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Further to DEA 2 Jul ’18 (abandonment): committed well in block 05-3/11, Nam Con Son Basin, P&A gas on 29 Jun ’18, PV Drilling VI JU. Target U. Miocene Mang Cau fm.

11-TTN 1X (Tho Tinh Nam-1) (Rosneft 100%) in block 05-3/11, P&A results n/a. Target U. Miocene Mang Cau fm.

Bozhong Depression in Bohai Gulf Basin, WD 25m, ops terminated late Apr '20, results n/a, Zhongyuouhai 5 JU. Target Tertiary clastics.

Bozhong 8-4S-1d (BZ 8-4S-1d) nfw Bozhong Depression in Bohai Gulf Basin, WD 25m, ops terminated late Apr '20, results n/a, Target Tertiary clastics.

On 1 December 2017, Total Exploration & Production USA was awarded four East Breaks blocks: EB 588 (G36094), EB 589 (G36095), EB 633 (G36096) and EB 678 (G36098), situated in the East Texas Coastal Basin. All four blocks were originally offered as part of Western Gulf of Mexico Lease Sale 249, which was held on 16 August 2017. The leases expected to expire on 30 November 2024. Following official award, Total E&P USA is now the operator and sole interest-holder (100% WI + Op) in all four East Breaks blocks.

Not Found

MOL has farmed out 30% to OMV in licences PL617 and PL771, effective from 22 May 2018. The acreage contains the Eidsvoll prospect which had been carded for 2017 but was shelved and the drill-or-drop deadline on both licenses has been deferred to February 2019. There have been three dry NFWs drilled on the acreage under previous licence, one of which had oil shows - 2/8-7 (1975, Amoco). PL771 was awarded on 6 February 2015 in APA 2014 covering 260.8 sq km of blocks 2/8 and 2/9. PL617 covers 112 sq km in North Sea block 2/9, adjacent to the NW of Hejre Field (Danish sector), and was awarded to a Valiant Petroleum-led group on 3 February 2012 under APA2011. Det norske oljeselskap (now Aker BP) and Point Resources exited PL617 with Det norske's 35% WI transferred to MOL Group on 29 September 2016 (immediately prior to the Aker BP merger completion), and Point's 15% stake was assigned to Fortis Petroleum, effective 31 August 2016. Fortis Petroleum exited PL771 & PL617 with its 30% share taken up by MOL on 23 April 2018. PL617 partners are now MOL Norge AS (70% + Op) and OMV (Norge) AS (30%). PL771 partners are MOL Norge AS (40% + Op), DEA Norge AS (30%) and OMV (Norge) AS (30%).

OMV acquired 30% interest in the licences PL617 (->70% + Op) and PL771 from MOL. (->40% + Op), DEA Norge AS (30%).

OK Energy is looking for an additional partner to farm-in to licence P2104 with a view to appraise and develop the Bedevere discovery in block 48/18c. It was confirmed in October 2019 that 50% interest in the licence was farmed down to Blue Dragon Energy for 100% funding of the appraisal / development well costs but it has been confirmed that further equity is still available in the licence. OK Energy was also awarded neighbouring blocks 48/16, 48/17d, 48/18b and 48/19b in the 30th Licensing Round. The latter two blocks, 48/18b and 48/19b were awarded under the classification of ‘straight to the second term’ with a view to develop the asset. The well is planned to be drilled in Q1 2020. Bedevere was discovered in 1985 by Mobil North Sea. The discovery has a Leman Sandstone Formation reservoir. The structure is located immediately next to a discovery known as 48/18c-5 ‘H’ Structure. This discovery was appraised with 48/18c-7 which proved an extension to the north west while, a second appraisal well 48/18c-12 to the south of the discovery only encountered minor gas. Immediately to the east lies the Anglia field. Anglia was discovered in 1972 before being brought onstream in 1991. The field produced gas until 2015. Pending completion of a deal between OK Energy and Blue Dragon Energy interest in P2104 will be held by OK Energy (North Sea) (50% + operator) and Blue Dragon Energy (50%). For further information, please contact: Paul Barrett – [email protected]

OK Energy is looking for an additional partner to farm-in to licence P2104 with a view to appraise and develop the Bedevere discovery in block 48/18c.

With effect from 30 April 2020 Equinor has increased its interest in PL 293 by 35% through a deal with Var which was reported on 14 May 2020. Operatorship has also been transferred to Equinor. The licence covers 93 sq km over parts of blocks 34/12, 35/7 and 35/10 to the east of Kvitebjorn. It contains the 2008 Afrodite gas discovery and an older discovery made (under a previous licence) by 35/10-2 in 1996. Afrodite was drilled by 34/12-1 which targeted a Jurassic horst block. 52 m of net pay was proven in the Middle Jurassic Brent Group with a porosity of 13% and less than 0.1 mD of permeability (due to the presence of illite). No gas water contact was found. Recoverable resources are estimated at approximately 40 MMboe (NPD, December 2019). Statoil drilled 35/10-2 and encountered a 72 m gas column in the Brent Group. The NPD reported recoverable resources of 23 MMboe in December 2016, but now (2020) classifies the find as 'production is unlikely'. Interest in PL 293 is now divided between Equinor Energy AS (75% + operator) and Var Energi AS (25%).

Equinor has increased its interest in PL 293 by 35% through a deal with Var

Cairn confirmed on 10 March 2020 that the sale of its wholly-owned subsidiary Capricorn Norge AS was completed in late February 2020 (financially effective from 1 January 2020). The company announced in November 2019 that it was selling the subsidiary to Solveig Gas Norway AS for the sum of USD 100 million. At the turn of 2019 / 2020 Solveig was re-named Sval Energi. In February 2020 Capricorn held interests in 15 licences in Norway and operated three of these. It was then awarded a further three licences (all operated) in March 2020 under APA 2019. The licences include two small discoveries (Agat, Jette) and the Nova field which is under development and due onstream in Q3 2021. Capricorn drilled its first two operated wells on the NCS in 2019 – both were dry holes. A well is also planned in 2020 on the Duncan prospect. The company was pre-qualified as an operator in Norway in late 2015 and in February 2016 it was awarded its first licence. Cairn will use the proceeds of the sale to support its ongoing business (which includes assets in the UK). Sval Energi, established in 2011, was acquired in 2019 by HitecVision. It is a significant owner in Gassled (15.55%) and has recently been involved in deals to acquire interests in Polarled and Duva. Its strategy is to become an integrated, infrastructure-based E&P operating company. Capricorn's first NCS operated well was 6508/1-3 which targeted the Lynghaug prospect in PL 758. A 170 m section of Are Formation (the primary objective) was encountered with around 50 m of net sandstone interbedded with claystones and coals. Failure was put down to migration. If it had been successful it would have been a play opener for the Nordland Ridge and could have been developed as a tie-back to the Norne FPSO. Pre-drill reserves estimates were 70 MMboe. Its second well, 6608/11-9, was drilled on the Godalen prospect in PL 842. Godalen had an Upper Jurassic Rogn Formation objective with potential to contain 90 MMboe and could also have been tied-back to Norne in the event of a discovery. The Rogn Formation was absent, although there were some sands (total 40 m) in the Upper Jurassic Melke Formation (118 m total section). Nova was previously called Skarfjell and was discovered in 2012 by 35/9-7. Its reservoir is the Upper Jurassic Heather Formation. The discovery was appraised over the following year and the PDO was submitted in May 2018 (and received approval four months later). Operator Wintershall Dea intends to recover 77 MMboe from the field over an eight-year period using two 4-slot subsea templates (installed in May 2019) sited one kilometre apart (the northerly template will host three water injectors and the southerly one will have three producers). The templates will be tied back to Gjoa which lies approximately 16 km to the northeast. There is also provision for a third template with four more wells if needed. Gjoa will supply Nova with power (from shore), gas lift and water injection. Drilling of six wells will commence in H1 2020 and the installation of the other facilities will take place in 2019 / 2020. A new topsides module will be installed at Gjoa in May 2020 where processing will take place prior to export via the Troll oil pipeline to Mongstad. Maximum production is expected to be 50,000 boe/d and investment is estimated at NOK 9.9 billion (USD 1.23 billion). The field consists of three segments and the initial development relates solely to Nova Main, with the Southeast and East segments representing future upside potential.

Cairn Energy plc, Solveig Gas Norway AS, Sval Energi AS Sale of Capricorn Norge AS completed

Committed well in Flamenco block, Magallanes Basin, target Tobifera fm, drilled to TD 2,380m in 1Q '20, currently under evaluation. GeoPark (op), partner ENAP.

Leun X-1 nfw Committed well in Flamenco block, Magallanes Basin, target Tobifera fm, drilled to TD 2,380m in 1Q '20, currently under evaluation. GeoPark (op), partner ENAP.

Interra Resources reported on 11 December 2019 that wildcat Kuala Pambuang 1 (KP-1), in the Kuala Pambuang PSC, located in Central Kalimantan, has reached its total depth at approximately 1,149 m (3,771 ft). Borehole cutting analysis from the well has shown live oil at several zones within the primary reservoir targets, which subsequently confirmed by the electrical wireline logs (EWL). DTS was also conducted at the open hole with live oil samples collected. The operator plans to complete the well next by installing casing and run casing perforation test at the potential reservoir. Likewise, further analysis is currently performed on the data and oil samples collected. Wildcat KP-1 was spudded on 7 October 2019. The well has a planned total depth of around 1,100 m. As reported by SKK Migas, Rig Vinct # 02/500 was used for the drilling operation which was estimated to last approximately 26 days. The target for the well, derived from data analysis and geological modeling conducted in 2017, has been identified in the Berai carbonate reefs, built on an extensive carbonate platform as the main reservoir. Secondary objectives are the clastic sedimentary reservoirs (Warukin Formation), situated above and below the carbonate platform. Interra reported exploration costs for the block of approximately USD 4,500 in Q4 2018. Reportedly, the block has unrisked prospective resources of 67 MMbbl for low case, 305 MMbbl for mid case and 1,288 MMbbl for high case as per assessment conducted by ERC Equipoise Pte Ltd in January 2019. The operator likely received technical approval for the well in late 2018, at which time it was in preparation to secure a drilling rig as well as preparing the drilling site. KP-1 is the first of possibly two commitment wells to be drilled in the block. In Q1 2015, the company completed a 304 km of 2D seismic survey in the block, an initial seismic data interpretation was likewise completed in Q3 2015. The results from the initial study was encouraging and the company decided to proceed with the advanced seismic processing technique, with the aim on finding the reservoir fluid content and the rock properties in the area, which also lead to limiting the possible explorations targets. The Kuala Pambuang PSC is operated by PT Mentari Pambuang Internasional (MPI) with 100% interest. Interra holds an effective interest of 67.5% in MPI. The company reported in November 2017 to be looking for a farm-in partner, to help with the funding of its exploration well campaign. However, as of Q1 2019, Interra indicated that the drilling and work programme for the year would be funded internally using available cash resources. Background Information The Kuala Pambuang block was offered in late September 2011 as part of the Second Petroleum Bidding Round 2011 under the direct offer mechanism. Preliminary award/announcement of winning bidder was made on 7 December 2011. The block was officially awarded on 19 December 2011 and firm commitments include G&G studies (USD 1.20 million) and 200 km 2D seismic acquisition (USD 3 million). G&G studies were ongoing during 2012. Goldwater signed a sale and purchase agreement on 3 February 2012 for the acquisition of 49% of the total issued and paid up share capital of PT Mentari Pambuang Internasional (MPI), a limited liability company registered in Indonesia and owned by PT Mentari ABDI Pertiwi. The deal was agreed on a “willing buyer, willing seller basis” and it involved cash consideration of USD 312,000 to MPI and a call option for Goldwater to acquire an additional 18.5% interest from MPI which can exercised anytime during the first three-year exploration phase. The deal was completed in February 2012 and the cash payment was funded from Interra’s existing funds on hand. The main prospective targets in the area, Warukin sandstones and Berai carbonates, had been historically identified by Royal Dutch Shell during pre-World War II exploration activities.

Kuala Pambuang-1 nfw (PT Mentari Pambuang Intern.100%) Commitment well in Kuala Pambuang block, TD=1149m reached, oil noted in several zones and DST'd, 'live oil samples collected'. Plans are to complete by installing casing and testing the potential reservoirs. Targets Warukin, U&L Berai fm's.

Petro Energy Ltd is seeking for a partner to assist in its exploration efforts in exploration licence PPL 388, located in the Papuan Mobile Belt, Papuan Basin. Petro Energy is offering negotiable working interest of around 80% plus the option to operate the licence in return for technical and financial assistance to help fulfil the six-year exploration work programme. The company is currently evaluating other investment support options. Once a partner is secured, Petro Energy could seek to alter the remaining work commitments by removing requirements to drill in the second and third terms. Instead, the company aims to focus on delineating any located leads and prospects. Ahead of the commitment to drill, the work programme includes a full geological review of the licence area to be conducted through know literature and available 2D seismic and gravity data. Petro Energy has commenced this part of the programme. The study will be used to provide a focus area ahead of the commitment to acquire 100 km of new 2D seismic by 29 June 2019. PPL 388, which covers an area of nearly 11,000 sq km, was awarded on 30 June 2015. It is schedule to expire, or be renewed by, 29 June 2021. Laying in a geologically challenging region of the eastern Papuan Mobile Belt, PPL 388 is the only licence in this sub-basin. Senex has also held acreage in the Mobile Belt from 2009 but relinquished the licence in 2015. There is an area of approximately 1,500 sq km in the far west of the licence which crosses into the Papuan Fold Belt, around 65 km north of the Total operated Elk-Antelope field. There are no wells located in PPL 388. The nearest exploration was conducted by Horizon and Kina Petroleum within the Ramu Sub-basin, approximately 15 to 25 km to the north. Raintree 1 and Kwila 1 were the first wells to test the southern Ramu Sub-basin in 2015. The wells were not successful in finding commercial hydrocarbons and thus the licence PPL 337 was relinquished. Petro Energy is offering a farm-in opportunity in its 100% owned and operated exploration licence PPL 388.

Papua New Guinea Petro Energy Ltd is seeking a partner in PPL 388, located in the Papuan Mobile Belt, Papuan Basin. Petro Energy is offering negotiable working interest of around 80% plus the option to operate the licence in return for technical and financial assistance to help fulfil the six-year exploration work programme.

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 April 2020, it is understood that the blocks listed in the table below were available for licensing. Sixty five blocks were available. There were no changes in the list compared to the previous one. Total open acreage amounts to 770,668 sq km of which 681,508 is onshore and 89,160 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-5 11,153 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-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 C-4 9,037 onshore 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 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

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.

PEDL 137 near Gatwick, testing of Portlandian completed, re-perforation of 35m of oil pay (+4.2m) increased productivity by up to 65%, sustainable initial pumped rate expected at 362 b/d of 36 API oil. HH-1z sidetrack or HH-2 appr are tentatively planned. The planning application for long term production is to be submitted to Surrey County Council shortly. Meanwhile a similar test of the underlying Kimmeridge Limestone 3 and KL4 oil pools is planned. Horse Hill Devt Ltd (op)=  Solo, UKOG, Primorous Invest., Alba Min. Res., Tellurian Inc + sundries.

Horse Hill (Horse Hill Developments (65% + Op.) and Tellurian via Magellan Petroleum 35%) in PEDL 137 near Gatwick airport, testing of Portlandian Limestone completed, re-perforation of 35m of oil pay (+4.2m) increased productivity by up to 65% (190 bo/d), sustainable initial pumped rate expected at 362 b/d of 36 API oil. HH-1z sidetrack or HH-2 appr are tentatively planned. The planning application for long term production is to be submitted shortly. Meanwhile a similar test of the underlying Kimmeridge Limestone 3 and KL4 oil pools is planned. The test result “strongly indicates” the vertical well is “commercially viable and robustly economic”. It has also been determined to be commercial even at the lowest observed daily flow rate of 140 bo/d and at oil prices below $60 a barrel.

