/d of gas, a second flowed 41 MMcf/d of gas and a third recorded 36 MMcf/d of gas. Six wells have been drilled within the block to date. All of the wells were drilled in the northwestern part of the block. The wells are Mandala 1, Jarua South 1, Terie 1, Monie 1, Monie South 1 and Wami 1. Sunoco drilled Mandala 1 in 1975, Terie 1 in 1976 and Monie 1 and Monie South 1 in 1980. Wami 1 was drilled by Gulf in 1976. Jarua South 1 was drilled by Marathon in 1980. All wells drilled in this block were P&A as dry holes. The Babo PSC, originally covering an area of 15,875 sq km, was awarded to Mobil Exploration Bomberai Inc (60%) and BHP Petroleum (40%) on 3 August 1990. The contract was awarded on the basis of payment of signature bonuses of USD 2.05 million. The work programme commitment was USD 20 million in the first six years and USD 70 million in 10 years. The contract was awarded "frontier terms" on the basis of its location in eastern Indonesia and the fact that the main plays were at pre-Tertiary level. Effective 1 September 1993, BHP farmed-out its total 40% interest to Arco, with Mobil also farming-out some 20% to Arco. Arco also assumed operatorship as of that date. The 3,495 sq km Arguni East PSC was awarded (together with the 4,865 sq km Arguni West PSC) to Arco (80%) with partner Inpex (20%) on 16 November 1998. The block was awarded on the basis of payment of a large total Signature Bonus of USD 7.2 million. The firm work programme commitment is USD 39.5 million for the first three years and USD 84 million in 10 years. Mobil's first exploration program in the block was to record 1,523 km of land gravity and magnetic data between early 1991 and January 1992. A total of 1,277km of field geological surveying were also conducted between these dates. A total of 10,000 sq km of Synthetic Aperture Radar (SAR) imagery was also flown across the contract area in 1991. These surveys were believed to have revealed at least three prospects in the PSC, including the West Onin Prospect which appeared to be an early candidate for drilling. West Onin 1 was set to be drilled in early 1993 but was postponed as Mobil sought partners. The well was expected to test Jurassic sandstones at a depth of approximately 2,438m, with the PTD set at 3,048 m. The mapped area of closure was believed to have been about 324 sq km. The first seismic campaigns conducted in the Babo PSC were a 390 km 2D survey in November/December 1997. In May 1998 a programme designed to record 325km of 2D data was started. That survey was completed in September 1998 after having recorded 318km of data. The survey is believed to have highlighted two Jurassic gas prospects and one significant lead. Arco was concentrating on the eastern less structured area of the block. Previous operator Mobil had concentrated activity in the highly structured western part of the PSC. The Udan Emas PSC was officially awarded to KrisEnergy on 20 July 2012. Firm commitments for the first three years of exploration include G&G studies (USD 600,000) and 250 km 2D seismic (USD 5 million). The block also had a one-well commitment for the fourth exploration year. Signature bonus paid was USD 1 million. The block was offered during the First Petroleum Bidding Round 2012 under the Direct Offer mechanism. Two bid documents were purchased for this block and there was one company who submitted a participating bid. Preliminary announcement of the winner for the block was made by Migas on 25 May 2012. The Udan Emas block is covered by 2D seismic data shot by previous operators. The total length of the 2D seismic data provided by Migas during the bidding process was 1,480.32 km, plus an additional 827.98 km of 2D seismic data in the optional data volume. The Udan Emas 2D seismic survey covered areas within the Teluk Arguni and Arguni Bawah districts of the Kaimana Regency. PSDM processing of the data was completed in Q4 2015. KrisEnergy reported seismic acquisition cost of over USD 20 million. Initial plan for the seismic survey was in December 2013, but it did not push through. According to local press report, qualification tender process commenced in early September 2013.

KrisEnergy continued offering a farm-in opportunity in the Udan Emas PSC, onshore West Papua, in April 2019. The company is offering up to 49% interest in the block, in return for pro-rata share of back costs and for full carry on a discretionary exploration well to be drilled by 2020. KrisEnergy holds 100% operating interest in the block, which was awarded in July 2012.

On 17 October 2019, the Argentine government granted an exploration permit for MLO-113 block to a consortium of a partnership of ExxonMobil and Qatar Petroleum through the publication of Resolution 648/2019 in the nation’s official gazette following the preliminary award of the block in May 2019 as a result of the Argentina Round 1 offshore bid round. Work program in the first exploration period of four years consists of 2D seismic acquisition of 962.96 km and reprocessing of 2,331.71 km, 3D seismic acquisition of 1,747.10 sq km and reprocessing of 1,455.92 sq km, along with 2D gravimetry and magnetometry acquisition of 5,156.01 km, followed by a drilling commitment for one well in the second exploration period of another four years. An optional third exploration period of five years is possible, although accompanied by a 50% partial relinquishment. ExxonMobil operates the block with 70% interest while partner Qatar Petroleum holds the remaining 30%. MLO-113 covers 5,826 sq km of deepwater area (as designated by the Argentine Secretary of Energy) in Malvinas Basin with approximated water depth below 200 m. Exploration target for the blocks in the area is expected to be oil and gas in the Springhill Formation, which has not produced from any fields on the Malvinas Basin side in comparison to the adjacent Austral Basin side where several offshore gas fields are currently producing. ExxonMobil and Qatar Petroleum won the rights for MLO-113 after submitting a joint offer of USD 30.1 million in Round 1 of the country’s offshore bid round that ended on 16 April 2019. Along with MLO-113, the group also won the rights for MLO-117 and MLO-118 blocks with offers of 34.475 million and 29.95 million, respectively, that are still pending on official awards as of mid-October 2019. The offshore blocks marked the second partnership between ExxonMobil and Qatar Petroleum in Argentina after Qatar Petroleum's purchase of 30% equity in ExxonMobil affiliates in mid-2018. Background Information The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. Granting of exploration permits from the round was originally expected to be published in early-August 2019 with signing of the permits to follow within 15 days.

Argentina, MLO-117

Sampang block off E. Java, S. of Madura Island in WD 48m, TMD 710m, elevated gas readings in the target Mundu fm, wireline logs to be run, HYSY 937 JU. Any resulting discovery could be tied-in to the Oyong facilities. Ophir (op), partners Singapore Petr. + Cue Egy.

Paus Biru-1 in South Madura Deep (East Java B.) TMD 710m, elevated gas readings in the target Mundu fm, wireline logs to be run, HYSY 937 JU. Any resulting discovery could be tied-in to the Oyong facilities. Ophir (op), partners Singapore Petr. + Cue Egy.

It was reported in October 2019 that Mari Petroleum Company Ltd (MPCL) has been awarded the Ghauri D&PL (development and production lease) over its Ghauri X-1 oil discovery in Potwar Basin and it has been made effective retrospectively from 1 January 2016. The lease, which has been excised from the Ghauri 3273-3 EL concession, covers 17.50 sq km area and is located in the Jhelum and Rawalpindi districts of the Punjab province. The equity split is as follows: MPCL 65% (operator) and Pakistan Petroleum Ltd (PPL) 35%. MPCL had announced the Ghauri X-1 oil discovery on 30 April 2014. The company reported that successful drill stem tests (DSTs) were carried out in the Cambrian Kussak and Eocene Sakesar formations. The well, post-acidisation, flowed from the Sakesar Formation at a rate of 5,500 bo/d through a 32/64” choke with a pressure of 1,100 psi. The same formation, without acidisation, had flowed 1,200 bo/d through a 28/64” choke. The well flowed from the Kussak Formation in surges, with nitrogen lift, at a rate of 136 bo/d.

MPCL (Mari Petroleum 65% op, PPL 35%) has been awarded the Ghauri D&PL.

The ANP has published the schedule and draft of rules for the planned 6th pre-salt round, scheduled 7 Nov ‘19. The offer includes the Aram, Bumerangue, Cruzeiro do Sul, Sudoeste de Sagitário and Norte de Brava blocks in the Campos + Santos basins, pre-salt polygon. Petrobras will exercise its pre-emptive rights on Aram, Norte de Brava and Sudoeste de Sagitário with 30% + operatorship. Details (in Portuguese) here.

Brazil, not found

Oyster is on the lookout for partners in its wholly-owned, 11,200 sq km block 1101 (Antsiranana) in the Ambilobe Basin along the northern tip of the island:

Oyster is on the lookout for partners in its wholly-owned, 11,200 sq km block 1101 (Antsiranana) in the Ambilobe Basin along the northern tip of the island:

Sharjah National Oil Corporation (SNOC) on behalf of the Petroleum Council of the Emirate of Sharjah launched the Sharjah 2018 License Round for three onshore blocks (A, B and C) on 25 June 2018. SNOC opened a data room to pre-qualified companies on 4 July 2018 and bids are due for submission on 18 November 2018, with any contracts subsequently awarded becoming effective on 1 January 2019. SNOC intends to retain a 25% government interest in blocks A and C, but it is seeking a 50% strategic partner with which to explore Block B, in which it has mapped an undrilled deep gas play below the depleted Sajaa gas-condensate field. It intends to initiate drilling within Block B during 4Q 2018. The company previously reported that it had completed a new 483 sq km 3D onshore survey during February 2017, however it transpires that up to 851 sq km of “new” 3D and 200 sq km of 2013 vintage 3D data will be made available under license as required. Of note is that SNOC’s initial interpretation of the newly acquired seismic has lead it to believe that “most” historical wells were either drilled off structure or failed to reach their primary Lower Cretaceous, Thamama Group carbonate objectives. Additional details can be found on the SNOC website: www.snoc.ae The three onshore blocks delineated cover an area of 1,885 sq km. They include developed hydrocarbon discoveries, along with a range of undrilled leads, prospects and untested plays. CONCESSION AREA AREA (sq km) SNOC % PARTNER(S) % OPERATOR SNOC CARRY BIDDING PARAMETERS Concession A 437        (includes Sajaa, Moveid & Kahaif fields) 25% 75% Farmee Carry on E&A (reimbursment during development phase) Bid Work Programme (Minimum one firm well during first exploration period) Concession B 264 50% 50% SNOC No carry. SNOC will pay its share of costs as per equity Bid bonus.               Partner with SNOC on first exploration well (currently in planning phase) Concession C 1184 25% 75% Farmee Carry on E&A (reimbursement during development phase) Bid Work Programme (Minimum 600 sq km 3D seismic during first exploration period)             © 2018 IHS Markit A WesternGeco land crew had initiated SNOC’s latest seismic survey in late October 2016. It was utilising Schlumberger’s UniQ land seismic acquisition platform technology to manage the long offsets required to image the complex overthrust geology in the area, and to help identify unconventional resource potential along with the existence of deep oil and gas objectives within the emirate. In 2016, Sheikh Sultan Bin Ahmed Al Qasimi, the deputy chairman of Sharjah Petroleum Council (SPC) and president of SNOC had unveiled plans to import liquefied natural gas (LNG) to "add to the supply of gas in Sharjah and Northern Emirates to meet the growing demand for energy”. The new survey was intended to support the forthcoming exploration drilling campaign, which is being devised to help meet those growing energy requirements through the discovery of additional domestic resources. Seismic data processing was completed during 1H 2017 in Schlumberger’s Abu Dhabi processing center using reverse time migration to image the complex geology. The 2016-2017 3D coverage complements a 3D survey programme conducted onshore Sharjah during 2011-13. During February 2014 a decree signed by His Highness Dr Shaikh Sultan Bin Mohammad Al Qasimi, Supreme Council Member and Ruler of Sharjah was promulgated formally merging the Sharjah Liquefaction Gas Company (Shalco) and Sharjah Oil Company (SOC) into a new entity to be known as the Sharjah National Oil Corporation (SNOC). The SNOC is owned by the government, but it operates autonomously on a commercial basis and is headquartered in Sharjah City. The Sharjah Petroleum Council was created in 1999 as a result of a decree issued by Shaikh Sultan bin Muhammad Al Qasimi. The council was charged with oversight of the petroleum sector within the emirate, including upstream and downstream planning policy, legislation and investment. The council replaced the existing Department of Petroleum and Minerals which had been undertaking these roles since 1972. The chairman of the Department of Petroleum and Minerals, Shaikh Ahmad bin Sultan Al Qasimi was appointed chair of the new council.