Further to the announcement of 18 October 2017, AIM-listed Alba Mineral Resources has completed the acquisition of a further 3.1% interest in Horse Hill Developments Limited ('HHDL') from Regency Mines. This brings Alba’s shareholding in HHDL to 18.1%, consolidating the Company’s position as the second largest shareholder in the HHDL consortium, behind only UK Oil & Gas Investments ('UKOG').   HHDL has a 65 per cent participating interest and operatorship of the Horse Hill oil & gas project (licences PEDL 137 and PEDL 246) in the UK Weald Basin.    The total consideration payable is £630,000 including the assignment to Alba of the benefit of all accrued loans in respect of the 3.1% interest.  Of this consideration, £315,000 is being settled by the issue to Regency of 74,733,096 fully paid ordinary Alba shares at a trading 15 day volume weighted average price ('VWAP'), with the balance payable in cash.   Admission to AIM  Application will be made for the 74,733,096 new ordinary Alba shares to be admitted to trading on AIM.  It is expected that Admission will become effective at 8.00 a.m. on 5 December 2017.  The new ordinary shares will be issued credited as fully paid and will rank in full for all dividends and other distributions declared, made or paid after Admission and will otherwise rank on Admission pari passu in all respects with the existing ordinary shares. Original article link Source: Alba Mineral Resources

United Kingdom, not found

1st well in drilling programme in SK-318 off Central Luconia Sarawak, P&A dry (TD n/a) on 3 Jun ’19, Deepwater Nautilus SS. Target Miocene Cycle IV carbs. Next wells planned Jerangau-1 + Bolai-Bawang-1.

Gandarusa 1 (Shell 75%, Petronas 15%, PBE 10%) 1st well in drilling programme in SK-318 off Sarawak, P&A dry (TD n/a). Target Miocene Cycle IV carbs.

On 1 July 2018, BP Exploration & Production was awarded 19 Desoto Canyon blocks: DC 178 (G36265), DC 181 (G36266), DC 182 (G36267), DC 183 (G36268), DC 222 (G36269), DC 223 (G36270), DC 225 (G36271), DC 226 (G36272), DC 227 (G36273), DC 267 (G36274), DC 270 (G36275), DC 271 (G36276), DC 311 (G36277), DC 312 (G36278), DC 314 (G36279), DC 315 (G36280), DC 357 (G36281), DC 358 (G36282) and DC 401 (G36284). These blocks span the Apalachicola, Gulf of Mexico and Louisiana Coastal basins. The blocks were originally offered as part of OCS Lease Sale 250, held in March 2018. Following official award, BP Exploration & Production is now the operator and sole interest-holder (100% WI + Op) in the previously mentioned 19 Desoto Canyon blocks.

On 1 July 2018, BP Exploration & Production was awarded 19 Desoto Canyon blocks: DC 178 (G36265), DC 181 (G36266), DC 182 (G36267), DC 183 (G36268), DC 222 (G36269), DC 223 (G36270), DC 225 (G36271), DC 226 (G36272), DC 227 (G36273), DC 267 (G36274), DC 270 (G36275), DC 271 (G36276), DC 311 (G36277), DC 312 (G36278), DC 314 (G36279), DC 315 (G36280), DC 357 (G36281), DC 358 (G36282) and DC 401 (G36284). These blocks span the Apalachicola, Gulf of Mexico and Louisiana Coastal basins. The blocks were originally offered as part of OCS Lease Sale 250, held in March 2018. Following official award, BP Exploration & Production is now the operator and sole interest-holder (100% WI + Op) in the previously mentioned 19 Desoto Canyon blocks.

Despite CV19, Genel is still hopeful of concluding a farmout for block SL10B / SL13 during 1H '20, ahead of drilling an explo well in 2021. The 18,290-sq km licence lies E. of Hargeysa in the Somali Basin, Somaliland. Genel 100% (partner East Africa Res.'s 25% acquired in Nov '19).

Genel is still hopeful of concluding a farmout for block SL10B / SL13 during 1H '20, ahead of drilling an explo well in 2021. The 18,290-sq km licence lies E. of Hargeysa in the Somali Basin, Somaliland. Genel 100% (partner East Africa Res.'s 25% acquired in Nov '19).

Block C-Champion (F1), Offshore Agreement 1, Baram Delta, drilled 20 Sep – mid-Nov '19, P&A results n/a, Deep Driller 5 JU. Target believed U. Upper Miocene Cycle V clastics.

Pelayak 1 nfw (Brunei Shell Petroleum 100%) in Block C-Champion (F1), Offshore Agreement 1, P&A results n/a, Target believed U. Upper Miocene Cycle V clastics.

Pandion agreed to acquire Aker BP's 30% equity in Norwegian Sea licence PL842 on 31 December 2018. The deal value has not been released and will be effective from 1 January 2019, pending regulatory approval. PL842 covers blocks 6608/10, 11 & 12 (425 sq km) located adjacent to the ENE of the producing Norne oil field. The licence was awarded on 5 February 2016 in APA 2015 and the drill decision has been taken as of 5 November 2018. Partners now have two years to drill a well, currently scheduled for 2019. PL842 current partners are Cairn Energy subsidiary Capricorn Norge AS (40% + Op), Skagen44 AS (30%) and Aker BP ASA (30%).

Pandion agreed to acquire Aker BP's 30% equity in Norwegian Sea licence PL842

On 20 October 2019 Sonatrach was awarded the El Haiad II exploration permit covering 1,073 sq km in the Berkine Basin. The award was confirmed by presidential decree on 8 December 2019. It is understood that this permit replaces the El Haiad permit which was due to expire in December 2018. Sonatrach operates the acreage with a 100% interest. The permit surrounds the El Merk field which is operated by an Eni-Anadarko-Total partnership. The El Haiad block contains no discoveries.

Sonatrach (100%) was awarded the Reggane II (Reggane B.) and El Hadjira II, Garet El Bouib II explo permit in the Hassi Messaoud B.

Further to DEA 14 Jan '20: PEL 155, Penola Trough, Otway Basin, TD 4,300m, 65m gross gas column confirmed in the target Pretty Hill fm, evaluation of a lower sandstone will take place after the casing is run, testing planned. Easternwell rig 106. Otway (op), partner Vintage Egy.

Nangwarry 1 expl. (Otway Energy 50%, op. Vintage O&G 50%) in PEL 155, gas disc. 120m of saturated gas column, within the Upper Pretty Hill Fm. and there is a possible 160m gas column within the mid-Pretty Hill section.

East Abu Sennan block, Abu Gharadiq Basin, W. Desert, compl. oil at TD 2,280m in late Aug ’18. Target Bahariya fm, ST 13 rig. Likewise Abu Sennan East G 1 (EAS-G-1), compl. oil at TD 1,865m on 31 Jul ‘18, same rig. Target Bahariya.

Egypt, Abu Gharadiq (Dev)

On 14 December 2017, the Federal Agency for Subsoil Use held an auction for three blocks in Krasnoyarsk Kray (Eastern Siberia). The highest bids were submitted by Irkutsk Oil Company (INK) and Fund Energy-subsidiary NovoKhim. The winners of the auction will obtain 27-year E&P licenses including a 7-year exploratory stage. Details of the offer are as follows: The Nizhne-Yengidinskiy block covers 3,281 sq km in the north-western part of the Baykit Basin. No wells have been drilled in the block. Hydrocarbon resources (category D1) of the block are estimated at 88 MMbbl of oil and 582 Bcf of gas. The starting price amounted to RUB 15 million (USD 0.25 million). INK offered RUB 16.5 million (USD 0.38 million). The Yerobinskiy block covers 4,146 sq km in the Kamov dome of the Baykit Basin. No wells have been drilled in the block. Hydrocarbon resources (category D1) of the block are estimated at 237 MMbbl of oil and 1,058 Bcf of gas. The starting price amounted to RUB 19 million (USD 0.32 million). NovoKhim offered RUB 47.5 million (USD 0.81 million). The Chunkunskiy block covers 3,241 sq km in the north-eastern part of the Baykit Basin. No wells have been drilled in the block. Hydrocarbon resources (category D1) of the block are estimated at 206 MMbbl of oil and 1,959 Bcf of gas. The starting price amounted to RUB 20 million (USD 0.34 million). INK offered RUB 220 million (USD 3.7 million).  

Russia, not found

Formerly Faroe Petroleum, now DNO, announced on 16 January 2019 that it had been awarded of two new Norwegian licences from the APA round, blocks 1/6 and 1/9 and as a result, the company started the process of equalizing interests in two UK blocks – 30/14a and 30/14b which collectively host the cross-border Edinburgh prospect. DNO then completed the acquisition of block 30/14a from Total which completed in April 2019. DNO was then awarded 30th round licence P2401 which contains block 30/14b. In December 2019 Shell and Spirit Energy completed their farm-in to the UK acreage which now equalises interest between the UK and Norwegian licences. Edinburgh is thought to be one of the largest remaining undrilled structures in the Central North Sea. The prospective reservoirs include the Upper Jurassic Ula age-equivalent (Freshney and Fulmar) and Triassic Skagerrak formations. The prospect sits at the south-eastern end of the prolific Josephine Ridge area. It is a large, tilted Mesozoic fault block and covers an area of 40 sq km. The acreage was previously held by Maersk and acquired by Total via the acquisition of the Danish major. Following completion interests in the blocks is held by Shell U.K. Ltd (40% + operator), DNO North Sea (U.K.) Ltd (45%) and Spirit Energy Resources Limited (15%).

Formerly Faroe Petroleum, now DNO, announced on 16 January 2019 that it had been awarded of two new Norwegian licences from the APA round, blocks 1/6 and 1/9

Norwegians BW Offshore and DBO Energy are reportedly amidst those considering a bid for Petrobras’ Golfinho mature field cluster offshore Espirito Santo Basin, 15,000 bo/d + 750,000 cumg. Binding offers for the cluster are required early September. It is recalled Petrobras is offering its entire 100% in the Golfinho + Camarupim deepwater clusters. The package includes the Camarupim, Camarupim Norte, Canapu, Golfinho deepwater E&P blocks, and the ES-M-525 block (BM-ES-023 contract, shared with PTTEP 20% + Inpex 15%).

Brazil (Espirito Santo B.) ES-M-525 op. by PETROBRAS (65%), PTTEP (20%), INPEX (15%), Norwegians BW Offshore and DBO Energy are reportedly amidst those considering a bid for Petrobras’ Golfinho mature field cluster offshore Espirito Santo Basin

ATP 1189-P (Total 66a), Cooper-Eromanga, Lane-1 drilled 11-21 Oct ’18, TD 2,791m, susp gas. Likewise follow-up Lois-1, drilled 24 Oct – 2 Nov ’18, TD 2,809m. Santos (op), partner Beach.

Lane 1 (Santos 62,5% Op, Vamgas 7,5%, Beach 30%) in ATP 1189-P block, gas discovery.

PL 857, E. Barents, WD 304m, reportedly hc discovery, nature + size yet n/a, well under completion, West Hercules SS. Equinor (op), partners Aker BP, Lundin + Petoro.

7132/02-02 (Gjøkåsen Deep) (Equinor 40% op, Aker BP 20%, Lundin 20%, Petoro 20%) in PL 857, reportedly hc discovery, nature + size yet n/a, well under completion, WD=304m.

Corallian Energy Limited is seeking farm-in partners to drill an appraisal well on the 1977 Curlew-A oil discovery made with well 29/7-1. The P2396 licence covers block 29/7b. Corallian is looking to divest up to 60% interest in the licence and in October 2018 announced that it had agreed to farm down 10% interest to Talon Petroleum Limited. As of July 2020, the remaining interest was still available. The appraisal well is planned to be drilled with a jack-up rig in water depths of 93 m to a TD at 2,700 m and well costs are in the region of GBP 9.7 million. The company has 3D seismic over the discovery. The drilling is planned for 2021, subject to farm-in. The Curlew-A discovery was made by Shell and is a 4-way dip closed oil bearing structure. The discovery well encountered net oil sands (Cromarty and Odin Members of the Sele and Balder Fm) of 10.5 m and recovered multiple oil samples of 36° API. The licence was previously held by Shell until it relinquished the acreage in 2016 prior to Corallian picking up the acreage in the 30th Licensing Round and is currently in its first phase. In October 2018 Schlumberger completed a Competent Person’s Report (CPR) stating that 3C combined Contingent Resources of the Cromarty and Odin reservoirs were 68 MMbo and 79 Bcf (82 MMboe recoverable), 2C Contingent Resources are 39 MMboe. There is upside in a secondary objective of the Forties Sandstone unit which wasn’t encountered during the discovery well but may be developed across the south-western flank. Resources of 22 MMbo have been estimated for the Forties sands and 8 MMboe in the chalk. Following completion of the deal in May 2019 with Talon Petroleum, interest in the licence is held by Corallian Energy Limited (90% + operator) and Talon Petroleum Limited (10%). For further information, please contact: Andrew Hindle Commercial Director +44 7775712817 [email protected]

United Kingdom (Central Graben Province), P2396 operated by CORALLIAN (90%), TALON (10%), Corallian Energy Limited is seeking farm-in partners to drill an appraisal well on the 1977 Curlew-A oil discovery made with well 29/7-1. The P2396 licence covers block 29/7b. Corallian is looking to divest up to 60% interest in the licence

ExxonMobil has increased its holdings in Brazil’s pre-salt basins after winning eight additional exploration blocks during Brazil’s 15th bid round. The blocks awarded add about 640,000 net acres to the ExxonMobil portfolio. Six of the eight newly awarded blocks will be operated by ExxonMobil.The additional blocks expand the company’s total position in the country to more than two million net acres, making it one of the largest acreage holders among international companies in Brazil.'These recent bid round results add highly prospective acreage to ExxonMobil’s deepwater portfolio that we will explore and develop with our partners,' said Steve Greenlee, president of ExxonMobil Exploration Company. 'This acreage in Brazil’s pre-salt play will provide excellent opportunities to deploy our deepwater expertise. We will continue working with the government to develop these world-class resources for the benefit of Brazilians for many years to come.'ExxonMobil and its partners jointly won a total of eight blocks, which include:ExxonMobil plans to obtain 3-D seismic coverage in 2018 on more than 4,000 square kilometers, including all of the ExxonMobil-operated exploration blocks announced in 2017, subject to permitting approvals.The company now has interests in 24 blocks offshore Brazil. ExxonMobil has worked in Brazil for more than 100 years.Original article linkSourceL ExxonMobil

ExxonMobil has increased its holdings in Brazil’s pre-salt basins after winning eight additional exploration blocks during Brazil’s 15th bid round. The blocks awarded add about 640,000 net acres to the ExxonMobil portfolio.

Boquerón block, Chaco Basin, junked on tech. reasons at 2,780m in Mar ‘18.

Paraguay, not found

Total has signed two new 40-year concession agreements with the Supreme Petroleum Council of the Emirate of Abu Dhabi (United Arab Emirates) and the Abu Dhabi National Oil Company (ADNOC). In the frame of these agreements, Total is granted a 20% participating interest in the new Umm Shaif & Nasr concession and 5% in the Lower Zakum concession, effective March 9th, 2018, for a total participation fee of 1.45 billion dollars, which represents an access cost of around 1 dollar per barrel of reserves. These interests bring to Total a production of 80,000 barrels of oil per day in 2018.   Located about 135 and 65 kms off the coast respectively, Umm Shaif and Lower Zakum are two of the major fields offshore and counting for around 20% of Abu Dhabi production. In addition to the huge oil reserves and the potential to grow oil production beyond 450,000 barrels per day (including Nasr – the present production being at around 300,000 barrels per day), Umm Shaif also contains a giant gas-cap, which is to be developed in the scope of the concession with a gas production target of 500 mmscfd. ADNOC Offshore (100% owned by ADNOC) will be the operator of all concessions offshore Abu Dhabi, to which Total, as a partner in the concessions, will bring its expertise by providing personnel and carrying out studies.    'These agreements represent another major milestone in our long-standing partnership with Abu Dhabi and ADNOC that dates back to 1939. Following the signing of the ADNOC Onshore concession in 2015, they confirm our commitment to ADNOC for the next 40 years,' said Patrick Pouyanné, Chairman and CEO of Total. 'With a 25% overall participating interest in two concessions, we are honored that ADNOC chose Total as its main partner on these offshore concessions that contain giant reserves with low technical costs and offer significant growth potential. In particular, we are delighted with the trust that ADNOC demonstrated by granting us a 20% participating interest in the Umm Shaif & Nasr concession, and therefore to be the leading partner on this asset. We intend to bring all of our competencies in order to make the most of the upside coming from the gas reserves, while we develop the oil production in the most effective way.'   'For nearly 80 years, Total has partnered with Abu Dhabi in the development of our oil and gas resources and has closely collaborated with ADNOC across various stages of our value chain,' stated Dr Sultan Ahmed Al Jaber, ADNOC Chief Executive Officer. 'Today’s announcement marks an important step to further strengthen our mutually beneficial and value-adding partnership with one of the world’s largest integrated upstream and downstream companies.'   In addition, as part of this partnership, Total has also extended its concession with ADNOC in the offshore Abu Al Bu Koosh field, operated by Total with a 100% interest, for three more years. This field produces approx. 10,000 barrels per day. Original article link Source: Total

otal has signed two new 40-year concession agreements with Abu Dhabi (United Arab Emirates) and ADNOC for 1.45 billion dollars. In the frame of these agreements, Total is granted a 20% participating interest in the new Umm Shaif & Nasr concession and 5% in the Lower Zakum concession.

Late 2017 well in S. part of VIII Urziceni Est block, Focsani Trough (Carpathian Basin), E. Romania, P&A non commercial gas at TD 1,725m. Hunt (op), OMV Petrom partner.

Traian N.-1, Late 2017 well, op. by Hunt (50%, Petrom 50%) in S. part of VIII Urziceni Est block, Focsani Trough, E. Romania, P&A non commercial gas at TD=1725m.

On 29 March 2018, Wintershall with 100% working interest was granted a preliminary award for the CE-M-601 block in the offshore Ceara Basin through the ANP Round 15. For the CE-M-601 block Wintershall offered a bonus of USD 2.72 million and 136 work units.   There were no other bids for the block.  

Wintershall with 100% working interest was granted a preliminary award for the CE-M-601 block in the offshore Ceara Basin through the ANP Round 15.

PetroChina achieved commercial gas flow in a deep shale gas well in the Sichuan Basin on 11 March 2019. Zu 203, a shale gas appraisal well located in Dazu-Yibin block, tested 7.5 MMcf/d of gas in the Longmaxi Formation. The well has a TD of 4,175 m (TVD). In November 2017 PetroChina made a breakthrough in Zu 201-H1 in the block, tested 3.7 MMcf/d of gas from the Longmaxi Formation below 4,000 m. In 2018, PetroChina achieved commercial gas flow in second well in the block, Zu 202-H1 tested 16 MMcf/d of gas in the Longmaxi Formation below 3,900 m. Except Dazu block, PetroChina has three shale gas field production blocks, Changning, Weiyuan and Zhaotong blocks, and several exploration blocks in the Sichuan Basin. Overall the company has approved 11 Tcf of gas in place and has completed total 419 shale gas wells, of which 337 wells on stream by end 2018.   In 2018 PetroChina produced 4.2 Bcm of shale gas from three fields in the Sichuan Basin. The company has target to produce 12 Bcm by 2020 and 24 Bcm by 2025 in the Sichuan Basin. Background Information China produced over 10.2 Bcm of shale gas in 2018, increase 14% from 9 Bcm in 2017. The gas output mainly comes from existing fields in the Sichuan Basin, operated by Sinopec and PetroChina respectively. PetroChina PetroChina produced 4.27 Bcm of shale gas in 2018, increased 40% from 3 Bcm in 2017. The gas is all produced in the Sichuan Basin from existing fields Weiyuan, Changing and Zhaotong. Several new discoveries have been made around these three fields area for the last two years, such as Lu 202, Zi 201, Zu 201 and Huang 202. PetroChina plans to produce 8 Bcm in 2019 and 12 Bcm by 2020, incremental will come from existing fields expansion and these new discoveries. Sinopec Sinopec produced 6 Bcm of shale gas from the Jiaoshibas field in the Sichuan Basin, same as in 2017. In 2018 Sinopec put additional 81 wells on stream in the field and added 5.4 Bcm of gas reserves. Jiaoshiba field has produced cumulative of 21.5 Bcm of shale gas by 2018 since it produced gas in 2012. Apart from the Jiaoshiba field, Sinopec also has achieved several successes in shale gas exploration drilling in other blocks in the Sichuan Basin, such as Yongchuan, Weiyuan-Rongxian and Dingshan area, in particularly Weiyuan-Rongxian block has been approved 4.4 Tcf of gas in place in 2018. China has approved cumulative of over 35 Tcf by April 2018. Currently all shale gas fields are found in the Sichuan Basin, such as Jiaoshiba, Weiyuan, Changning, Zhaotong and Weirong.

Deep shale gas well in Dazu-Yibin block, Sichuan Basin, TD 4,175m, early March tested 7.5 MMcfg/d from the Longmaxi Shale.

Cairn is offering equity in the SNE o&g field in the Sangomar Offshore Deep block, deepwater MSGBC Basin, data room open for interested parties, bids due before end June. Earlier noises about Cairn and BP discussing have been denied. Capricorn (op), partners Woodside, FAR + Petrosen.

Cairn is offering equity in the SNE o&g field in the Sangomar Offshore Deep block, deepwater MSGBC Basin,

On 21 November 2017, ONGC Videsh Ltd (OVL) announced that it acquired 15% working interest in the Cooper Block (Block 2012A) from Tullow Oil plc (Tullow). OVL is a wholly owned subsidiary of Oil and Natural Gas Corporation Limited (ONGC), the National Oil Company of India. Therefore, Tullow’s stake in Block 2012A is now 10%, with Eco (Atlantic) Oil and Gas Ltd (ECO) still operating the permit with a 32.5% interest. Remaining partners are AziNam (32.5%) and NAMCOR (10%). OVL already completed a farm out deal with Tullow in Namibia in early October 2017, acquiring 30% stake in PEL 037 (Blocks 2012B, 2112A and 2113B). To date (late 2017), operator ECO intends to explore the Osprey lead, for which Tullow's exploration team played a lead role so far to oversee processing and conduct the initial interpretation for the block partners. The lead is in water roughly 500 m deep and is covered by both 2D and 3D seismic data. Block 2012A is located within the Walvis Sub-basin and covers 5,800 sq km in water ranging in depths from 20 to 500 m. A number of targets have been identified. They include basal Tertiary clastics and turbidites (2,000 to 2,300 m), Upper Cretaceous clastics and turbidites (2,400 to 2,700 m), and Lower Cretaceous carbonates (3,300 to 3,600 m).  

Namibia (Southwest African Coastal B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Block 2012A op. by ECO ATL (32.5%, AZINAM 32.5%, TULLOW 25.0%, NAMCOR 10.0%) to be check.

PetroChina – Sichuan made a breakthrough in the Sichuan Basin, Pingtan 1, a NFW, tested 23.6 MMcf/d of gas from the Permian Qixia Formation on 12 May 2020. Pingtan 1 is located in the southwest of basin, drilled on Pingluoba structure in the south of the Longmenshan fault belt. The well was spudded on 11 December 2017, with objective in the Qixia Formation, and reached a TD of 6,866 m on 20 January 2020. During drilling the core data indicated good reservoir quality. Pingtan 1 is the first well achieved commercial gas flow in the Qixia Formation in this area. Around Pingtan 1, several gas fields have been found, such as Pingluoba and Baimamiao, with reservoir in the Jurassic and Triassic, a few wells hit the Qixia Formation but reservoir is wet. The Marine Qixia Carbonate reservoir is represented in the basin. Although it is present in 18 fields, but no major discovery has been found yet. For the past few years, PetroChina made gas discovery in the Qixia Formation in northeast part of the basin, such as Longtan 1, Shuangtan 1 and Shuangtan 3. In 2017 PetroChina tested high gas rate in Longtan 1 which flowed 37 MMcf/d of gas from the Permian Qixia Formation with H2S content of 8.93 g/m3. In 2016 PetroChina made a breakthrough in in Shuangtan 3, the well not only tested gas from the Permian Qixia Formation, but first time achieved commercial gas flow from the Devonian Guanwushan Formation, 4 MMcf/d of gas. In 2014 PetroChina made Shuangtan 1 discovery, the well tested 30 MMcf/d of gas from the Permian Qixia Formation and 44.7 MMcf/d of gas from Maokou formations.

Pingtan-1 nfw. (PetroChina 100%) Pingluoba structure, Yanting-Daying block, S. Longmenshan fault belt in SW Sichuan Basin, drilled 11 Dec '17 – 20 Jan '20, TD 6866m, in May tested 23-6 MMcfg/d from the target Permian Qixia fm. This is the 1st commercial gas flow from the Qixia here.

Petronas has agreed to farmin to offshore blocks A2 + A5 from FAR ahead of drilling the Samo prospect in late 2018. Petronas will get 40%, FAR retaining 40% and operatorship, although Petronas has the right to take over as leader for development. Petronas will fund 80% of Samo well costs up to USD 45 MM, non-well costs up to USD 1.5 MM, and will reimburse FAR USD 13.5 MM in back-costs and cash. The deal is subject to govt approval. Partner otherwise GNPC. Block A2 covers 1,298 sq km,  A5  1,378 sq km:

Petronas has agreed to farmin 40% interest to offshore blocks A2 + A5 from FAR (40% op, GNPC 20%).

Statoil has farmed-out equity to Anadarko (now 41.66%) and Venari Offshore (16.67%) in the Monument subsalt Paleogene prospect in WD 2,042m. The BOEM has yet to issue any drilling permits for the planned Monument wells in Walker Ridge blocks 271 (OCS G35080) and 272 (OCS lease G35081), although the initial Exploration Plan was approved in Sep ’15. Background from GEPS.

United States, not found

Rharb Centre block, C-E Morocco, TMD 1,210m, gas find in the U. & L. Guebbas fm, testing planned Feb '20, est. 1.3-1.9 Bcf recoverable. Rig to BMK-1 north of OYF-2. SDX (op), partner Onhym.

Ouled Youssef-2 (OYF) expl. (SDX 75%op, Onhym 25%) in Gharb Centre block, C-E Morocco, TMD=1210m, gas find in the Miocene U. & L. Guebbas Fm, testing planned Feb '20, est. 1,3-1,9 Bcf recoverable. The discovery had de-risked a further 500MM to 1Bcf of prospective resources in the western compartment of the Lower Guebbas target.

A total of 103 tracts were preliminarily awarded on 6 Dec ’17 under the North Slope Areawide NS2017W lease sale, total 727 sq km.  Repsol bagged the highest number of tracts (45, over 271 sq km) on trend and east of the Nanushuk oil discovery. Armstrong Energy followed with 24 tracts, Other participants include ConocoPhillips, Accumulate Energy, Andrew Bachner - Keith Forsgren, Caracol Petr. - TP North Slope Devt, and Douglas Barr - Daniel Donkel. Newcomers are the oddly-named Mayhem Energy, Three Mountain Oil, and Regenerate Alaska. Block details from GEPS.

United States, not found

Australian Gasfields Ltd (AGF) and Beach Energy Ltd entered into an agreement in July 2017 for AGF to acquire complete interest in two Cooper-Eromanga permits: production licence PL 184 (Thylungra field) and exploration permit ATP 932-P. The deal, which is expected to be completed by end-January 2018, will see AGF increase its interest to 100% in both permits. Currently, AGF holds 19.6% in PL 184 and has zero interest in ATP 932-P. Since early 2016, Beach has undertaken geological and geophysical studies in PL 184, in which AGF has contributed around AUD 770,000. The studies have been focused on the determining commercial opportunities for the Thylungra discovery.  PL 184 was awarded on 13 September 2001 and is due to expire on 12 September 2021. Both Beach and AGF have participated in the permit since October 2001. Beach Energy currently holds its interest through Beach Energy Ltd (74.2% + operator) and subsidiary company Mawson Petroleum Pty Ltd (6.2%). ATP 932-P covers at area of 1,541 sq km and was awarded on 15 February 2013. Beach had been offering a farm-in opportunity in the block after a deal with Real Energy to acquire 50% interest failed to complete in 2012. ATP 932-P is currently 100% owned by Beach Energy, through its subsidiary companies: Drillsearch Energy Pty Ltd (50% + operator) and Circumpacific Energy (Australia) Pty Ltd.  

Australia (Eromanga B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: ATP 932-P(b) op. by ENERGY WD (100.0%) to be check.ATP 932-P(c) op. by ENERGY WD (100.0%) to be check.ATP 932-P(a) op. by ENERGY WD (100.0%) to be check.

In early 2020, the Ethiopian Ministry of Mines, Petroleum & Natural Gas offered 22 open blocks in the country (see attached map): Ethiopia blocks on offer Block Name Block Sqkm Main Political Province Basin Names Gambela 157075.86 Binshangul Gumuz Amhara Massif~Abbay (Blue Nile) Basin North West 82516.38 Amara Mekele Basin~Amhara Massif~Northeast African Fold Belt Afar Area 62997.88 Afar Afar Basin~Red Sea Basin~Mekele Basin~Ogaden Sub-basin (Somali Basin)~Northeast African Fold Belt Rift Valley Block 43054.83 Ye Debub Biheroch Afar Basin~Amhara Massif Omo 30598.73 Ye Debub Biheroch Amhara Massif~South Omo Graben (EARS, East Branch)~Chew Bahir Graben (EARS, East Branch) Metema 29827.79 Binshangul Gumuz Mekele Basin~Northeast African Fold Belt~Amhara Massif Afar 24589.42 Afar Afar Basin~Mekele Basin~Red Sea Basin~Northeast African Fold Belt Block 05 18299.34 Oromiya Ogaden Sub-basin (Somali Basin) Block 07 12254.06 Sumale Ogaden Sub-basin (Somali Basin)~Mandera-Lugh Sub-basin (Somali Basin) Block 02 12232.2 Oromiya Ogaden Sub-basin (Somali Basin)~Mandera-Lugh Sub-basin (Somali Basin) Block 06 12232.2 Oromiya Ogaden Sub-basin (Somali Basin) Block 18 12232.19 Sumale Ogaden Sub-basin (Somali Basin) Block 01 12206.7 Oromiya Ogaden Sub-basin (Somali Basin) Block AB8 12135.44 Amara Abbay (Blue Nile) Basin~Amhara Massif Block AB9 12128.45 Amara Abbay (Blue Nile) Basin~Amhara Massif Block AB5 12108.5 Amara Amhara Massif~Abbay (Blue Nile) Basin Block AB6 12108.5 Amara Amhara Massif~Abbay (Blue Nile) Basin Block AB3 12068.51 Amara Amhara Massif Block AB2 12068.5 Amara Amhara Massif Block 19 6467.74 Sumale Ogaden Sub-basin (Somali Basin) Block 21 6094.66 Sumale Mudugh Sub-basin (Somali Basin) ~Ogaden Sub-basin (Somali Basin) Area 4 3679.4 Ye Debub Biheroch Amhara Massif~East African Rift System, Eastern Branch Source: IHS Markit 2020 © 2019 IHS Markit   Another five blocks were under discussions in Ethiopia in late 2019. The Government confirmed in late year that a Production Sharing Agreement (PSA) concerning one or more of these blocks was pending to be approved. These blocks could be Block 10 and Block 14 to be awarded to the British Delonex. Blocks Under Discussion in Ethiopia (late 2019) Basin Name Block Name Block Sqkm Existing drilling Existing discoveries Existing Exploratory Surveys Political Province Amhara Massif Block AB1 9,900 no no no Amara Amhara Massif Block AB4 9,900 no no 2011 (seismic) Amara Amhara Massif Block AB7 9,900 no no no Amara Ogaden Sub-basin (Somali Basin) Block 10 - possibly DELONEX 12,207 no no 1989 (2D) Sumale Ogaden Sub-basin (Somali Basin) Block 14 - possibly DELONEX 12,207 no no 1962 (2D), 1963 (Gravity/Magnetic). 1992 (2D) Sumale Source: IHS Markit, 2020               Until the update of the existing Petroleum law is approved by the Government, contracts are awarded in the form of Model PSA of 1994 between the government of Ethiopia, represented by the Minister of Mines and Energy, and a contractor. Contracts have an initial exploration term of four years and an optional two-year term, with two possible further exploration periods of two years (4+2+2). The development and production period is of 25 years. Minimum exploration and expenditure obligations are negotiable as well as signature and production bonuses. The income tax is 30% but will be reduced to 25% according to the petroleum draft being prepared by the Ministry. For further details, interested companies are invited to contact: Mr. Ketsela Tadesse Director – Petroleum Licencing & Administrative Dictatorate Ministry of Mines, Petroleum & Natural Gas P.O.Box 751 Addis Ababa, Ethiopia Phone: + 251 11 646 12 09 Fax: + 251 11 646 34 39 [email protected]

Ethiopia (Afar B.) Afar (Gewane-El Wiha) op. by GPB GL RS (100%)

Lundin has agreed a deal with Wintershall Dea to acquire a 10% interest in PL 894, subject to government approval. The licence contains the 2018 Balderbra discovery which has just been appraised (February 2020). However, the results of the appraisal were disappointing, with reserves being significantly downgraded, and Lundin states that development is no longer considered to be economically viable. Balderbra discovery well 6604/5-1 targeted a robust structural closure (Maastrichtian sand drape over older tilted fault blocks) with an amplitude anomaly between the Gullris (6604/2-1) and Gro (6603/12-1) wells. A gross gas column of 190 m across three separate sandstones totalling 90 m was encountered in the Springar Formation. The upper sandstone unit is thin with variable permeability, the middle sand is thicker (56 m gross) and laminated with 21% porosity, and the lower sand has a gross thickness of 129 m and 15% porosity. The three units are not in pressure communication and no GWC was encountered. A development as a tie-back to Aasta Hansteen was initially being considered. Appraisal well 6604/5-2 S targeted three Upper Cretaceous Springar Formation sandstones, with the first mapped at 3,633 m (3,389 m TVD), and was also designed to locate the GWC. However, although a total of 210 m of Springar Formation was present in the well (with 140 m of this being poor quality sandstone) there were only traces of gas and the well is classed as a dry hole. Pressure communication with the discovery was also not established and recoverable reserves were reduced from 247-671 Bcfg plus 6-19 MMbc (at discovery) to 106-283 Bcfg plus 1-6 MMbc. Upon completion of the deal, interest in PL 894 will be divided between Wintershall Dea Norge AS (30% + operator), Equinor Energy AS (40%), Petoro AS (20%) and Lundin Norway AS (10%).