United Arab Emirates Sharjah National Oil Corporation (SNOC) Sharjah 2018 License Round submissions due mid-November 2018

Khewari 2568-3 EL, Indus onshore, Sindh, P&A dry at TD 3,713m (Cret.), co. N-3 rig. OGDCL (op), partner Govt Holdings.

Wassan 1 (OGDCL 95% op, GHPl 5%) in the Khewari 2568-3 EL block, P&A after being unsuccessful in finding the hc.

Santos Ltd spudded the Bearcat 1 exploration well in ATP 1189-P, located in the Cooper-Eromanga Basin, on 21 July 2018.  The well was drilled by the “Ensign 970” land rig.  On 2 August 2018 the well was suspended, as a future gas production well, after reaching a total depth of 3,007 m. The well was part of an ongoing exploration campaign within ATP 1189-P. ATP 1189-P, which covers an area of 9,151 sq km, was awarded on 1 January 2015.  The well is being in block Total 66(a), which is held by Santos Ltd (37.5% + Operator), Santos subsidiaries Santos Petroleum Pty Ltd (25%) and Vamgas Pty Ltd (7.5%) and Beach Energy subsidiary Delhi Petroleum Pty Ltd (30%).

Bearcat 1 exploration well in ATP 1189-P, located in the Cooper-Eromanga Basin well was suspended, as a future gas production well, after reaching a total depth of 3,007 m.

New Era is acquiring a 50% non-operating stake from Bridgeport in applications ATP 2023 + 2024-P (total 855 sq km) and in ATP 948-P (2,004 sq km) and PL 256 (15 sq km) in the Cooper-Eromanga.  New Era will fund part of a 4-year programme which includes seismic + drilling.

Australia, ATP 948-P

A decree published in Venezuela's official gazette by the Ministry of Petroleum on 16 November 2017, awarded the Petrosur JV the rights to the Junin-10 Block in the Orinoco heavy oil belt. The Supreme Court in mid-July 2017, announced the creation of the Petrosur JV with Dutch company Stichting Administratiekantoor Inversiones Petroleras Iberoamericanas (SAIPI) participating with 40% WI and PDVSA affiliate Corporacion Venezolana del Petroleo SA with 60% WI. Stichtings are Dutch entities that allow ownership and control to be legally separate, so that the identities of the owners or beneficiaries can remain private to the public. The Venezuelan Supreme Court's ruling approving the creation of Petrosur was issued by the court's constitutional division and ignored the 1999 constitution that explicitly states that only the National Assembly can approve joint ventures. The Supreme Court has ruled that it can choose oil sector JV partners and bypass the elected national assembly after it fell into opposition hands following the 2015 elections. State oil company PDVSA believes the block has the potential to produce 200,000 bo/d. CNPC agreed to invest in Junin-10 in September 2013 as part of a Chinese state-visit but no news has since surfaced regarding this pledged investment. Prior to that in 2010, PDVSA rejected offers by Statoil and Total to partner in the block.

Venezuela, Junin 10

Sand Hill is looking to sell up to all of its 80% in th E X-5 Adea, Pannonian Basin in E. Romania ahead of a planned, 2-phase, 550-sq km 3D survey (costed at USD 3.5 MM phase 1 and USD 2 MM phase 2). Three explo wells would follow as well as 130km of 2D. Sand Hill (op), partner Panfora O&G. Contact: David Westlund, [email protected].

Sand Hill is looking to sell up to all of its 80% in th E X-5 Adea, Pannonian Basin in E. Romania ahead of a planned, 2-phase, 550-sq km 3D survey (costed at USD 3.5 MM phase 1 and USD 2 MM phase 2). Three explo wells would follow as well as 130km of 2D. Sand Hill (op), partner Panfora O&G.

Hitherto unreported on 10 October 2019, Exxom Mobil Corp (Exxon) and partner NAMCOR were awarded PEL 86 (Block 1811A) and PEL 89 (Block 1711) located within the Namibe basin. The blocks were awarded after government approved the farm in agreement signed between Exxon and NAMCOR (On 24 April 2018 see: Exxon Mobil Corp awarded two blocks (Block 1710 and Block 1810) and farms into two (Blocks 1711 and 1811A) ). Block 1711 and Block 1811A cover a combined area in excess of 11,000 sq km in water ranging in depths between 0 m and 2,400 m. Exxon operates the blocks with an 85% interest and NAMCOR holds the remaining 15% interest. Both blocks have been explored with 3D seismic acquisitions and drilling. In 2012 Enigma Oil & Gas Exploration (Pty) Ltd a subsidiary of Chariot Oil and Gas drilled the 1811/05 01 exploratory well which was plugged and abandoned as dry. In 2008 Sintezneftegas Namibia Ltd drilled the Kunene 1 well which was plugged and abandoned with gas shows.

Exxon secured rights to PEL 86 (block 1811A) and PEL 89 (block 1711) totalling some 1,000 sq km in WD 0-2,400m, Namibe Basin off the north coast on 10 Oct '19. Exxon (op), partner Namcor.