Lundin is to acquire a 10% stake from Wintershall Dea in PL 894 (Voring) and 5% interests in PL 533 and PL 533 B (Barents Sea).

OK is seeking an extra partner in P2104 /block 48/18c with a view to appraise + develop the Bedevere gas discovery with planned 48/18c-16. Currently OKE (op), Blue Dragon Egy 50%, the latter so far funding the well but further equity is still available. Contact: [email protected].

OK is seeking an extra partner in P2104 /block 48/18c with a view to appraise + develop the Bedevere gas discovery with planned 48/18c-16. Currently OKE (op), Blue Dragon Egy 50%, the latter so far funding the well but further equity is still available.

Tulip secured explo rights to blocks Q8, Q10b + Q11 effective 29 Sep ’18, pursuant to an application gazetted in 2015. Q8 contains the abandoned Q8-A and Q8-B gasfields. Tulip (op), partner EBN.

Netherlands, not found

On 8 August 2019, Petrobras issued a press release indicating it signed the sales agreement with SPE 3R Petroleum SA for the Macau package of seven fields in the onshore Potiguar Basin.  The seven production concessions include the Aratum, Lagoa Aroeira, Macau, Porto Carao, Salina Cristal, Sanhacu, and Serra.  The terms of the deal were reported to be a total consideration of USD 191.1 million to be paid in two installments.  The first installment of USD 48 million paid on signing date and the remainder of USD 143.1 million to be signed after formal approvals and transaction closing. On 22 September 2017, Petrobras issued a press release indicating that it is offering for potential sale and assignment 19 production concessions in five separate packages or poles onshore in the Potiguar and Sergipe-Alagoas basins.

Petrobras issued a press release indicating it signed the sales agreement with SPE 3R Petroleum SA for the Macau package of seven fields in the onshore, for US$191 MM. The seven production concessions include the Aratum, Lagoa Aroeira, Macau, Porto Carao, Salina Cristal, Sanhacu, and Serra.

On 21 March 2018, SDX Energy announced that the SAH-2 development well in the Sebou permit yielded an average rate of 12.9 MMscf/d of gas through a 40/64” choke (maximum flow recorded was 13.5 MMscf/d of gas). The well will be shut in for several days to allow pressure build up before connecting the well to the existing infrastructure.   On 9 March 2018, SDX Energy announced that SAH-2 development well encountered 5.2 m of net gas pay in two zones in the Guebbas and Hoot formations with an average porosity of 33%. SAH-2 was spudded on 27 February 2018 and drilled to a TD of 1,304 m. it is expected to be tested and connected to existing infrastructure. The SAH-2 is part of SDX Energy’s nine-well drilling campaign targeting an increase in its local gas sales volumes in Morocco by up to 50% and an increase in its reserves by more than 100%.    

Morocco, Sebou

The authorities cleared on 14 Dec ’17 the award of 1st round Levant offshore blocks 4 (1,911 sq km) and 9 (1,742 sq km) to a group comprising Total, Eni and Novatek (release). Commitments will call for 1 well in each of the 1st + 2nd explo terms.

Lebanon, not found

EP 21-5-1 completed in early August 2020 without result reported. CNOOC – Shenzhen spudded a new-field wildcat EP 21-5-1 in the Pearl River Mouth Basin, South China Sea, on 20 July 2020. The well is situated at a water depth of approximately 90 m area located in the Enping Sag and near EP 20-4 and EP 20-5 discoveries, with targets in the Mio-Oligocene clastic play. “Nanhai 2” S/S is used for the drilling operation. 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 completed with success. CNOOC announced in 2019 mid-year review that Enping 20-5-1 encountered oil pay zones about 93 m thick, and that the discovery was expected to become a "mid-sized" oil field, defined as having recoverable resources of 2.5 MMcm to In March 2020 CNOOC announced that the successful appraisal of Enping 20-5 and Enping 20-4 confirmed a "reserves base of mid-to-large oil fields". In addition, two wells drilled in 2019 around the EP 20-4/5 discovery, EP 21-2-1 and EP 21-3-1, without result reported. Background Information In the past few years, about 10 discoveries have been made in the Enping Sag, the most significant ones are EP 24-2, EP 18-1 and EP 23-1 fields cluster, with reservoirs from Miocene to Oligocene sands. To date, five fields have been brought onstream successively since 2014. The latest onstream field in the area is EP 23-1 fields cluster (together with EP 23-2 and EP 23-7), which started commercial production in November 2016 with initial flowing 5,597 bo/d from three wells. The cluster together with Enping 18-1 (on stream Sep 2016) were tied-into the Enping 24-2 facilities, the later on stream in 2014. In 2018, CNOOC completed EP 15-2-1 and EP 10-2-1, in the Enping Sag with both penetrating oil-bearing zones. The EP 10-2-1 and EP 15-2-1 discoveries, together with existing EP 15-1 discovery, are expected to be a medium size cluster/joint development. EP 15-1 discovery was made in 2016 in the Enping Sag. The Miocene to Oligocene reservoirs are the most significant reservoirs in the PRMB, mainly predominated by sandstones and carbonates of the Lower Miocene Zhujiang Formation, sandstones of the Middle Miocene Hanjiang Formation, and sandstones of the Upper Oligocene Zhuhai Formation. These sandstones were mainly deposited as massive fluvial sands and as deltaic channel and tidal bars with good reservoir properties. In addition, CNOOC has completed a few wells in the Enping Sag for the last five years. EP 9-4-1 was completed in early February 2020 with result unreported. In 2019 quite a few wells drilled with result unreported, such as EP 10-4-1, EP 20-1-1, EP 20-2-1, EP 20-7-1 and EP 24-3-1d. In 2018 CNOOC completed EP 12-2-1d with result unreported. In 2017 CNOOC completed EP 23-11-1d and EP 18-6-1 with result unreported. In 2016 CNOOC drilled EP 11-4-1 and EP 16-1-1 with result unreported.

(Pearl River Mouth B.) EP 21-5-1 nfw, located in Yangjiang 18, operated by CNOOC LTD (100%), completed in early August 2020 without result reported.

On 8 February 2019 Cluff Natural Resources announced it had entered into a binding, conditional farm out agreement and a three-month exclusive option with Shell in relation to licences P2252 (blocks 41/5a, 41/10a and 42/1a) and P2437 (block 48/8b) respectively. Shell will acquire 70% interest and operatorship in licence P2252 which contains the Lytham, Fairhaven and Pensacola prospects. In return, Shell will pay all the costs of acquiring 400 sq km of new broadband 3D seismic data over the Pensacola prospect in Summer 2019. The work programme also involves the processing of new and existing seismic data and sub-surface studies to support a well investment decision before the end of 2020. All costs in relation to the well investment decision will be split in proportion to each companies interest in P2252. Cluff also agreed to grant Shell the option to acquire 50% interest in licence P2437 which contains the Selene prospect by 30 April 2019. On 30 April 2019 Cluff announced that Shell has exercised the option taking a 50% interest in the licence. Shell will make a payment of USD 600,000 which is comprised of an initial payment and further payment upon completion to Cluff. Shell will also pay 75% of the costs up to USD 25 million to drill an exploration well and well test on P2437. On completion of the deals Shell has indicated its intention to drill an exploration well on the Selene prospect as soon as possible. Completion of the deals is subject to regulatory approvals. The Lytham and Fairhaven appraisal opportunity is interpreted as a large 4-way dip closed N-S orientated anticlinal structure compartmentalised by E-W oriented faults. The reservoir objective consists of a fractured Z2 Hauptdolomite platform carbonate. The reservoir has produced in Dutch, German and Polish regions. The Stassfurt Halite provides a 300 m seal and underlying early Carboniferous coals and organic shales could source light liquid hydrocarbons and gas. The prospect holds P50 prospective resources of 168 Bcf with a CoS of 46%. Cluff propose a horizontal appraisal well perpendicular to the fracture network to test the Hauptdolomite reservoir. Pensacola is a large patch reef structure with a fringing reef and lagoon architecture mapped on a mixed 2D and 3D seismic dataset. The fringing reef is interpreted as being a higher quality carbonate reservoir than the reef core. The fringing reef and lagoon fill are estimated to hold P50 prospective resources of 270 Bcf and 154 Bcf respectively. Cluff would be looking to acquire 3D seismic across the entire reef prior to drilling. Seismic acquisition and processing was budgeted at GBP 3.5 million with well costs in the region of GBP 8 million to 10 million. The Selene prospect is estimated to contain mean GIIP of 509 Bcf (90 MMboe) and is located on the Northern limb of the Sole Pit Basin inversion axis and is defined to have a NW-SE elongated closure. Selene is located in the Rotliegend aged Lower Leman Sandstone play fairway. Selene, a four-way dip closed structure, is thought to hold P50 Gross Prospective Resources of 291 Bcf and is analogous with a number of nearby fields including Shell’s operated Barque field. A Chance of Success for Selene has been attributed at 39%. It is located approximately 20 km from the Barque gas infrastructure which feeds the Bacton gas processing plant. Exploration well 41/10-1 was drilled in block 41/10a in 1995 where gas shows were interpreted by Marathon from porous dolomites within the Zechstein evaporate sequence. Walter Oil and Gas drilled well 41/5-1 in block 41/5a during 2004 and penetrated the Hauptdolomite platform. There was the presence of gas in Zechstein but due to technical issues the well failed to flow gas. Image logs demonstrated persistent and long open fractures which resulted in significant mud losses. Lundin drilled the Lytham prospect with well 041/10-02 in 2007, however the well was sidetracked (041/10-2Z), having reached a TD of 800 m on 27 July 2007. The Zechstein Hauptdolomite was determined as dry and having poor reservoir quality with 7% porosity and 60% gas saturation. The well was plugged and abandoned without being tested. Two exploration wells have been drilled in 28/8b. Well 48/8a-1 discovered Sloop in 1989 by Conoco and is defined as a Lower Leman gas bearing sand in a faulted structure. Amerada Hess drilled 48/8b-2 on 13 January 1989 reaching a TD of 3,795 m with two cores being taken in the Rotliegend Leman Sandstone and a core in the Carbonifeous. Both formations were either tight or water wet and the well was plugged and abandoned as a dry hole on 7 April 1989.   Following completion of the deal interest in P2252 will be held by Shell U.K. Ltd (70% + operator) and Cluff Natural Resources Plc (30%). Interest in P2437 will be held by Cluff Natural Resources Plc (50% + operator) and Shell U.K. Ltd (50%).

Cluff Natural Resources (->0%) has announced that Shell (->100%) has exercised its exclusive option to farm in to Licence P2437 (Block 48/8b) contains the 291 BCF Selene Prospect.

Helios was awarded sole 6-yr rights to the Monzón + Barbastro blocks by the Aragon autonomous authority on 9 Mar '20. Monzón (ex-Binefar + part-Barbastro) covers 512 sq km and Barbastro (ex-part Abiego, Peraltilla + Barbastro) 383 sq km in the Ebro Basin, both effective 28 May '20. Plans include G&G studies, reinterpretation of vintage well + seismic data and acquisition of min. 150km of new 2D seismic in yr 3. No fracking allowed.

Helios was awarded sole 6-yr rights to the Monzón + Barbastro blocks

El Dorado Oeste field area / block, Foothill Belt of Chaco Basin, drilled Apr – Jul ’19, TD 4,360m, susp. after tests during Sep '19, results awaited. Targets Chaco Group + Iquiri fm.

Colorado X10D (YPFB 100%) shallower pool wildcat (SPW) well in El Dorado Oeste block, P&A with unreported result.

On 2 May 2019, Murphy reported some details regarding its suspended oil and gas discovery Cholula 1EXP directional new-field wildcat (NFW) in the CNH-R01-L04-A5.CS/2016 contract block.   The operator reported that it logged 56 m of net pay in the Upper Miocene objective de-risking the south-eastern area of the block where the partners have plans for additional exploration and appraisal wells.  Murphy has identified another eight prospects in the south-eastern area of the block within 20km of the Cholula 1EXP or tie-back distance for any future development concept.  Although Murphy did not report any estimated reserves, IHS Markit estimates that the 2P recoverable reserves for the Cholula 1EXP are 85 MMboe.  There is another estimated 300-400 MMboe in resource potential in the eight prospects Murphy has identified in the south-eastern area of the block for a total of approximately 500 MMboe.  This amount of reserves would possibly make this area of the block commercially viable since it is located about 90 km from shore.  The other option for Murphy would be to attempt to go through PEMEX facilities and pipelines.  Murphy also reported that it has identified another 25 prospect leads in the remaining area of the block with resource potential of up to 2 Bboe. The NFW was spudded on 8 February 2019 and reached a final total depth (TD) of 2,690 m on 12 March 2019. The CNH reported that the NFW had a proposed total depth (PTD) of 2,746 m measured depth (MD) and 2,717 m true vertical depth (TVD).   The Transocean “Deepwater Asgard” D/S drilled the well in a water depth (WD) of 684 m.   The total estimated drilling cost was USD 46.65 million, and the estimated prospective resources was approximately 200 MMboe. The working interest breakdown of the contract is Murphy Sur, operator with 30% working interest, PC Carigali Mexico Operations with 23.34% working interest, Ophir Mexico Offshore Exploration with 23.33% working interest, and Sierra Offshore Exploration (DEA) has a 23.33% working interest.     In early-November 2018, Murphy as consortium operator for the CNH-R01-L04-A5.CS/2016 contract, announced plans to spud the Cholula 1EXP new-field wildcat (NFW), name changed from Palenque, in the 1st quarter of 2019, delayed from the originally planned 4th quarter 2018.  The plans were announced with its 3rd quarter 2018 earnings report.  The contract exploration plans were previously approved by the CNH in May 2018.    Murphy reported that the Cholula prospect has gross mean resource potential of 200 MMboe and the well cost is estimated to be USD 50 million.  From the approved exploration plans the NFW has a proposed total depth (PTD) of 4,000 m and will test a Miocene objective. On 14 May 2018, the CNH officially approved of the exploration plan submitted by the consortium of Murphy, Ophir, PC Carigali, and Sierra for the CNH-R01-L04-A5.CS/2016 contract.  The approved plan includes the acquisition and re-processing of 3D seismic over the entire block area, various geological and geophysical studies (G&G), and the drilling of one exploration commitment well.  Operator Murphy plans to acquire and re-process 2,573 sq km of the 3D Waz shot by WesternGeco over the area. The partners have selected three prospects in the southeastern area of the block, the Comala, Palenque, and Santiago prospects.  The Palenque prospect is the highest ranked prospect that may be drilled after further G&G studies confirms the location. It has potential prospective resources of 141 MMboe and risked resources of 51 MMboe.  It is a Miocene prospect in an approximate water depth of 750 m with a proposed total depth of 4,000m.  All three prospects have reported estimated prospective resources of 301 MMboe.  A total of 63,380 work units will be apportioned to the exploration efforts on the block with the Palenque well included.  The CNH reported that this was worth USD 90 million.  The minimum commitments for the block were 48,131 work units.    On 10 March 2017, the CNH signed the Official Award for an exploration and production license contract with the consortium of Murphy, Ophir, PC Carigali, and Sierra for the CNH-R01-L04-A5.CS/2016, Area 5 - Salina block the consortium won through the CNH-R01-LO4/2015 Bid Round.  The official contract name is CNH-R01-L04-A5.CS/2016.  This represents the first entry in the country for Murphy, Ophir, and PC Carigali.  Sierra already has working interest in two shelf blocks from R1.1.  Ophir Energy created a new subsidiary that is the official company in the consortium.  The company changed the name of its subsidiary from the original qualified Ophir Mexico Holdings Limited (Ophir Energy) to Ophir Mexico Block 5 Salina S.A. de C.V.