Parnaiba Gas Natural (PGN) suspended with results unreported the 4-PGN-ARAGUAINA-SE-MA (4-PGN-022-MA) new-pool wildcat (NPW) in the BT-PN-001 contract, PN-T-102 block on 10 December 2017.  The well may be a dry hole as the operator has yet to file a gas show report for it.  The NPW was spudded on 14 November 2017.  The well had a proposed total depth (PTD) of 2,178 m.  The primary targets were the Devonian Cabecas Formation and the Mississippian Poti Formation. The well is located in the southeastern corner of the discovery evaluation plan (PAD), the PA_1OGX119MA_PN-T-102 in the Parnaiba Basin approximately 20.4 km north southeast of the 1-OGX-FAZSERRINHA-MA (1-OGX-120-MA) NFW gas discovery well drilled in 2013.   On 11 October 2017 the ANP approved a 3rd modification to the discovery evaluation plan (PAD) operated by Parnaiba Gas Natural (PGN) associated with the BT-PN-001 contract, PN-T-102 block that includes new commitments and a final expiry extension pending conditions.  The operator will have a decision point on 20 December 2017 to drill a horizontal well from a side-track of firm well, assumed to be the 3-PGN-ARAGUAINA-003D-MA (3-PGN-021D-MA) outpost.  The horizontal well is dependent on the results of the firm well.  The operator has a second decision point on 6 April 2018 to drill another exploration well on a newly mapped structure nearby.  If all of the commitments are met the final expiry of the PAD will be on 10 September 2018. On 15 June 2016 the ANP approved a 2nd modification to the discovery evaluation plan (PAD) operated by Parnaiba Gas Natural (PGN) associated with the BT-PN-001 contract, PN-T-102 block that includes a final expiry extension pending conditions.  Two new-field wildcats are associated with the PAD and include the 1-OGX-ARAGUAINA-MA (1-OGX-119-MA) and the 1-OGX-FAZSERRINHA-MA (1-OGX-120-MA) both located in the block. The PAD modification approval has firm and contingent commitments.  The June 2016 firm commitment for the PAD is for the operator to conduct petrophysical and geo-mechanical analysis of the data obtained from drilling the 3-PGN-ARAGUAINA-002A-MA (3-PGN-016A-MA) outpost, suspended with gas shows in January 2016.  The operator will also have to stimulate the outpost well and conduct a formation test. The operator has to conclude the firm commitments by 15 November 2016 and decide to conduct the contingent commitments or the PAD will expire.  The contingent commitments include the acquisition of 102 km of 2D seismic and the drilling of one well and a formation test of that well.  If the contingent commitments are conducted the PAD will have a final expiry date of 10 February 2018 whereby commerciality will have to be declared or the PAD relinquished. On 26 June 2014 the ANP originally approved the discovery evaluation plan (PAD) filed by Parnaiba Gas Natural (PGN) for the PA_1OGX119MA_PN-T-102 carved out of the BT-PN-001 contract, PN-T-102 block in the Parnaiba Basin. The contract was partially relinquished with an evaluation area carved out of the block for the two discovery wells that covers an area of 963.70 sq km.  Two new-field wildcats are associated with the PAD and include the 1-OGX-ARAGUAINA-MA (1-OGX-119-MA) and the 1-OGX-FAZSERRINHA-MA (1-OGX-120-MA) both located in the block. The PAD covers an area of 963.70 sq km. The original expiry date of the PAD was 10 October 2016. Parnaiba Gas Natural is the operator of the BT-PN-001 contract with a 100% working interest after acquiring all of the working interest from former partners Imetame, Orteng and Delp.  On 28 December 2015 the ANP granted Parnaiba Gas Natural approval to acquire all of the working interest in the BT-PN-001 contract, PN-T-102 block from its three former partners Imetame who held 16.665% working interest, Orteng who held 16.6665%, and Delp with 16.67%.  

Brazil (Parnaiba B.) 3-PGN-ARAGUAINA-002A-MA op. by PARNAIBA (100.0%) in PN-T-102 block

At crossroads of ADLs 391718, 391719, 319720 + 391721, E. of the Horseshoe 1/1A discovery in North Slope Basin, P&A’ing at TD 2,073m, analysis of wireline logs reveal low oil saturations in the primary Nanushuk Topset + Torok targets, MDT likewise inconclusive, Nordic-Calista Services rig 3. Pantheon (Accumulate Egy [88 Egy], Otto Egy, Red Emperor JV) (op), partner Borealis.

At crossroads of ADLs 391718, 391719, 319720 + 391721, E. of the Horseshoe 1/1A discovery in North Slope Basin, P&A’ing at TD 2,073m, analysis of wireline logs reveal low oil saturations in the primary Nanushuk Topset + Torok targets, MDT likewise inconclusive, Nordic-Calista Services rig 3. Pantheon (Accumulate Egy [88 Egy], Otto Egy, Red Emperor JV) (op), partner Borealis.

1st well in PL 762, NE of Norne, WD 288m, TVD 2,724m, failed to find gas in the Permian, P&A dry. Aker BP (op), partners Equinor + Petoro. Deepwater Stavanger SS moving to Nipa well (see DEA 16 Aug ’19) in PL 986 SE for the same operator.

6608/06-01 (Vagar) exploration (Aker BP 20% op. Equinor 60%, Petoro 20%) in PL 762, P&A dry, intersected 285m of carbonate rocks in the Zechstein group in the Permian, the rocks were partially tight and partially with poor reservoir quality, but with 4m of moderate reservoir quality. TD=2724m.

Wushi 1-6-4d (WS 1-6-4d) was suspended (results TBC) on or around 16 November 2019 after having been spudded on or around 10 November 2019, using the "Kantan 2" jack-up. The deviated oil appraisal well will likely be targeting the Weizhou Formation. Wushi 1-6-4d is in the CNOOC operated Beihai 31 Block in the offshore Beibuwan Basin and is approximately 4.5km S of Wushi 1-6-1, drilled by CNOOC in August 2013.

Wushi 1-6-4d (WS 1-6-4d) was suspended (results TBC) on or around 16 November 2019 after having been spudded on or around 10 November 2019, using the "Kantan 2" jack-up. The deviated oil appraisal well will likely be targeting the Weizhou Formation. Wushi 1-6-4d is in the CNOOC operated Beihai 31 Block in the offshore Beibuwan Basin and is approximately 4.5km S of Wushi 1-6-1, drilled by CNOOC in August 2013.

Salda Nadi block 9b, Upazila Kasba of Brahmanbaria District, onshore Bengal Basin, in August tested gas from between 2,463-2,472m and 2,528-2,535m, 3-9 MMcf/d resp., pressure failure suggests non-commercial tight gas zones. Bapex continues to drill 500m deeper to the original planned TD. Hong Hua - Bijoy 12 rig.

Kosba-1 nfw, Salda Nadi block 9b, Upazila Kasba of Brahmanbaria District, onshore Bengal Basin, in August tested gas from between 2,463-2,472m and 2,528-2,535m, 3-9 MMcf/d resp., pressure failure suggests non-commercial tight gas zones. Bapex continues to drill 500m deeper to the original planned TD.

Aker BP has taken a 23.835% interest in PL 159 D from operator Equinor. The deal was reported by the NPD on 5 June 2018 and it is effective from 31 May 2018. PL 159 D covers a 7 sq km area over part of block 6507/3 to the east of Aerfugl. It contains the 2009 Idun North gas discovery. Aker BP operates the neighbouring licences (PL 212, PL 212 B and PL 262) which contain the Aerfugl and Skarv fields and it is assumed that the company is interested in developing Idun North along with Aerfugl. Idun North discovery well 6507/3-7 proved gas in the Middle Jurassic Fangst Group with estimated recoverable reserves given at the time of 20-105 Bcfg. The Aerfugl field is in development, with the PDO being approved in April 2018. Aerfugl will be a phased development using a total of six subsea wells tied-back to the Skarv FPSO. Phase I (three producers in the southern part of the field) passed concept selection in March 2017. The development will utilise electrically heated flowlines, chemical pumps and scale inhibitor packages for flow assurance and first gas is due in October 2020. Test production from the field was carried out in advance of the PDO submission in order to provide in depth knowledge of the reservoir. The plan for Phase II is yet to be finalised but is likely to consist of two wells in the northern part of the field together with a well on Snadd Outer (PL 212 E) and is tentatively due onstream in Q3 2023. Following completion of the deal, interest in PL 159 D is divided between Equinor Energy AS (36.165% + operator), DEA Norge AS (40%) and Aker BP ASA (23.835%).

Aker BP acquired 23,835% interest in the licences PL 159 D from Equinor (->36,165% + Op, DEA 40%)

Hague and London Oil BV (HALO) is reviewing the possibility of divesting its non-operating interest in SC 54A, located in Northwest Palawan Basin, to better focus on their operations in Europe. The service contract is currently suspended under force majeure, until 5 August 2020. On 9 August 2017, the joint venture received three years extension from the Department of Energy (DOE) for the exploration license for the block. The suspension is related to a territorial dispute related to international arbitration at the West Philippines Sea. No activity beyond care and maintenance is allowed at the licensed block unless the dispute is settled before the suspension duration end. The SC 54A contains several oil fields such as Yakal (2008), Tindalo (2008) and Nido 1 (1976). The Nido 1 is the first offshore oil discovery in the Philippines and although it proved to be non-commercial at the time, acted as a catalyst for a new cycle of increased exploration interest in the basin. Tindalo field was abandoned after four tested intervals were found to produce formation water, following a workover on the well. The commerciality of the Yakal 1 discovery is yet to be proven. Current right holders of the block are Nido Petroleum Philippines Pty Ltd (42.4%, operator), Yilgarn Petroleum Philippines Pty Ltd, (30.1%), Hague and London Oil BV (15 %) and TG World Corp (12.5%). Background Information The Philippines DOE has previously approved a moratorium for SC 54 for three years to give the partners sufficient time to evaluate existing 3D seismic and the prior small discoveries in the block. At the end of the moratorium period, the joint venture can elect to enter Exploration sub-phase 7, which carries a one-well commitment by 2018. If the joint venture continues into production period, the three years moratorium period will be automatically deducted from the production period. On 27 October 2014, Wessex Exploration PLC completed the acquisition of Hague and London Oil BV (HALO), in turn holding 15% interest in SC 54-A. Through 2014, HALO acquired the 15% interest on the SC 54A block formerly owned by Trafigura Ventures III BV. As of April 2013, Nido Petroleum was still seeking farm-in partners for SC 54A block. The block interest was held by Nido Petroleum Philippines Pty Ltd (42.4%, operator), Kairiki Energy Limited, through its wholly-owned subsidiary Yilgarn Petroleum Philippines Pty Ltd, (30.1%), Trafigura Ventures III BV (15%) and TG World Corp (12.5%). On 4 March 2013 Nido Petroleum announced the termination of negotiations with Viking Energy Holdings 2 Ltd regarding a potential farm-in to SC 54A. The block contains undeveloped oil fields Tindalo, Nido 1X1 and Yakal. Nido and the SC 54A partners will continue working with the operating consortium of adjacent SC 14 towards a possible development of Nido 1X1 via the Nido A platform, located in SC 14. On 1 June 2012, Nido together with its partners announced the signing of a Memorandum of Agreement (MoA) with Viking Energy Holdings 2 Ltd, outlining key commercial terms upon which a farm-in agreement will subsequently be negotiated. According to the MoA, Viking will be assigned a 60% operating stake in exchange for carrying the existing rightholders in the development of the Yakal, Tindalo and Nido 1 oil fields in the block. At the time of the announcement, the MoA was still subject to negotiation and signing of a formal agreement between the parties. Once the deal with Viking pushes through and given official approval, interest sharing in SC 54A will be Viking Energy (60%, operator), Nido Petroleum (16.96%), Yilgarn Petroleum (12.04%), Trafigura (6%) and TG World (5%). On 25 March 2010, the DOE approved the farm-out agreements of Kairiki Energy and Nido Petroleum with TG World Energy Corp for 12.5% participating interest in the SC54A block. In early March 2010, Kairiki Energy and Nido Petroleum signed separate farm-out agreements with TG World Energy Corp (4.9% interest ) upon commencement of production at the Tindalo oil field and as subsequent crude oil cargoes from the field are lifted. Under the agreement with Nido Petroleum, TG World acquired 7.6% interest. In November 2009, Kairiki Energy and Nido Petroleum farmed-out of 15% interest in SC54A block to Trafigura Ventures III BV. The partition of SC 54 into SC 54-A (inboard portion) and SC 54-B (outboard portion) was approved by the DOE on 17 June 2009. This partition was intended to allow development of the shallow water block and promote exploration in the deep water block. SC 54-A contains marginal discoveries Tindalo, Nido 1 and Yakal 1. On 30 September 2008, Nido completed operations in the Yakal 1 oil discovery in SC 54. Yakal 1 encountered an oil column of 66m to 78m in the Nido Limestone Formation at a depth of 1,733m to 1,839m. Yakal 1 was drilled to a TD of 1,969.5m and is situated in water depth of around 115m. On 16 January 2008, Nido completed acquisition of 194km of 2D seismic data over the Signal Head oil discovery area in its newly renegotiated SC 54 block area. The survey commenced on 12 January 2008, using the CGGVeritas "Pacific Titan" S/S. On 11 January 2008, Nido announced that the company renegotiated with the Philippines government a new block outline for the SC 54 block. The new block outline was to include the Signal Head oil discovery (deemed uneconomical during the time of drill) made by Phil Oil & Geotherm Energy Ltd in 1978. The total block size remained the same at 5,376 sq km with the company relinquishing 120 sq km in the less prospective southeastern portion of the block to make up for the gain of the Signal Head. On 30 October 2007, Nido completed shooting a 165 sq km 3D seismic survey over the block. The survey commenced on 30 September 2007 using the CGGVeritas "Pacific Titan" S/V. The survey focused on the Princesa lead and it was tied into a previous 640 sq km 3D seismic survey which was concluded on 10 January 2007. On 20 March 2006, Nido announced that it accepted an offer from Australian company Yilgarn Gold Ltd to farm-in to SC 54. Yilgarn would earn 40% interest upon completion of two stages. First, Yilgarn would fund the acquisition and processing of seismic data on a 4:3 promote basis, based on estimated costs of US$ 6 million for the programme. Second, Yilgarn would fund the drilling of a well on a 2:1 promote basis, based on estimated well costs of US$ 15 million. The farm-in offer was conditional upon Yilgarn obtaining financing for the seismic programme, relevant approvals, conducting a due diligence and executing a formal farm-in agreement with Nido. SC 54 was awarded to Nido (100%) in August 2005. The company committed to a US$ 220,000 G&G study during the first (six month) sub-phase, after which it had the option to enter the second sub-phase of one year, during which a single exploration well (at a minimum cost of US$ 6 million) is required. Further G&G studies and post-drill analysis were required for the third sub-phase (six months), while the fourth sub-phase (12 months) required another well, at a minimum cost of US$ 6 million. The fifth sub-phase (12 months) involved additional post-drill analysis and G&G studies, while the sixth and seventh sub-phases (18 months and 12 months respectively) carry commitments of one well each, at a minimum cost of US$ 6 million per well. The Nido 1 discovery was made in 1976 by Cities Services. The well was targeting Oligo-Miocene reefal buildups along the Northwest Palawan shelf. This was the first offshore oil discovery in the Philippines and although it proved to be non-commercial at the time, acted as a catalyst for a new cycle of increased exploration interest in the basin.