Cholula 1 (Murphy op. 30%, Petronas 23, 34%, Sierra 23, 33%, Ophir (Medco) 23,33%) in CNH-R01-L04-A5.CS/2016 (block 5), was drilled to a TD= 2683m (WD=700m) and came across approximately 57m of net pay. “The results of the well have significantly de-risked the block and the company is currently evaluating future appraisal plans," the Murphy said.

China’s Fosun, through its Roc Oil sub, has agreed to acquire a 50% stake in Buru’s 2,600 b/d Ungani oilfield (L20 + L21 licences) in the Canning Basin, WA, for A$64 MM.  Buru will retain 50% + operatorship. The deal is pending necessary approvals.   Roc will also earn a similar 50% stake in EP 391, 428 + 436 in the same area by funding A$20 MM towards up to 4 wells.  These include the Kurrajong + Ungani West prospects (target Ungani Dolomite), the Yakka Munga prospect and later in 2019 the Rafael prospect, DDGT1 rig. Of note, the Roc deals do not cover the Laurel unconventional gas accumulation within these blocks (of which the Yulleroo gasfield).

China’s Fosun, through its Roc Oil sub, has agreed to acquire a 50% stake in Buru’s (->50% op.) 2600 b/d Ungani oilfield (L20 + L21 licences), for A$64 MM.

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, using the “Deepsea Bergen” S/S, spudded well 35/11-22 S in PL 248 C targeting the Bergand prospect on 12 December 2018. The well had objectives in the Middle Jurassic Tarbert, Ness, Etive, Rannoch and Oseberg formations and the Lower Jurassic Cook and Statfjord formations. On 20 January 2019 Equinor kicked off a technical sidetrack - 35/11-22 ST2. The well was drilled to TD at 3,882 m and on 2 February 2019 the well was abandoned. Results are expected shortly. PL 248 C is located to the west of Equinor’s Fram field where the operator recently (25 May 2018) reported additional investment to drill new wells, resulting in an extra 70 MMboe of recoverable reserves (almost doubling the total remaining reserves). New seismic acquired in the Fram area is being worked up for new exploration opportunities and QA of existing prospects. The Fram field system consists of Fram West, Fram East, Fram H-North and Byrding. West and East each have two four-slot templates tied-back to Troll C. H- North has a further template daisy-chained to Fram West and the Byrding field also uses these facilities. The reservoirs are the Upper Jurassic Draupne, Heather and Sognefjord sandstones and the Middle Jurassic Brent Group. Interest in PL 248 C is divided between Equinor Energy AS (30% + operator), Petoro AS (40%) and Wellesley Petroleum AS (30%).

035/11-22 S (Bergand) (Equinor 30% + Op, Wellesley Petrol. 30%, Petoro 40%) in PL 248 C block - P&A, awaiting results.

Coro Energy's subsidiary Apennine Energy SpA has acquired Sarp SpA's 25% WI on the San Lorenzo production licence and become sole licensee. The transaction was published on 16 November 2018 and effective from 30 October 2018. San Lorenzo was awarded to the partners on 10 March 2014 for a 20 year period and covers 4.92 sq km in the Northern Apennines Basin along the eastern coastline of Italy. The acreage contains the Casa Tiberi gas field discovered by Casa Tiberi 1 NFW (2012, Apennine, 715m) and first gas was delivered on 28 July 2014 from a Lower Pliocene Cellino formation sandstone. During September 2018 the field was producing at a rate of approximately 85,500 cfg/d. Apennine Energy SpA operates the licence with 100% equity.

Coro Energy's subsidiary Apennine Energy SpA has acquired Sarp SpA's 25% WI on the San Lorenzo production licence and become sole licensee.

BOFF ML, Bombay offshore, ops concluded mid-May '20, assumed suspended as DST'd, TD 2,607m, Sagar Bhushan DS.

(Bombay B.) WO-24 K op. by ONGC (100%) in Saurashtra block, TD = 2607 m, WD = 78 m is understood operations have concluded at the well in mid-May 2020, with the rig subsequently moving off location on around 18 May 2020

On 3 October 2018 Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd had signed a Heads of Agreement with Rathlin Energy (UK) Ltd (wholly owned subsidiary of Connaught Oil and Gas Ltd) on a proposed farm-in for a 16.665% interest each in PEDL 183. The licence is located in East Yorkshire and contains the West Newton A-1 gas discovery. There are also plans to drill the West Newton B appraisal well in Q1 2019. The deal was announced to have been completed on 3 December 2018. West Newton B will be located approximately 1.5 km south of the 2013 West Newton well. It is planned to target three potential Permian reservoirs in the Brotheran, Kirkham Abbey and Cadeby formations. The well has a planned TD of 2,000 m to the base of the Permian section. It was initially planned to be drilled with the KCA Deutag T-61 rig. In November 2017 Rathlin confirmed that it still plans to drill the well and in December the company stated that it is currently out to assess and determine rig availability. Drilling is planned to take 6 - 12 weeks where the company is not planning to test any shale horizons (TD likely to be 1,000 m above the Bowland Shale) estimated to be deeper than its Permian targets. It is hoped that the well will determine the commerciality of the discovery. In an update from the company on 17 June 2015 it confirmed that East Riding of Yorkshire Council has granted planning permission for the well. On 26 November 2015 Rathlin announced that it was pleased that the planning committee has unanimously approved the planning application for an extension at West Newton A. Following the well encountering gas the company can move forward with investigating the commerciality of the discovery within the Permian Kirkham Abbey Formation. On 26 July 2016 the OGA confirmed that the Environment Agency has granted a permit for the drilling of the well. In 2013 Rathlin Energy drilled with West Newton 1 (A) well. The well was drilled to a TD of 3,150 m into the Dinantian Carbonate section in the Carboniferous and was tested. The well was located north of West Newton and east of Marton in the parish of Aldbrough, East Riding Yorkshire. It had a primary target based from 2D mapping and is a Permian aged Caedby Carbonate reef. The source rock potential is present within the Permian basinal sediments, the Westphalian coal measures and the Bowland shale sequence. PEDL 183 was awarded in the 13th Onshore Licensing Round and covers an area of 913 sq km. Interest in the licence following the deal is held by Rathin Energy (66.67% + operator), Humber Oil and Gas (16.665%) and Union Jack Oil Plc (16.665%).

Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd had signed a Heads of Agreement with Rathlin Energy (UK) Ltd (wholly owned subsidiary of Connaught Oil and Gas Ltd) on a proposed farm-in for a 16.665% interest each in PEDL 183.

Bangchak Corporation Public Company Ltd (BCP) reported on 13 July 2018 that it had executed a sale and purchase agreement to divest its entire stake in SC 14C1 (Galoc), located offshore Northwest Palawan Basin, to Tamarind Galoc Pte Ltd. The deal involves approximately USD 20 million for shares in BCP’s subsidiary Nido Production Galoc (NPG), which owns 55.8% of the Galoc oil field. Part of the payment is due at the closing of the agreement while the remaining will be payable at agreed terms. BCP owns the stake in NPG through its wholly-owned Nido Petroleum, which was acquired in 2014. Prior to the asset disposal, interests in SC 14C1 were split among Galoc Production Company (GPC) (33%, operator, wholly-owned subsidiary of Nido Petroleum), Kufpec (26.84%), Nido Petroleum (22.88%), Oriental Petroleum (7.79%), Philodrill Corp. (7.21%) and Forum Energy (2.28%). The Galoc field is expected to deplete after 2020 as more than 80% of the recoverable reserves (approximately 4.7 MMbo) had been produced by end of 2017. The SC 14C1 production period is due to expire in December 2025. Due to that reason, the operator and its venture partners were expected to expand the field by developing the mid-Galoc area (MGA). However, poor results from two appraisal wells which were drilled in April 2017 had downgraded the potential of the area. Galoc 7 and its sidetrack intersected poor reservoir quality in the Galoc clastic units with combined gross thickness of 277 m and combined net reservoir thickness of 20 m. Tamarind Galoc, a wholly subsidiary of Tamarind Resources, was established to focus on oil and gas in Southeast Asia. The company is currently operating in New Zealand, Australia and Papua New Guinea. Background Information SC 14 in the Northwest Palawan Basin has had a complex contractual history since its award to Cities Service for on 17 December 1975. Its original partners include Oriental, Philodrill, PNOC, Husky as well as other local firms. The interest holdings were distributed differently in each of the four sub-blocks (A, B, C and D). On 17 December 1986, 14% of the original contract area was retained. This includes 12.5% held as Retained Area plus Matinloc/Pandan, Nido and Libro Production Areas. Cities made oil discoveries at Nido 1, Matinloc 1, Pandan 1, Libro 1, Tara 1 and Galoc 1. In 1982 a four years extension to the exploration period was granted. Alcorn, in its 1989 Annual Report, stated that oil in-place was estimated to range between 80 - 260 MMbo and recoverable reserves between 24 and 102 MMbo, implying a recovery factor between 30 and 40%. In 1990, recoverable reserves were revised to 25 to 40 MMbo. Unocal initially signed an agreement to carry out a phased study of the Galoc oil and gas field with the intent to determine the field's economic feasibility. In mid-October 2003, Unocal decided not to exercise its option to farm-in to the Service Contract and not to proceed with Phase 2 of the development of the Galoc field. The company considered the 150 MMbo in-place uneconomic. The Joint Venture continues to seek interested partners to develop the Galoc field. On 24 September 2004, partner Nido Petroleum announced that, subject to the approval of the Philippines Department of Energy (DOE), a farm-in agreement for the development of the Galoc field has been executed. Two previously unknown companies, Cape Energy Pty Ltd and Team Oil Ltd, have farmed-in to "the Philippines Joint Venture partner's share of SC-14C for carrying costs through development". The current partners will maintain their current equity position in the contract until the two companies have earned their respective interests. Although subject to confirmation, it appears that the farm-in is for SC 14C West Linapacan (North-east) only, and does not involve the other areas of SC 14. On 19 July 2005, the farm-in agreement for the development of the Galoc field was finally approved. Galoc Production Company formed by Vitol Holdings, Granby Oil and Team Oil took over the operatorship of the SC 14C Northeast block by acquiring 75% of the rightholding of the Phillippines Companies.GPC, a Netherlands-based oil investment company, completed a farm-in agreement for a 58.291% operating interest in SC 14C West Linapacan (North-east) on 19 July 2005, including the undeveloped Galoc field. The Galoc field was discovered by Cities in 1981 with the drilling of wildcat Galoc 1. The well was targeting what was believed to be a carbonate build-up identified from a seismic anomaly, but which turned out to be an unusual turbidite sandstone mound in the Lower Miocene Galoc Unit, which unconformably overlies the Nido Limestone. Galoc 1 was drilled to TD at 3,700m and intersected a 40m oil column. A DST in the Galoc Unit flowed 1,828 bo/d (35.3° API). Cities followed the discovery in the same year with the South Galoc 1A step-out, located 5km south of Galoc 1. The well was drilled on a similar but separate anomaly to the discovery and reached TD at 2,614m, encountering five gas bearing intervals in two zones, with a net pay of 15m. The lower zone yielded a flow of 3.77 MMcfg/d plus 280 bc/d while the upper zone tested 3.16 MMcfg/d plus 188 bc/d. South Galoc 1A was plugged and abandoned as a non-commercial gas/condensate discovery. Galoc lies in 320 m of water at about 2,300 metres below sea level, in a low relief domal structure with an areal extent of about 12 sq km at the oil/water contact. A combination stratigraphic/structural trapping mechanism is formed by the turbiditic sands being draped over a subtle anticlinal structure at Nido Limestone level. The field produced 385,000 barrels on long term test in 1988. The field was brought onstream on 9 October 2008, with oil flowing to the "Rubicon Intrepid" FPSO. In March 2006, information from DoE (Department of Energy) Petroleum Resources and Development Division indicated that the Galoc and Octon oil fields could likely produce a maximum of 16 MMbbl during a three to ten-year operation. On 16 September 2008, an independent reserves certification report indicated that Galoc field's 1P reserves were 15.9 MMbo, a 64% increase over the previous estimate of 9.7 MMbo. On 4 May 2011, partner Otto Energy reported an upgrade in gross remaining 2P reserves as of 1 January 2011, to approximately 7.35 MMbo. The upgrade was due to better than expected reservoir performance and to an extension of field life because of higher prevailing oil price. During 2011, Otto was assessing Phase 2 development which was then expected to unlock contingent resources of 2 to 8 MMbo. Following an independent assessment by GCA (Gaffney, Cline & Associates) as of 30 June 2011, 1P recoverable reserves increased to 12.4 MMbo, 19.2% higher than the previous estimate of 10.4 MMbo as of 31 December 2010. According to partner Nido, the increase was due to better than expected reservoir performance in the first half of 2011. The 2P and 3P recoverables estimate changed respectively by +1.6% and -2.2% from the previous estimates of 31 December 2010. An audit by GCA up to 31 December 2011 indicated a new 1P estimate of 14.44 MMbo recoverable, a 16.45% increase from the previous estimate of 12.4 MMbo (as of 30 June 2011). The new 2P recoverable reserves estimate was 22.89 MMbo, a 23.06% increase from the previous estimate of 18.6 MMbo. The new 3P recoverable reserves estimate was 29.44 MMbo, up from the previous 26.3 MMbo (11.94% increase). Nido attributed the increased reserves to a better than expected reservoir performance during the second half of 2011. Following approval of FID for Phase II field development in September 2012, operator Otto Energy announced an upgrade in reserves according to a third-party assessment as of 1 July 2012. The upgrade was due to higher recovery factors from existing wells and to the booking of new reserves previously classified as contingent. Remaining recoverable reserves have been estimated at 8.9 MMbo on a 1P basis (a 156% increase from a previous estimate as of January 2012) and 13.4 MMbo on a 2P basis (134% increase). A new reserves assessment was reported by Otto on 14 March 2013. The revision, carried out by advisor RISC, indicated EUR of 21.7 MMbo (1P) and 25.4 MMbo (2P) as of 1 January 2013. These figures mark increments of 13% (for 1P) and 1% (for 2P) from the previous assessment released in July 2012. The increase was attributed to better than expected reservoir performance and to field life extension due to higher prevailing oil prices. Remaining recoverable reserves have been estimated at 11.7 MMbo (1P) and 15.4 MMbo (2P). Reserves replacement ratio in the field has been estimated as 115% on a 1P basis and 98% on a 2P basis. Otto Energy was evaluating the possibility of a further expansion of the Galoc oil field in late August 2014. Following the first eight months of Phase II production, the operator gained a better understanding of the reservoir distribution between the producing Galoc Central area and the undeveloped Galoc Mid and North areas. Otto expects to issue a recommendation regarding further exploration and development activities between late 2014 and early 2015. Phase II performance has been in line with expectations since its startup in December 2013, with over 2 MMbo produced up to 31 July 2014. The two Phase I wells (Galoc 3ST1 and Galoc 4) continued producing according to forecasts through July 2014. Phase II wells (Galoc 5 and Galoc 6) were producing 4,680 bo/d as at 31 July 2014, contributing to 58% of the total field production. Otto also released an updated third-party reserves assessment as of 31 July 2014, based on decline curve analysis from Phase II production. Developed field reserves have been estimated at 9.2 MMbo (1P), 11.9 MMbo (2P) and 15.6 MMbo (3P). The updated 2P and 3P estimates are respectively 2% and 4% lower than previous estimates as of 31 December 2013. First oil production from Phase II development of the Galoc field was achieved on 4 December 2013. The initial output following the commissioning of new wells Galoc 5H and Galoc 6H was 14,500 bo/d. With the new developments, the field is anticipated to produce beyond 2020 with an estimated ultimate recovery of approximately 25 MMbo. Phase II development focused on the refurbishing of the “Rubicon Intrepid” FPSO and the drilling of horizontal production wells Galoc 5H and 6H. The project was completed in approximately 14 months, from FID to first production. Following the first eight months of Phase II production, the operator gained a better understanding of the reservoir distribution between the producing Galoc Central area and the undeveloped Galoc Mid and North areas. Otto originally expected to issue a recommendation regarding further exploration and development activities between late 2014 and early 2015. Phase II performance has been in line with expectations since its startup in December 2013, with over 2 MMbo produced up to 31 July 2014. The two Phase I wells (Galoc 3ST1 and Galoc 4) continued producing according to forecasts through July 2014. Phase II wells (Galoc 5 and Galoc 6) were producing 4,680 bo/d as at 31 July 2014, contributing to 58% of the total field production Nido Petroleum acquired the block operatorship from Otto Energy on 17 February 2015. In July 2015, the operator announced that the Mid-Galoc area is estimated to contain gross 1C-2C-3C contingent resources of 6.2-9.5-14.6 Mmstb respectively. In-place oil volumes for that area have been estimated at 52.6 MMbo (P90), 77.3 MMbbl (P50) and 113 MMbbl (P10). Recovery factors range between 12% and 13% and are typical of reservoir performance under a pressure depletion mechanism. Two horizontal development wells were planned to be tied back to the existing Galoc FPSO facilities. First oil production form mid Galoc area is expected to commence on 1 January 2018 with initial peak anticipated at 3,000 stb/d.

Tamarind (->55,8%) has bought a 55% stake in the Galoc field (lies off in SC 14C-1) from partner BCP for US$20 MM.

Total reportedly looks set to be the winner of the undrilled, 4,032-sq km  1-22 Tervel offshore block. Tervel will cover the area of the former, unallocated  1-22 Teres block, location between Total’s 1-21 Han Asparuh and Shell’s 1-14 Han Kubrat permits in WD 1,800-2,500m.

Total reportedly looks set to be the winner of the undrilled, 4,032-sq km 1-22 Tervel offshore block. Tervel will cover the area of the former, unallocated 1-22 Teres block, location between Total’s 1-21 Han Asparuh and Shell’s 1-14 Han Kubrat permits in WD 1,800-2,500m.

AE-0056-2M-Mezcalapa-06 block, onshore Sureste Basin, susp. Results n/a earlier this month. PTD was 3,955m, target U. Miocene.

Cibix 1EXP op. by Pemex (100%) in AE-0056-2M-Mezcalapa-06 block, susp. Results n/a, PTD=3955m target U.Miocene

In January 2019 Albpetrol confirmed that tender calls for the exploration acreage held under the state company administration will be launched in 2019. That statement is in line with an announcement of the Albanian Minister of Infrastructure and Energy who disclosed on 6 December 2018 that tenders will be “soon” launched for the offshore acreage located in the Adriatic and the Ionian seas. It is understood that the first blocks to be offered will be the Adriatiku 2, Adriatiku 3, Adriatiku 4 and Joni 5 blocks, however neither detailed information on the acreage nor indications on the timeframe were disclosed at that stage. The Adriatiku 2 block covers 2,880 sq km. Work carried out in the block includes 2,375 km of 2D seismic (with 2,332 km of gravimetry and 2,386 km of magnetics) acquired in early 1992 and the A2-1X wildcat (the first well ever drilled offshore Albania), plugged and abandoned as a dry hole in September 1993 at a final depth of 3,930 m. The block was previously held by Agip between 1991 and 1993. Adriatiku 3 covers 1,185 sq km directly to the south of Adriatiku 2. It corresponds roughly to the Ardiatiku 3 block held by Occidental between 1991 and 1999 without its southeastern part which is now covered by the Duressi permit (San Leon). A total of 1,900 km of 2D seismic was acquired by Occidental in the block in late 1991. The company also drilled the A3-1X wildcat, abandoned with gas shows in May 1994 at a TD of 2,251 m (the well is located outside of the present Adriatiku 3 block). The 698-sq km Adriatiku 4 roughly covers the western part of the former Adriatiku 4 block successively held by Chevron and Agip between 1991 and 2000. A total of 1,574 km of 2D seismic and gravity data were acquired over the block in 1991-1992. Agip made a non-commercial gas/condensate discovery in 1993 with the A4-1X wildcat (located 2 km to the east of the present Adriatiku 4 block). It found 38 MMbbl of 51° API condensate and 150 Bcf of gas. A second wildcat, A4-2X, was plugged and abandoned as a dry hole in February 1997. The 2,268 sq km Joni 5 block covers a frontier area in the southernmost part of the Albanian shelf and deep waters. It is adjacent to the offshore boundary with Greece. Water depth ranges from the coastline up to 1,000 m. The area lies on the eastwards extension of the Apulian Carbonate Platform. Main plays include Cretaceous shelf-edge carbonates sealed by Messinian evaporites and reef-edge talus deposits sealed by mudstones. Three Cretaceous carbonate platform-edge prospects were identified in the Joni 05 block by the previous operators, each showing mean prospective resources in the order of 100 MMboe (Alpha-1, Alpha-2, Beta). Available data for the block includes 2,750 km of 2D seismic acquired in 1992 and 450 sq km 3D seismic acquired in 2009. Couple wells were also drilled nearby including the A5-1X wildcat drilled by BHP and partners Premier and Svenska in 1995. It was plugged and abandoned with oil and gas shows at a TD of 3,298 m without testing. The proposed final depth was 5,000 m with Messinian (Upper Miocene) sandstones as a primary objective, and Pliocene sands and Mesozoic carbonates as secondary objectives.

Albania (East Padan and Adriatic - South Adriatic-Durres) A4-1X

On 2 January 2018 the sale of Tap Oil Ltd’s interest in retention lease WA-33-R retention lease, located in the Barrow Sub-basin, North Carnarvon Basin, to joint venture partner Santos Ltd was registered by the National Offshore Petroleum Titles Administrator (NOPTA).  Tap Oil no longer holds any interest in the licence, with Santos now holding sole interest and operatorship, through subsidiaries Quadrant Oil Australia Pty Ltd and Santos (BOL) Pty Ltd. Tap entered into a sale and purchase agreement to sell its 22.474% interest in the licence on 30 November 2018.  Quadrant and Santos acquired this interest, which was subject to regulatory approval.  The sale of Tap’s interest has an effective date of 1 July 2018. Santos and Quadrant previously increased their respective shares in the permit when, on 19 November 2018, Hydra Energy (WA) Pty Ltd withdrew from WA-33-L.  Hydra assigned its 10% interest in the permit to joint venture partners Quadrant Energy and Santos Ltd. In line with the Hydra and Tap deals, Santos undertook rearranging of the interest holdings in the permit. Now that the withdrawal of both previous holders is complete, interest holdings have become Quadrant Oil Australia Pty Ltd (55% + Operator) and Santos (BOL) Pty Ltd (45%).  However, Quadrant is now a wholly owned subsidiary of Santos, after a takeover, so Santos effectively holds 100% interest in the permit. The withdrawal of Tap was part of a wider strategy to divest its Australian portfolio after completion of a strategic review of all assets. In February 2018 the new Tap Oil Board concluded that, to achieve a low risk, moderate return strategy, it would focus on the producing Manora asset in Thailand and monetize its Australian portfolio to establish a “simpler and leaner” company. WA-33-R covers an area of 321 sq km in water depths less than 100 m. The southern area of the Maitland gas discovery (the northern area lays within WA-214-P, also operated by Quadrant) is located in the licence. The Maitland discovery is yet to be developed. WA-33-R was awarded in 2004 and is scheduled to expire or be renewed on 21 December 2020. Several pipelines, including the Jansz-Barrow Island gas line, already transect the Maitland area.  The existing John Brookes platform lies 12 km from Maitland. Gas could also be processed via East Spar Joint Venture, with the East Spar line just 17 km to the south. WA-33-R is extensively covered by 3D seismic data and Tap expects several further prospects outside of the Maitland field. Work commitments within the lease have been minimal with geotechnical, engineering and marketing studies totaling AUD 100,000 by November 2014.

On 2 January 2018 the sale of Tap Oil Ltd’s interest in retention lease WA-33-R retention lease, located in the Barrow Sub-basin, North Carnarvon Basin, to joint venture partner Santos Ltd was registered by the National Offshore Petroleum Titles Administrator (NOPTA).

The NPD reported on 20 June 2019 that Equinor has carved out a new licence from PL 193. PL 193 GS consists of two part blocks from block 34/11 covering an area of 38 sq km. With effect from 29 May 2019 Spirit Energy left licences PL 193 GS and PL 193 E transferring its 19% interest in the licences to Equinor. In the second half of 2019 Equinor will drill test production well 34/10-C-21 A at Nokken located in PL 193 GS, east of Gullfaks. The Middle Jurassic Brent Group reservoir will be tested and fracked. Testing is expected to commence 1H 2020 and last between three and six months depending on well performance. Results from the well will be used to determine the development solution for the field. The well will be an extended reach well, drilled by the Gullfaks C rig. Nokken was discovered in 1996 by Statoil’s 34/11-2 S well. Gas and condensate flowed from the Etive and Ness formations (DST 1A) at a rate of 4.5 MMcfg/d plus 786 bc/d and from the Tarbert and Ness formations (DST 2) at a rate of 6.1 MMcfg/d plus 471 bc/d. The NPD (December 2018) puts potential recoverable reserves at 125 Bcfg plus 9 MMbc. Interests in PL 193 E and PL 193 GS is held by Equinor Energy AS (58.55% + operator), Petoro AS (30%), A/S Norske Shell (6.45%) and Total E&P Norge AS (5%).

The NPD reported on 20 June 2019 that Equinor has carved out a new licence from PL 193. PL 193 GS consists of two part blocks from block 34/11 covering an area of 38 sq km.

CapeOmega has transferred its 21.8% in PL 048 D to Petrolia effective 28 May '20. The small (6 sq km) PL 048 D lies in part of block 15/5 and contains the E. extn of the UK/Norway Enoch field. Equinor (op), partners now Petrolia, Aker BP + DNO.

Norway (Viking Graben Province) PL 048 op. by EQUINOR (78%), KPC (22%) CapeOmega assigned its 21,8% stake in Enoch Field licence PL 048 D to Petrolia NOCO. Following completion of the deal, interest in PL 048 D is held by Equinor 58.9% + op., Petrolia NOCO 21.8%, Aker BP 10% and DNO 9.3%.

Terra Nova has agreed to acquire partner Perseville’s 30.83% interest in Petroleum Exploration Licence PEL 112 + 444, total  2,255 sq km on the W. flank of the Cooper-Eromanga.  The deal is pending approval by the SA govt.

Terra Nova has agreed to acquire partner Perseville’s 30.83% interest in Petroleum Exploration Licence PEL 112 + 444, total 2,255 sq km on the W. flank of the Cooper-Eromanga.

According to local press reports in Kazakhstan, Shell has decided to withdraw from the project to jointly develop the offshore Kalamkas-More field (within the North Caspian PSA framework) and the Hazar field (managed by the Caspi Meruerty Operating Company (CMOC) consortium). Public hearings of environmental impact assessment that were scheduled to be held earlier in October, have been cancelled. Shell Kazakhstan is quoted as saying that the company has taken a decision to cancel its participation in the project due to complex project economics. Shell considers the Kalamkas/Hazar project non-competitive compared to other projects in its global portfolio. In December 2018, the Ministry of Energy of the Republic of Kazakhstan, PSA LLP as the Authorized Body and the companies participating in the North Caspian PSA as shareholders, signed an agreement on the provision of a plan for the development of the Kalamkas-More field. The agreement provided for the companies to submit a development plan for approval by the Management Committee of the North Caspian PSA before Q4 2019. In April 2019, North Caspian Operating Company’s (NCOC) announced that NCOC and CMOC were planning to start joint development of Kalamkas-More and Hazar. Active development operations were planned for 2021-2027. Shell, which takes part in both operating companies, said in the past that separate development of the two fields did not make sense economically. Background Information Kalamkas-More was discovered by NCOC in 2002. It is located around 75 km south-west of Kashagan. According to the Ministry of Energy, the field’s reserves in-place are 1,177 MMb (149.5 MMt) of oil, 527.5 Bcf (15.4 Bcm) of solution gas and 526 Bcf (15.36 Bcm) of non-associated gas. Hazar was discovered by the CMOC in 2007. It is located around 40 south-west of Kalamkas-More. The field’s 2P reserves are estimated at 404 MMb of oil 5.7 Bcf of associated gas and 215 Bcf of solution gas. Both fields are in the North Ustyurt Basin, i.e. in a different geological setting compared to Kashagan which is in the Precaspian Basin. Kalamkas-More and Hazar’s reservoirs are Mesozoic clastics at relatively shallow depths (1,500-2,000 m), there is no salt in the section and the oil is sweet. The shareholders of NCOC are KMG Kashagan B.V. (16.87%), Shell Kazakhstan Development B.V. (16.81%), Total EP Kazakhstan (16.81%), AgipCaspian Sea B.V. (16.81%), ExxonMobil Kazakhstan Inc. (16.81%), CNPC Kazakhstan B.V. (8.33%), Inpex North Caspian Sea Ltd. (7.56%). CMOC comprises Shell RD Offshore Ventures

Shell has reportedly elected to withdraw from the Kalamkas-More field devt project in the North Caspian PSA and from the Hazar field (run by Caspi Meruerty Optg Co [Shell]) in the N. Ustyurt Basin), citing complex project economics and an earlier belief that separate devt of both fields did not make sense economically.

Kosmos is aiming to reduce its 2020 capital budget for the base business by around 30% whilst keeping 2020 production flat. This has led to plans to defer its share of the BP-operated 2020 Tortue Phase 1 capital spending and extend the carry of capital obligations through the end of this year. The company's priority remains to sell down interests to support a self-funded growing gas business. FID on Tortue Phases 2 + 3 are expected mid-2022 and mid-2023 resp.

Senegal, not found

Wenchang Sag, PRMB, S. China Sea, WD 140m, ops terminated (results n/a) mid-Dec ’18, Nanhai 6 SS. Target Tertiary sands.

China, not found

Woodside is seeking a partner to commit to drilling an exploration well in Frontier Exploration Licence (FEL) 5/13 which contains the Beaufort (previously known as Ventry) prospect. Woodside is currently maturing the prospect with the aim for it to be drill ready in 2020. Partner Bluestack Energy defines the prospect to consist of Upper Jurassic deepwater sandstone reservoir rocks, analogous to the Magnus and Burns Sandstones of the North Sea. The reservoirs are acoustically hard (relative to shale) and often have a high frequency banded appearance, reflecting lateral continuity of bedding. The reservoirs are trapped by a large stratigraphic/hanging wall trap. Overpressured Upper Jurassic / Lower Cretaceous shales provide ideal conditions for stratigraphic trapping. Underlying Beaufort is the Walton prospect (previously named Ventry Deep) which has a similar geometry and seismic character. Bluestack estimate the Beaufort prospect to hold recoverable prospective resources of 395 MMboe with well costs estimated at USD 56 million. FEL 5/13 comprises of six blocks – 35/25a, 35/30, 36/21a, 36/26a, 44/5a and 45/1a and covers a total area of 712 sq km. The acreage was initially awarded as Licensing Option 11/03 in the 2011 Atlantic Margin Licensing Round. Woodside farmed into licence in 2013 acquiring a 90% working interest and operatorship from Bluestack. Up to 45% participating interest in FEL 5/13 is available for farm-in with a data-room set up in London. Interest in the licence is held by Woodside Energy (Ireland) Pty Ltd (90% + operator) and Bluestack Energy Ltd (10%).

Woodside is seeking a partner to commit to drilling an exploration well in Frontier Exploration Licence (FEL) 5/13 which contains the Beaufort (previously known as Ventry) prospect. Woodside is currently maturing the prospect with the aim for it to be drill ready in 2020. Partner Bluestack Energy defines the prospect to consist of Upper Jurassic deepwater sandstone reservoir rocks, analogous to the Magnus and Burns Sandstones of the North Sea.