Philippines Hague and London Oil BV potentially divesting its non-operating interest in SC 54A

Block 3 (Afar), Huqf Arch in Oman Basin, E. Oman, ops terminated 3Q ’18, tested, understood successful in the Khufai fm. PTD was 4,140m. CCED (op), partners Tethys Oil + Mitsui.

Block 3 (Afar), Huqf Arch in Oman Basin, E. Oman, ops terminated 3Q ’18, tested, understood successful in the Khufai fm. PTD was 4,140m. CCED (op), partners Tethys Oil + Mitsui.

On 7 August 2019 Oilex Ltd announced that it has entered into an agreement to acquire Holloman Energy Corporation’s subsidiary company Holloman Petroleum Pty Ltd. Holloman Petroleum holds 48.5% interest in two Cooper-Eromanga Basin permits: PEL 112 and PEL 444, alongside operator of the permits Terra Nova Energy. Both Terra Nova and Holloman had been looking to divest their interests in the permits. Oilex has agreed to acquire 100% interest in the subsidiary for the consideration of 40,416,917 ordinary Oilex Shares, plus AUD 24,250 payable upon completion. The structure values the deal at around AUD 1.2 million, based on AUD 0.03 per Oilex share. The deal is set to close on 30 September 2019. The permits are located in the Western Flank Fairway and Terra Nova reports that there are a number of Namur and Birkhead structural prospects within both permits. PEL 112 covers an area of 1,000 sq km and was awarded on 17 April 2003. Terra Nova has outlined the Milo, Libby and Drole structural prospects, which combined hold a potential 9 MMb oil in place. Milo is outlined as the primary target, with the largest potential resource and lowest risk. One exploration well is due in 2019. The well will likely target one of these prospects and be positioned from the 2012 Mulka 3D seismic survey, which is located in the north of the permit area. The Wolfman 1 well was drilled within the Mulka survey area in 2013. It targeted a dip closure in the Namur Sandstone at around 1,200 m depth but was dry at location. Secondary, deeper, targets of the Birkhead and Hutton formations were also dry. PEL 444 covers an area of 1,150 sq km and was also awarded on 13 April 2003. Terra Nova has identified the Maverick mid-Birkhead prospect which is considered as a key exploration target.  It has a potential 1.71 MMbo resource. The Crater and Moraine Namur prospects have also been outlined as potential targets. The prospects in PEL 444 have been identified from the merged Jasmin and Wingman seismic datasets, which Terra Nova has reported as providing high level mapping of the licence. Terra Nova considers there is potential for the Hoplite 1 oil play fairway to extend into PEL 444. One commitment well is due in 2021. The Baikal 1 well was drilled in 2015, located approximately 8 km west of Hoplite 1. The well targeted this the oil play within the mid-Birkhead channel sands but was dry at location. However, the channel sands, which were mapped from seismic, were encountered and now provides qualification to the current exploration model. PEL 112 and PEL 444 are held by Terra Nova Energy Australia Pty Ltd (a Claren Energy subsidiary - 51.5% + Operator) and Holloman Petroleum Pty Ltd (48.5%).  Upon completion of Oilex acquiring Holloman Petroleum Pty Ltd, interests will become: Terra Nova Energy Australia Pty Ltd (51.5% + Operator) and Oilex Ltd (48.5%). Completion of the deal will see Holloman Energy holding zero exploration assets.

Oilex has agreed to acquire Holloman Energy’s 48,5% interests in Terra Nova-run (51,50% op.) PEL 112 + 444, (total 2255km²).