FAR Limited reports that debt financing for the Sangomar field development offshore Senegal is not proceeding as expected due to COVID-19 and oil price impact on debt markets and the Company has commenced a process to sell all or part of its working interest in the Senegal Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore (RSSD) project in parallel with investigating alternative sources of finance. Location of the Senegal RSSD BlocksIn January, The Government of Senegal approved the Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore (RSSD) joint venture Exploitation Plan and granted the Exploitation Authorisation for the Sangomar Field Development offshore Senegal. Woodside, as Operator of the RSSD joint venture executed the purchase contract for the floating production storage and offloading (FPSO) facility and issued full notices to proceed for the drilling and subsea construction and instalment contracts, including: MODEC Inc for the purchase of an FPSO Subsea Integration Alliance for the construction and installation of the integrated subsea production systems and subsea umbilicals risers, and flowlines Diamond Offshore for two well-based contracts for the drill rigs Ocean BlackRhino and Ocean BlackHawk Following the grant of the Exploitation Authorisation, the RSSD joint venture executed the Host Government Agreement with the Government of Senegal and took an unconditional final investment decision (FID) for the Sangomar Field Development phase 1. The Development and Exploitation Plan outlines the full field multi-phase development of oil and gas and details how the Sangomar Field (formerly SNE Field) will be developed in a series of phases using a stand-alone floating production storage and offloading facility with an initial 23 subsea wells and supporting subsea infrastructure planned for Phase 1. The FPSO is sized for the integration of potential future development phases, including gas export to shore and future subsea tie-backs.First oil is targeted in 2023. A high-definition 3D marine seismic survey across the SNE North, Spica area was completed in February 2020. On 27 March 2020, the Sangomar Operator, Woodside, announced the joint venture was taking early action to manage the impacts of COVID-19 on the supply chain and project schedule. The joint venture continues to evaluate options to reduce the total cost and near-term spend whilst protecting the overall value of the investment. Financing Update COVID-19 and the recent oil price collapse adversely impacted FAR’s financing plans for the Sangomar Field Development. The severe tightening of global debt markets, especially for oil and gas companies, resulted in the debt arrangements FAR had put in place at the beginning of the year being unable to close or complete. FAR has been taking action to seek to preserve shareholder value from this world class asset in the intervening weeks. FAR is contractually committed to the Sangomar Field Development and the approved 2020 work program and budget of US$163M (net to FAR). FAR recognises that it is unlikely to be able to fund its future share of the substantial project commitments based on its current cash reserves and future equity raises alone. The process has commenced to sell all or part of the FAR working interest and investigate alternative sources of finance. In addition, the joint venture is working together with our contractors to cut CAPEX and rephase expenditure into the future to ease the pressure on all partners’ cash flow at this time. The Sangomar Development was running US$117M under budget for the year to end of March and we expect this trend to continue. FAR’s Managing Director Cath Norman said: Reaching FID on Sangomar was a momentous milestone for the joint venture and the people of Senegal and FAR is proud to have played an integral part in the discovery, appraisal and now commitment to develop the significant oil resource offshore Senegal. We thank all our stakeholders and assure you the joint venture is working tirelessly with our partners to manage the impact of COVID-19 on supply chain, costs, and schedule. The key challenge for FAR over the coming weeks is managing the fallout of the COVID-19 epidemic and oil price rout with respect to our ongoing commitment to the Sangomar Field Development and associated work program and budget approved for 2020. FAR thanks its shareholders for their support in the capital raise and SPP at the beginning of the year and welcomes new shareholders to our company. Progressing a sell down of FAR’s working interest in Senegal or arranging alternative financing for FAR’s share of the development and at the same time preserving cash and shareholder value in our assets remain clear objectives of the Board at this time. Original article link Source: FAR Limited

FAR to sell all or part of its interest in the Sangomar development offshore Senegal

Khalda Petroleum has made a discovery in its Bravo South 1X NFW, encountering oil & gas in what is understood to have been a Cretaceous-Jurassic interval. The well was drilled on the Khalda Offset PSC, located in the Matruh Basin. It was spudded on 21 March 2018 and reached a TD of 4,572m in the Jurassic Yakout Formation. Operations were carried out by the Egyptian Drilling Company #57 rig. The discovery lies 2.5km SW of the company's 2012 Bravo 1X (TD 4,932m) oil & gas discovery and ~4km east of the 2014 Herunefer East 1X (4,500m TD) oil & gas discovery. Bravo South 1X is the first well drilled on the exploration lease part of the concession in 2018. Equity in the Khalda consortium is split between Apache (33.5%), Sinopec (16.5%) and EGPC (50%, carried).

Bravo South 1X NFW Khalda Petroleum has made a discovery encountering oil & gas in what is understood to have been a Cretaceous-Jurassic interval

In early February 2020 Petrobras announced the teaser to divest the BM-PAMA-3 and the PAMA-M-192 and PAMA-M-194 exploratory blocks in the Para-Maranhao Basin. The sale is part of the Petrobras divestment program which between 2020-24 aims to collect revenues from US$ 20 to 30 billion. Petrobras is the operator of the blocks, with 100% in BM-PAMA-3 and 80% in PAMA-M-192 and PAMA-M-194 partnering with the China's Sinopec holding the remaining 20%. Petrobras aims to divest up to 50% of the BM-PAMA-3 Block and up to 40% in the PAMA-M-192 and PAMA-M-194 blocks. Sinopec could exercise its right of first refusal to acquire the Petrobras stake on PAMA-M-192 and PAMA-M-194. The BM-PAMA-3 Block was awarded in ANP Round Three and is currently in the appraisal phase, due to the discovery made with well 1BRSA903PAS, known as Harpia. The BM-PAMA-8 concession which includes the PAMA-M-192 and PAMA-M-194 blocks was acquired in ANP Round Six and is currently in the second period of exploration.At an ANP Board of Directors Meeting on 28 September 2016, the board reviewed a Discovery Assessment Plan (PAD) for the 1BRSA903PAS discovery on the BM-PAMA-3 block in the frontier Para-Maranhao Basin. The plan calls for a reprocessing of seismic data and new studies of geology and geophysics and the deadline to drill an extension well is now 28 February 2020. The final completion date for the PAD is now 15 December 2020 when Petrobras will have to issue a declaration of commerciality or relinquish the area. Petrobras acquired 3D seismic over the contract in early 2009. The ANP in April 2012 approved Petrobras's discovery evaluation plan for the significant, rank wildcat, 1BRSA903PAS, Harpia prospect, on the south central part of the BM-PAMA-3 Block. To date no follow up appraisals have been drilled for the discovery. Petrobras concluded operations during late September 2011 on the well after reporting oil and gas shows. It was considered by some to be the most significant well drilled in Brazil during 2011. Petrobras drilled the well in a water depth of 2,060m. Petrobras had a PTD of 5,908m for the wildcat and drilled a very large, gravity induced, faulted anticlinal structure. The principal targets were the Eocene portion of the Travosas Formation with secondary targets possibly in the Cenomanian section of the Travosas Formation. Additional targets were believed to exist in the Oligocene and Miocene sections of the Travosas Formation. The Travosas Formation ranges in age from Cenomanian to Pleistocene and is predominantly shale with sandstone turbidites, fans, and channels that range through the entire extent of the formation. The wildcat was the deepest water well ever drilled in the Para-Maranhao Basin and has a play analogy in the successful West African transform margin, Campanian to Turonian fan, channel plays in Ghana and Ivory Coast.

In early February 2020 Petrobras announced the teaser to divest the BM-PAMA-3 and the PAMA-M-192 and PAMA-M-194 exploratory blocks in the Para-Maranhao Basin.

South Umbarka block, N. Egypt Basin, tested 685 bo/d + 47 MMcfg/d, no further details. PTD was 4,816m, last reported at 4,993m (Shifah fm) in early September. Khalda (op), partners EGPC, Apache + Sinopec.

Egypt (Shoushan Sub-basin (Northern Egypt B.)) Khalda

Further to DEA 19 Mar ’19 (farmin offer) GV has agreed to dispose of its 100% interest in EP 127, 14,280 sq km in the Georgina Basin, NT, to Westmarket Oil & Gas Pty Ltd.  The move is subject to usual conditions. * Global Vanadium, ex-Baraka Energy.

Westmarket will acquire 100% operating interest in EP 127 from Global Vanadium for A$1.5 MM.

PGNiG has been cleared to acquire an extra 10% in PL 636 + 636B, reaching 30%. The acreage contains the Duva field, PDO of which is approved and production expected as of year-end 2020 using 2 oil wells and a gas well linked subsea to the nearby Gjøa facilities. Peak expected at ab. 30,000 boe initially. Neptune (op), partners PGNiG, Idemitsu, Sval Energi. Release here.

PGNiG has been cleared to acquire an extra 10% in PL 636 + 636B, reaching 30%. The acreage contains the Duva field, PDO of which is approved and production expected as of year-end 2020 using 2 oil wells and a gas well linked subsea to the nearby Gjøa facilities. Peak expected at ab. 30,000 boe initially. Neptune (op), partners PGNiG, Idemitsu, Sval Energi.

L44/43, onshore Phetchabun Basin, compl. oil at TD 1,368m on 9 Dec '19. Target Wichian Buri Group volcaniclastics, E-02 rig.

L44/43, onshore Phetchabun Basin, compl. oil at TD 1,368m on 9 Dec '19. Target Wichian Buri Group volcaniclastics,

In November 2018 Parex Resources acquired the Middle Magdalena Basin Fortuna Block and the deal remains subject to regulatory approvals. Exploration plans for the acreage include a 3D seismic survey in 2019 and a two-well drilling program. Additional details were not released.

Parex Resources acquired the Middle Magdalena Basin Fortuna Block

Sunny Hill Energy – owner of Petroceltic – announced on 29 May 2019 having sold the entire issued share capital of Petroceltic SARL and its wholly-owned subsidiary - Petroceltic Bulgaria EOOD - to an undisclosed third party on 29 May 2019. Sunny Hill Energy took control of Petroceltic in June 2016 which was rebranded as Sunny Hill Energy in April 2019. The company’s project of converting the Galata field into a gas storage facility was confirmed in May 2019. Petroceltic previously stated that the Galata field has a high-quality reservoir with permeability of 2,400 md which is ideal to be used as a storage facility. The potential storage capacity of the Galata field after conversion could reached some 2 Bcm.The field is located about 27 km southeast of the city of Varna. It was Bulgaria's first significant offshore field situated on the Black Sea shelf and also the first commercial offshore field to be developed in the country. The Galata field was discovered in 1993. The original target of the Galata 1 exploration well was the Valanginian, but it discovered an unexpected Middle Eocene reservoir (sandstone) not clearly shown on the seismic interpretation. Its gas reservoir is situated below a depth of 1,040 m and is represented by the Maastrichtian Dobrina Formation and the Paleocene Komarevo Formation. It was put onstream in 2004 and the production ceased in 2009. During the shut-down period (2009 to 2013), a considerable volume of gas migrated from peripheral regions to the main area of the field. For that reason, Petroceltic restarted producing from the field in February 2013. In April 2015 Petroceltic estimated that the remaining reserves were less than 3.5 Bcf, consequently the field was shut-in.

Sunny Hill Energy – owner of Petroceltic – announced on 29 May 2019 having sold the entire issued share capital of Petroceltic SARL and its wholly-owned subsidiary - Petroceltic Bulgaria EOOD - to an undisclosed third party on 29 May 2019.

Soliton Resources Limited is offering the opportunity to farm-in to licence P2390 (blocks 23/26e and 30/1d) which contains the Isolde diapir prospect. The Isolde diapir is relatively large with the main targets on its flanks of Paleocene sandstones and Paleocene / Cretaceous chalk. These are the primary reservoirs in the adjacent Machar field (also a diapir) and other nearby fields. Average porosity within the Paleocene sandstones is 23% with a moderate net to gross and within the chalk is 19% – 20% with a high net to gross but low matrix permeability. Chalk reservoirs in piercement diapirs within the North Sea are fractured from extension such as Machar and Banff which aid well productivity. Hydrocarbons are thought to have a relatively high GOR with API values ranging from 40° to 42° for the oil. Minor seal leakage is indicated by ubiquitous shallow oil/gas shows above the diapirs. Soliton estimate mean recoverable resources of 109 MMboe with mean recoverable resources in a gas scenario of 380 Bcf. The prospect is located in 90 m water depths and an exploration well is expected to cost USD 9.5 million drilled to a TD of 2,285 m. Licence P2390 was awarded to Soliton Resources (100%) in the 30th Offshore Licensing Round under the innovate licence schemes. Phase A is for three years from 1 October 2018 with the main commitment to obtain 20 sq km of 3D data, this has been fulfilled. Optional Phase C will commence from 1 October 2021 for three years with a commitment well. For further information please contact: Graham Goffey [email protected] +44 7974 333316

Soliton Resources Limited is offering the opportunity to farm-in to licence P2390 (blocks 23/26e and 30/1d) which contains the Isolde diapir prospect.

Tri-Star has taken over from Stuart Petroleum as holder of PELs 288, 289, 290 + PEL 331, total 33,105 sq km in the Cooper-Eromanga, effective 14 Feb ’18.

Australia, PEL 331

It was announced on 24 November 2019 that Turkiye Petrolleri A.O. (TPAO) has been awarded the M41-C1,C3,C4 exploration licence (Zagros Province) on 18 November 2019 for a period of five-year. The licence, covering an area of 413 sq km, is located towards southeast of the country and TPAO will be 100% owner and operator of the licence. TPAO had filed the application on 13 November 2018. It was subsequently reported 7 December 2019 that Petar Dogalgaz ve Petrol Arama San. Tic. A.S had also submitted the application for M41-C1,C3,C4 licence on 7 February 2019 which was rejected by the government on 28 November 2019.

TPAO (100%) has been awarded the F19-B1,B4 (Thrace Basin) and M41-C1,C3,C4 exploration licence ((Zagros Province)

Palawan55 Exploration and Production Corporation is offering a farm-in opportunity in SC 55, located in Southwest Palawan Basin, in late September 2019. The Fifth Sub-Phase exploration for the block is valid through 25 August 2021 with one commitment well. Palawan55 holds a 37.5% operating interest and partner Pryce Gas Inc (PGI) has 25% participating interest. In August 2019, the partner Red Emperor withdrew from SC 55, prior to submitting a deed of assignment for its 37.5% to Palawan55. Palawan55's interest will increase to 75%, upon approval by the Department of Energy (DOE). Previous activity conducted in the block is the drilling of a commitment well, Hawkeye 1. The well was plugged and abandoned with oil and gas shows. It is the only well drilled within the block. The joint venture had selected and matured the Cinco prospect defined by 3D seismic acquired in 2010. The prospect lies in a water depth of 1,430 m with area of closure of 53 sq km and best prospective resource estimate of 1.6 Tcf of recoverable gas. Background Information The original 9,152 sq km of SC 55 was awarded to Ottoman Energy (42.5%, operator), AustralAsian Consortium (AAC) (42.5%) and Trans-Asia Oil and Energy Development Corporation (15%) on 5 August 2005. The contract area was initially divided into two separate blocks, SC 55A (6,097 sq km) and SC 55B (3,055 sq km), the majority of which lies in deepwater. In early 2015, PNOC-EC’s expressed interest to farm-in in the block, however did not received approval by the Office of the President of the Philippines. Red Emperor farmed-in for the 15% working interest with the previous operator, Otto Energy (formerly Ottoman Energy) on 2 March 2015. Red Emperor’s participating interests increased to 25% after Otto exited the block and transferred its operating interest to its partners. On 27 July 2015, PGI signed a farm-in agreement for the right to earn a 10% working interest. PGI agreed to participate and pay 10% at amount of US$3.225 m of the well cost of the drilling and testing of the Hawkeye 1 which were commenced in July-August 2015. Otto fulfilled the commitment for the fourth exploration sub-phase with the drilling of the wildcat. It is the first wildcat drilled in the concession and the pioneer for turbidite play in the basin. Approximately USD 25 million was spent on the drilling commencement of Hawkeye 1. The Hawkeye 1 was plugged and abandoned on 19 August 2015, with oil and gas shows. The well was spudded on 31 July 2015 by “Maersk Venturer” drillship in water depth around 1,788m and had TD at 2,920 m. The well penetrated the top primary target Pagasa clastic reservoir which is interpreted to be gas bearing at sub-commercial volumes. The high impact wildcat has proven the presence of an active petroleum system in the contract area, which hosts the “Cinco Prospect” as well as several other leads. The results of the the Hawkeye 1 has been incorporated into understanding of the other prospects, including Cinco, which potentially share the same charge source. The SC 55 block identified two prospects and eight carbonate leads in the area where the 1,800sq km 3D survey was shot. Total unrisked mean recoveral resource potential is estimated at 19 Tcfg plus 670 MMbc for the Oligocene to Early Miocene carbonates. The Uno prospect, similar to Cinco, is also a platform carbonate build-up located in the central portion of the block. The prospect lies in a water depth of 960 m, has an area of closure of 38 sq km with reservoir objective depth from 3,960 to 4,600m (up to 600m column height), and has gross recoverable resource estimates of 0.01 to 2.1 Tcfg (0.85 Tcfg mean) plus 2-74 MMbc (29 MMbc mean).

Red Emperor (Century Red) has withdrawn from SC 55 (9152km). Its 37,5% interest is distributed amongst remaining partners Palawan55 op. ->75% and Pryce Gas 25%).

On 12 June 2020, Sirte Oil Co (Sirte) reported that the A-005-LP003D exploratory well encountered oil and gas in the Beda Formation. The well tested 626 b/d of oil and 62.7 MMscf/d of gas in an interval between 2,169 m and 2,190 m of the reservoir formation. TD was reached at 2,240 m at the Hagfa Formation. On 28 December 2019, Sirte spudded the well in the LP003D-A-001 field, onshore in central Sirte Basin using the ADWOC 37 rig with a planned depth of 2.259 m. The main objective was the Paleocene Beda Formation. ELF first drilled LP003D-A-001 in the 1970s. This approximately 10 MMbbl Oil Recoverable (IHS Markit estimation) field was appraised with two wells in 1973 and 1975, respectively and then again in 2013 with one last well. All the wells encountered oil in the Beda Formation, but the field was never developed. Sirte operates 003D block with the 100% of interest and is fully owned by the National Oil Corporation (NOC).