Thailand’s 21st round is expected to be held towards 2Q ’19, after the announcement of winners for the Bongkot + Erawan fields lateish in 2018. There is a thought trend to release only onshore blocks in round 21, offered as PSCs and service contracts, in addition to royalty/tax concessions. It is recalled the following blocks had originally been earmarked: Onshore: Phitsanulok Basin: L01/57, L07/57, L08/57 Mae Sot Basin: L06/57 Phetchabun Basin: L16/57A-L16/57B Chao Phraya Basin: L23/57 Khorat Plateau Basin: L02/57, L03/57, L04/57, L05/57, L09/57, L10/57, L11/57, L12/57, L13/57, L14/57, L15/57, L17/57, L18/57, L19/57, L20/57, L21/57, L22/57 Offshore : Gulf of Thailand Basin: G01/57, G02/57A-G02/57B, G03/57, G04/57, G05/57A-G05/57B Malay Basin: G06/57.

Thailand’s 21st round is expected to be held towards 2Q ’19, after the announcement of winners for the Bongkot + Erawan fields lateish in 2018. There is a thought trend to release only onshore blocks in round 21, offered as PSCs and service contracts, in addition to royalty/tax concessions. It is recalled the following blocks had originally been earmarked: Onshore: Phitsanulok Basin: L01/57, L07/57, L08/57 Mae Sot Basin: L06/57 Phetchabun Basin: L16/57A-L16/57B Chao Phraya Basin: L23/57 Khorat Plateau Basin: L02/57, L03/57, L04/57, L05/57, L09/57, L10/57, L11/57, L12/57, L13/57, L14/57, L15/57, L17/57, L18/57, L19/57, L20/57, L21/57, L22/57 Offshore : Gulf of Thailand Basin: G01/57, G02/57A-G02/57B, G03/57, G04/57, G05/57A-G05/57B Malay Basin: G06/57.

Total has agreed to sell all of its interests in the Martin Linge field (51%) and Garantiana discovery (40%) on the Norwegian Continental Shelf to Statoil. The consideration for the transaction is $1.45 billion with an effective date of January 1st, 2017.  The transaction remains subject to final due diligence and approval from the relevant authorities.   'The forthcoming acquisition of the Maersk Oil portfolio, which will make Total the second largest operator in the North Sea, leads us to review our portfolio in this area so as to focus on the assets in which Total will be able to generate synergies and reduce their breakeven points. In this context, given that Martin Linge is Total's only operated asset in Norway, there is limited scope to optimize operations, whereas with Statoil’s leading operating position on the Norwegian Continental Shelf, Statoil is in a better position to optimize this asset for the benefit of all stakeholders. We are therefore satisfied with the agreement with Statoil, a long time trusted partner, which in addition, offers us a satisfactory value for this asset', commented Arnaud Breuillac, President, Exploration & Production at Total. 'Norway remains a strategic country for Total as one of the largest contributors to the Group's production and we of course intend to continue bringing our expertise to Norway by focusing in particular on major non-operated assets such as Ekofisk, Snohvit and Johan Sverdrup.'   The transaction involves the transfer of relevant employees from Total to Statoil in compliance with the applicable legislation.Martin Linge is an oil and gas field under development west of the Oseberg field in the North Sea (Source: Statoil) Click here for Statoil announcement: Statoil takes over operatorships and equity in the Martin Linge field and Garantiana discovery Original article link Source: Total

Norway, not found

Bennett Resources, a wholly owned subsidiary of Black Mountain Exploration, acquired 100% interest and operatorship in EP 371, located in the Canning Basin, in late 2019. Bennett Resources acquired the interest from previous holder Mitsubishi. Initially a name change was reported and registered, in October 2019, from Mitsubishi subsidiary Diamond Resources to Bennett Resources. This has now been reported to be an interest change, with the Black Mountain subsidiary taking full interest. The permit was awarded in March 1993 and is currently scheduled to expire, or be renewed, on 20 July 2023. Two wells are outlined under the work programme until the expiry date. Eight wells have already been drilled during the permit's validity, including the Asgard, Valhalla 2 and Valhalla North tight gas discovery wells. Mitsubishi acquired its 100% interest in the licence after completing an asset swap agreement, with Buru Energy Ltd, in January 2018. Under the terms of the deal Diamond Resources acquired Buru’s 50% interest and operatorship in the EP 371 permit. Diamond Resources gained full access to the associated gas resources, facilitating a timely appraisal and commercialisation of the resources. In return, Buru acquired Diamond Resources’ 50% interest in the conventional fields located in L 20, L21 and EP 391, EP 431, EP 436 and EP 428. The deal was completed to allow the companies to focus on areas in which they hold most expertise and have the ability to maximize the exploration potential and production from the assets. As well as the Asgard, Valhalla 2 and Valhalla North tight gas discoveries, EP 371 also contains the oil discovery Crimson Lake, made in 1988. Possible options for development include producing gas for the domestic market, utilizing existing infrastructure, or tying into the LNG facilities available. Black Mountain has submitted environmental plans for downhole well operations, possibly involving workovers of the existing wells. EP 371, which covers an area of 3,675 sq km, was awarded on 18 March 1993. Black Mountain Resources now holds 100% interest through subsidiary Bennett Resources Ltd.

Bennett Resources, a wholly owned subsidiary of Black Mountain Exploration, acquired 100% in EP 371 from Mitsubishi.

NE part of REC-T-070 block, Recôncavo onshore, oil shows report to ANP on 21 Jul ’17, susp. mid-Sep ‘17. PTD was 3,120m, target Candeias fm.

1-LMB-001D-BA (1-BRSA-1351D-BA) op. by Petrobras (100%) in REC-T-070 block, suspended with oil shows.

Sonatrach is understood to have abandoned its Sif Fatima Nord 1 (SFN 1) NFW in October 2017. The well, located on the Sif Fatima II exploration licence in the Berkine Basin, was spudded on 27 April 2017. Drilling operations were carried out using the ENTP #139 rig. SFN 1 reached a TD of 4,400m and was targeting the Early Devonian in a prospect lying to the north of the Rhourde Dabdaba Nord Field. The well was the second spudded on the block in 2017. Sonatrach operates Sif Fatima II, which confers exploration rights across the Sif Fatima Field Complex, with 100% equity.

Algeria, Sif Fatima II (Dev)

Shunbei field area in Shuntuoguole North block, Tarim Basin, tested 804 bo/d from the Ordovician.

China (Tarim B.) ? op. by SINOPEC XB (100.0%) in Shuntuoguole block

EP 20-7-1 was completed on 10 July 2019 without result reported. CNOOC – Shenzhen spudded a NFW in the PRMB Basin, South China Sea, on 11 June 2019. Enping 20-7-1, located in the Enping Sag in a water depth of 90 m area, has target in the Mio-Oligocene clastic play. “HYSY 943” J/U is used of the drilling operation. In March 2019 CNOOC has completed EP 20-1-1, EP 20-2-1 and EP 20-5-1 in this area, but without result reported. In November 2018, CNOOC completed EP 20-4-1 with oil in this area. In January 2019 an appraisal well, EP 20-4-2 was drilled. In February and March 2018, CNOOC completed EP 15-2-1 and EP 10-2-1, in the Enping Sag, both well penetrated oil bearing zones. EP 10-2-1 and EP 15-2-1 discoveries, together with existing EP 15-1 discovery, will be expected to be a medium size field group for joint development. EP 15-1 discovery was made in 2016 in the Enping Sag. Background Information In the past few years, CNOOC has made a number of discoveries in the Enping Sag, such as EP 24-2, EP 23-1 and EP 18-1, with reservoir from Miocene to Oligocene sands. Enping 24-2 field was on stream in 2014 and Enping 18-1 was on stream in September 2016. CNOOC was brought Enping 23-1 fields group (together with Enping 23-2 and Enping 23-7) on stream in November 2016. In 2016 CNOOC has also drilled two new-field wildcat wells in this area, EP 11-4-1 and EP 16-1-1, without result reported. In 2017 CNOOC completed EP 23-11-1d in May and EP 18-6-1 in November in this area without result reported. In 2018 CNOOC also drilled EP 12-2-1d in the Enping Sag without result reported.

EP 20-7-1 – Completed without result reported – PRMB, South China Sea

Khan Kubrat (Han Kubrat) block, frontier Black Sea deepwaters, WD 1,200m, TD 3,327m, completed in June, non-commercial hydrocarbons in the target Maykop fm sands, not tested, Noble Globetrotter II DS. Shell (op), partners Repsol + Woodside. Studies will now be undertaken by the partners to see how to proceed in the block.

Khan Kubrat (Han Kubrat) block, frontier Black Sea deepwaters, WD 1,200m, TD 3,327m, completed in June, non-commercial hydrocarbons in the target Maykop fm sands, not tested, Noble Globetrotter II DS. Shell (op), partners Repsol + Woodside.

On 6 December 2018, the ANP approved of Bertek divesting its 100% working interest in the ES-T-345 and ES-T-476 blocks in the onshore Espirito Santo Basin to newcomer BGM Petroleo e Gas Ltda.  Bertek was granted the official awards for the blocks in January 2018 through the ANP Round 14. On 29 January 2018, Bertek with 100% working interest was granted official awards by the ANP for the ES-T-345 and ES-T-476 blocks in the onshore Espirito Santo Basin from the ANP Round 14.  The company paid a total signature bonus of USD 153,312.30 for the two blocks and has work commitments of USD 551,735.02.  The blocks cover a total area of 46.14 sq km. The contract has one five year exploration period and 7.5% royalties.  The rentals for the blocks are USD 14.15/sq km/year.  The local content is stipulated as 50% in the five year exploration phase and in the development production phase is 50%.

Brazil, ES-T-476

In late January 2020, Total E&P USA acquired 4.62% WI from Chevron USA in Green Canyon Block GC 762, situated in the East Texas Coastal Basin. The transaction is effective as of 1 November 2019. GC 762 is sited 4km north from Chevron's Anchor oil and gas field on adjacent block GC 807. In December 2019, Venari Offshore divested its entire 18.75% WI in contiguous blocks GC 762 and GC 763 to operator Chevron USA. Both blocks lie directly adjacent to Chevron's December 2014 Anchor discovery, the company's second Paleogene discovery in 2014, and sited in GC 807 (East Texas Coastal Basin). The final investment decision (FID) to develop the Anchor oilfield was first announced by Total in mid-December 2019. Following completion of the transaction, equity in GC 762 is now shared between Chevron USA (75.38% WI + Op) and Total E&P USA (24.62%).

Total E&P USA acquired 4.62% WI from Chevron USA in Green Canyon Block GC 762, situated in the East Texas Coastal Basin.

After the ratification on 21 June 2020 of 8 agreements signed earlier in the year between IOCs and Egyptian state-agency EGAS (separate article), it is understood that Shell has been awarded the North Cleopatra and North Marina offshore concessions. The two blocks are located along the Egyptian coastline and extend across the boundary between the Herodotus and Nile Delta basins. North Cleopatra and North Marina cover an area of 4,505 sq km and 4,599 sq km, respectively. Both blocks were expected to be on offer as part of the West Mediterranean Bid-round canceled in January 2020 by the Ministry of Petroleum and Mineral Resources.

(Northern Egypt and Herodotus basins) Shell has been awarded the North Cleopatra and North Marina offshore concessions. The two blocks are located along the Egyptian coastline and extend across the boundary between the Herodotus and Nile Delta basins. North Cleopatra and North Marina cover an area of 4,505 sq km and 4,599 sq km, respectively. Both blocks were expected to be on offer as part of the West Mediterranean Bid-round canceled in January 2020 by the Ministry of Petroleum and Mineral Resources.

Spyker has withdrawn from licences 12/06 + 4/16 over blocks 5504/20 W, 5504/24 SW + 5504/20d, home to Lille John + Broder Tuck discoveries. Spyker's 8% has been re-assigned pro-rata to partners. Dana (op), partners Petrogas (UK & Denmark), Danoil + Danish North Sea Fund

(Central Graben Province) Spyker Energy exited the 12/06 and 04/16 licence which covers blocks 5504/20 W, 5504/24 SW and 5504/20d. The 8% interest in each licence that was held by Spyker Energy has been split between the remaining participants.