Libya (Central Sirte B.) A-005-LP003D expl, operated by NOC (100%) in 003D block, oil & gas encountered in the Beda Formation below 2,178m in the target Beda fm, tested 626 bo/d + 62.7 MMcfg/d from between 2,169-2,190m.

Equinor spudded exploration well 6507/2-5 S targeting the Orn prospect in PL 942 on 23 July 2019. The well’s objective was the Middle Jurassic Fangst Group and condensate of the Alve type was the expected hydrocarbon. The “West Phoenix” S/S is being used and operations are expected to last around 53 days. Partner Aker BP reports prospective resources of 8-40 MMboe. In the event of a discovery, development via a tie-back to the Skarv FPSO would be the most likely option (Skarv lies approximately 20 km to the southeast). On 11 September 2019 Equinor was plugging and abandoning the well having reached a TD of 4,230 m (4,186 m TVD). This is the second Equinor well in the area in 2019. The company earlier drilled the Snadd Outer Outer well in neighbouring block 6507/3 and made a new discovery (see separate article for details). PL 942 is operated by Equinor Energy AS (40%) with Aker BP ASA (30%) and Wellesley Petroleum AS (30%) as partners.

6507/02-05 S (Orn) (Equinor 40% op, Aker BP 30%, Wellesley Petr. 30%) in PL 942 block, P&A, results awaited. The well’s objective was the Middle Jurassic Fangst Group and condensate of the Alve type was the expected hydrocarbon.

Nexen has acquired a 25% interest in Frontier Exploration Licences (FEL) 5/18 and 6/18 from ExxonMobil. In return for the interest in the licences, ExxonMobil has taken a 50% interest in FEL 3/18 which contains the Iolar prospect, slated for drilling next year in 2019. It is understood that the deal completed in September 2018. Iolar is planned to be drilled in Q2 2019 with the Stena IceMax drillship. FEL 3/18, previously known as LO16/7, covers an area of approximately 1,300 sq km and is located immediately west of FEL 2/14 where Providence drilled the Druid / Drombeg exploration well in 2017.   Interest in FEL 3/18 is now held by Nexen Petroleum UK Limited (50% + operator) and ExxonMobil Exploration and Production Ireland (offshore south) Limited (50%). Interest in FEL 5/18 and FEL 6/18 is now held by ExxonMobil Exploration and Production Ireland (offshore south) Limited (25% + operator), Equinor UK Ltd (50%) and Nexen petroleum UK Limited (25%).

Nexen has acquired a 25% interest in Frontier Exploration Licences (FEL) 5/18 and 6/18 from ExxonMobil. In return for the interest in the licences, ExxonMobil has taken a 50% interest in FEL 3/18 which contains the Iolar prospect,Interest in FEL 3/18 is now held by Nexen Petroleum UK Limited (50% + operator) and ExxonMobil Exploration and Production Ireland (offshore south) Limited (50%). Interest in FEL 5/18 and FEL 6/18 is now held by ExxonMobil Exploration and Production Ireland (offshore south) Limited (25% + operator), Equinor UK Ltd (50%) and Nexen petroleum UK Limited (25%).

In a press release dated 31 March 2020, Oil Search announced it had successfully flow tested the Nanushuk reservoir in the in the Mitquq 1 ST1 (API 501032080801) exploration well on lease ADL 393876 on the North Slope. The well encountered a net pay zone of 172 ft (52 m) with a gas cap of 29 ft (9 m) and flowed at a stabilized rate of 1,730 bod from a single stimulated zone. Logs and core were acquired before conducting the flow test. The original Mitquq 1 (API 501032080800) well encountered 197 ft (60 m) of net hydrocarbon pay in the primary objective Nanushuk interval, comprised of 17 ft (5 m) of net gas pay and 180 ft (55 m) of net oil pay. No oil-water contact was encountered. The well also intersected 21 ft (6 m) of net gas pay and 31 ft (10 m) of net oil pay in the secondary objective Alpine C target. The Alpine C reservoir will be evaluated by future appraisal wells. The well was spud 25 December 2019, using the Nabors 7-ES rig. On 18 December 2019, the Alaska Oil and Gas Conservation Commission approved permit 2191500 filed by the company to drill the well. Oil Search filed the Lease Plan of Operations Application on 26 September 2019 and the Alaska Department of Natural Resources approved it on 6 December 2019. The plan covers lease ADL 393876, where the drill pad will be located, and adjoining lease 393875 directly to the east. The Mitquq prospect in the Pikka East block is about 6 mi (10 km) to the southeast of the Pikka Nanushuk Development Pad A (ND-A). The prospect is described as Nanushuk analog that can be tied back to future Pikka infrastructure, with a potential resource of 200 – 500 MMbo. Secondary targets may be penetrated to evaluate exploration upside within the Torok, Kuparuk C and Alpine C reservoirs. The application calls for the drilling of one well and a sidetrack from an ice pad located in Sections 3 and 10 of U11N7E, as well as acquiring tiltmeter data and a walkaway vertical seismic profile. The wells will be directionally drilled to a true vertical depth of 7,000 ft (2,134 m) or less, with the Mitquq 1 well being drilled to a bottom hole location about 3,083 ft (940 m) to the east-southeast. Oil Search operates the leases with 51% working interest, with the remaining 49% interest held by Repsol. Keiran Wulff, Managing Director of Oil Search, said, "We are very encouraged by the success of our 2019/20 Alaskan exploration programme, with oil discovered in all three penetrations, at Mitquq 1 Mitquq 1 ST1 and Stirrup, and excellent flow rates achieved in the two well tests. We also discovered high quality oil in a deeper reservoir at Mitquq which was not tested. While further appraisal will be required, these new discoveries may represent low cost tie-back options to the proposed Pikka Unit Development and have the potential to create substantial long-term value for Oil search shareholders, as well as having positive implications for the prospectivity of our acreage."

United States, ADL 393876

On 24 April 2018, ExxonMobil announced that it had signed agreements with the government of Namibia and the National Petroleum Corporation of Namibia (NAMCOR) for Block 1710 and Block 1810. In addition, the company signed farm in agreements for Block 1711 and Block 1811A. All the blocks cover acreage primarily atop the Namibe basin just south of the Angolan/Namibian border. It’s worth noting that Exxon has a signed memorandum of understanding for Block 30, Block 44 and Block 45 in the Angolan portion of the basin. Exxon’s acreage seems to correlate with the major depocenters within the basin where sediment thicknesses are expected to be more than 3,000 m.   Block 1710 and Block 1810 cover a combined area in excess of 20,000 sq km and will be operated by Exxon with a 90% interest, NAMCOR will hold a 10% stake. Exxon will assign 5% of its interest to a local Namibian Company. To date these blocks are virtually unexplored, there are a few 2D seismic lines the cross both blocks but no 3D data and no drilling. 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 will operate the blocks with an 85% interest and NAMCOR will hold 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.

ExxonMobil (90% op. Namcor 10%) awarded rights to blocks 1710 + 1810, and farmin (85% op. Namcor ->15%) to 1711 + 1811A blocks, total 28000km².

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 May 2020, it is understood that the blocks listed in the table below were available for licensing. Sixty five blocks were available. There were no changes in the list compared to the previous one. Total open acreage amounts to 770,668 sq km of which 681,508 is onshore and 89,160 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-5 11,153 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-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 C-4 9,037 onshore 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 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

Mauritanian Government open blocks Total open acreage amounts to 770,668 sq km of which 681,508 is onshore and 89,160 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-5 11,153 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-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 C-4 9,037 onshore 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 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

Imetame has been cleared to farmout a 50% interest to Petro-Victory in ES-T-354, 373, 441, 477 + 487 blocks, total 143 sq km onshore Espirito Santo Basin. Imetame will retain operatorship and 50%:

Imetame has been cleared to farmout a 50% interest to Petro-Victory in ES-T-354, 373, 441, 477 + 487 blocks, total 143 sq km onshore Espirito Santo Basin. Imetame will retain operatorship and 50%:

During Q1 2020, Khalda Petroleum had successfully completed its Elan 1X NFW as an oil & gas discovery. The well encountered a 29.5m net pay and tested at ~7,500 boe/d. It is understood to be situated between the Qasr and Ozoris fields, located on the Khalda Offset PSC in the Shushan Basin.Qasr was discovered by the company’s 2003 Qasr 1X NFW (4,182m TD), with Ozoris being discovered by the company’s 2001 Ozoris 1 NFW (3,857m TD). Both discoveries reservoir in the Cretaceous Alam El Bueib Formation. Equity in the Khalda Petroleum consortium is split: Apache (33.5%), Sinopec (16.5%) and EGPC (50%, carried).

Egypt (Northern Egypt B.) Elan 1 op. by APACHE (67%), SIPC (33%), EGPC (0%) in Khalda block, TD = 4188 m oil & gas discovery. The well encountered a 29.5m net pay and tested at ~7,500 boe/d.

ANP's 2019 ToR Excess Volumes PSC round (aka Transfer of Rights) was held yesterday with mixed results. Only 2 of the 4 contracts on offer resulted in preliminary wins, and there were only 2 bids for the Búzios* and Itapu** blocks - led by Petrobras. There were no bids for Atapu and Sépia. Majors failed to participate, suggesting terms were not attractive enough (high upfront dues) - 7 out of 14 qualified participated and only 3 bids were placed. Ecopetrol, Equinor, ExxonMobil, and Petrogal participated but placed no valid bids. The authorities will look at alternative solutions to offer Atapu and Sépia again – possibly in 2020. * Búzios: Petrobras (op) 90%, CNODC 5%, CNOOCI 5%. **Itapu: Petrobras 100%. ANP's planned 6th pre-salt round takes place later today (ref. DEA 16 Oct '19).

Petrobras was granted a preliminary award for Itapu field (100%) and Buzios field (90% op, CNOOC 5%, CNODC 5%), biggest area on offer ANP's 2019 ToR Excess Volumes PSC round (aka Transfer of Rights) in the Brazilian pre-salt.

Re-drill of 2017 junked HP/HT well targeting the Glengorm prospect in P2215, WD 86m, TD 5,056m, 37.6m net gas + cond pay in the Jurassic, 250 MMboe recoverable. Well P&A’d, Prospector 5 JU. Target Fulmar + Freshney sst. Tie-backs possible to the Elgin-Franklin platform and the Culzean project. CNOOCI (op), partners Euroil + Total.

United Kingdom (Fulmar-Clyde Terrace (Central Graben)) Fulmar

East West Petroleum Corp is understood to be offering equity in both PEP 54877 and PMP 60291, located in the Taranaki Basin, in which it holds 30% working interest. The company announced on 4 August 2020 that it had terminated an agreement for the sale if its equity in both permits to a private New Zealand company. East West Petroleum is now seeking to "bring value to shareholders from its 30% interest which can include the sale of the working interest". PEP 54877 is located on trend with, and between, the Stratford and Cheal fields. The permit is virgin territory with no wells having previously been drilled. The area is covered by 3D seismic data, principally by the Brecon 3D survey which was acquired in 2006. The Kapuni 3D and Stratford 2D seismic surveys also cover portions of the permit. PMP 60291 covers the Cheal East oil and gas field which was discovered in 2013. With the field on production at rates of over 200 boe/d for 2019, the permit offers a revenue stream in the right oil price environment. With the oil price at a 22-year low in April 2020, East West Petroleum reported that permit operator Tamarind Resources Pte Ltd had considered the possibility of shutting the field in amidst a collapsed oil price. PEP 54877 covers an area of 12 sq km and was originally awarded on 11 December 2012. PMP 60291 covers an area of 3 sq km and was awarded on 15 September 2017. Tamarind Resources Pte Ltd, via wholly owned subsidiary Cheal Petroleum Ltd, holds 70% operated interest in the permits with the remaining 30% held by East West Petroleum Corp subsidiary East West Petroleum (NZ) Ltd.

(Taranaki B.) East West Petroleum Corp is understood to be offering equity in both PEP 54877 and PMP 60291. Both blocks are operated by TAMARIND (70%) partner EAST WEST (30%).

According to reports in November 2018, Petroleos Sudamericanos plans to purchase and reactivate four production concessions in the Province of Rio Negro from state company YPF, namely the Bajo del Piche, Barranca de los Loros, El Medanito, and El Santiagueno blocks. The USD 30 million investment project is currently under review by the provincial government before the transfer of assets can be approved. Bajo del Piche block (74 sq km) is situated on the Neuquen Embayment part of Neuquen Basin, while Barranca de los Loros (186 sq km), El Medanito (104 sq km), and El Santiagueno (623 sq km) blocks are situated on Northeast Platform part of the basin. Background Information In September 2018, fields in the Bajo del Piche, Barranca de los Loros, El Medanito, and El Santiagueno blocks produced 8.2 Mbo and 13.2 MMscfg, 614 bo and 3.5 Mscfg, 29.6 Mbo and 82.6 MMscfg, and 28.8 Mbo and 53.9 MMscfg, respectively.

Petroleos Sudamericanos plans to purchase and reactivate four production concessions in the Province of Rio Negro from state company YPF, namely the Bajo del Piche, Barranca de los Loros, El Medanito, and El Santiagueno blocks.

Neptune Energy has announced two important hydrocarbon discoveries in northwestern Germany. Initial results were positive following successful drilling of the Adorf Z15 gas well and the Ringe 6 oil well. Drilling of the Adorf Z15 appraisal well, in the municipality of Emlichheim, reached final depth of 3,500 meters in the Carboniferous formation in February 2020. Subsequent production tests indicated flow rates of up to 1,700 boepd gross. A processing plant for the natural gas will be constructed during H1 2020 with production expected to start towards the end of the year. In the Ringe region, drilling operator Wintershall Dea began operations in December 2019 to develop an extension of the existing reservoir. The Bentheim sandstone formation was found to be oil bearing at a depth of 1,500 meters. For completion and connection to the existing infrastructure, the project was handed back to production operator, Neptune, and production is expected to start from next week. Neptune’s Managing Director in Germany, Andreas Scheck said: 'The results of these two successful wells underline the great potential for future oil and gas production in the region and will enable us to increase our production significantly. I would like to thank everyone involved.' Neptune is operator of the Adorf and Ringe fields. Wintershall Dea is a joint venture partner. Neptune’s share in the Adorf Z15 well is 66.7% and 45% in Ringe. Original article link Source: Neptune Energy

Neptune (op.50%, Wintershall Dea 25%, BEB Erdgas 25%) has announced 2 important hc discoveries: Adorf Z15 appr. gas well in the Adorf block, reached TD=3 500m in the Carboniferous Fm, production tests indicated flow rates of up to 1700 boe/d gross, and Ringe 6 oil well in Ringe block.

TPAO secured sole rights to explo licences E18-C1,C2,C3, E18-D1,D2 and F19-A1,A2,A3 on 3 Jul ’18 for 5 years. The 3 licences total 1001 sq km in the Thrace Basin.

TPAO secured sole rights to explo licences E18-C1,C2,C3, E18-D1,D2 and F19-A1,A2,A3 on 3 Jul ’18 for 5 years. The 3 licences total 1001 sq km in the Thrace Basin.

Guachiria Sur block, Llanos Basin, drilled 13-20 Jan ’18, TD 2,126m, no results.

Maguey 1 (Lewis Energy 100%) in Guachiria Sur block, P&A, w.o. results.

Total (30%) has exited licence K01c to operator ENGIE as of 24 January 2018. The exploration licence covers 274 sq km and is located 5 km N of the K01-A and K04-A producing gas fields, both operated by Total. ENGIE has until 1 July 2018 to decide if to drill K01c, with drilling operations to be completed by 4 January 2019. K01c was awarded to GDF SUEZ (renamed ENGIE in April 2015) and Total for four years initial period, commencing 2 January 2012. The two companies had submitted a joint application for the acreage in November 2010 and the Ministry of Economic Affairs received no competing bids during the public tender period. Three dry exploration wells have been drilled on the acreage between 1979 and 2006. On 11 May 2017, ENGIE received a binding offer from Neptune Energy to acquire a 70% interest in its E&P division, and is pending completion. K01c licence partners are ENGIE E&P Netherlands BV (60% + Op) and Energie Beheer Nederland (EBN) (40%).

Total (30%) has exited licence K01c to operator ENGIE