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NAMR has approved OMV Petrom’s 2013 agreed acquisition of Repsol’s 49% stake in onshore blocks V Baicoi, VI Targoviste, XII Pitesti and XIII Targu Jiu. OMV Petrom ends sole holder of the tracts, total 11,182 sq km in the Diapir Fold Belt and Outer Carpathian Foredeep.   The investments done under the Joint Operating Agreement amount to more than 200 million USD until today, including 2D and 3D data acquisition campaigns and drilling of two deep and complex, high pressure wells. A third exploration well is currently in the drilling phase, below 5,000 m.

Romania, XII Pitesti

ADNOC is launching its first ever bid round for new licensing opportunities in Abu Dhabi. The offered acreage is shown below in orange (map courtesy ADNOC), 6 blocks (2 offshore, 4 onshore), details available after the roadshows: Abu Dhabi 23 Apr ’18, USA 26 Apr ’18, Europe 1 May ’18, Far East 8 May ’18 Registration is required.  Bid deadline is Oct ’18, winners by year-end.

UAE, not found

Europa Oil and Gas is offering interested parties to farm-in to Frontier Exploration Licence (FEL) 4/19 which contains the Inishkea prospect and several other Jurassic and Triassic gas plays. Inishkea is located in the Erris sub-basin, around 13 km north-west of the producing Corrib gas field, and has a gross mean un-risked prospective resource estimate of 1.5 Tcfg. The company expects to obtain permission in 2H 2020 to complete a site survey for future exploration drilling at the licence. On 11 June 2020, Europa acquired FEL 3/19, containing the Edge prospect, and will re-launch the farm-out of FEL 4/19 in combination with this opportunity. In October 2019 Europa reported it was in ongoing negotiations with a major oil and gas company concerning licences FEL 4/19, FEL 1/17 and FEL 3/13, but this fell through by January 2020. Inishkea has a 33% chance of success and has been de-risked through PSDM reprocessing of 770 sq km of 3D seismic over both the prospect and the Corrib gas field. Reprocessing was benchmarked and calibrated against Ocean Bottom Cable 3D seismic data over the Corrib gas field. Inishkea is defined as a large Triassic structure comprising of Triassic Sherwood sandstone reservoirs, Carboniferous source rocks and a trapping mechanism consisted of a Triassic Uilleann Halite top seal and fault seal. The water depths are relatively shallow (400 - 600 m) and do not require harsh environment sixth generation drillships, which will reduce drilling costs. Europa has conducted a drill cost estimate for a well on the Inishkea prospect and a dry hole cost including mobilisation and demobilisation of USD 28 million using a rig rate of USD 120,000 per day. Gas infrastructure is already present nearby at Corrib therefore a fast track path to commercialisation is potentially available, subject to negotiation and cooperation with the current infrastructure owners. The remaining inventory in FEL 4/19 includes the Inishkea NW prospect (1,094 Bcf), Inishkea W prospect (212 Bcf), Bofin lead (69 Bcf), Corrib North discovery (40 Bcf) and Corrib NW prospect (26 Bcf). Interest in FEL 4/19 is held solely by Europa Oil & Gas (Inishkea) Ltd. For further information please contact: Murray Johnson Email: [email protected]

Europa Oil and Gas is offering interested parties to farm-in to Frontier Exploration Licence (FEL) 4/19 which contains the Inishkea prospect and several other Jurassic and Triassic gas plays. Inishkea is located in the Erris sub-basin, around 13 km north-west of the producing Corrib gas field, and has a gross mean un-risked prospective resource estimate of 1.5 Tcfg.

The council of ministers has reportedly approved the award of southwestern deepwater block 7 to Total (op) + Eni. The 4,555-sq km block contract will run 3+2+2 years + 25 prod. Meanwhile a Total deal with Eni to farmin to the latter’s offshore blocks 2, 3, 9 + 8 has also been approved. Kogas already partners Eni in blocks 2, 3 + 9.

The council of ministers has reportedly approved the award of southwestern deepwater block 7 to Total (op) + Eni. The 4,555-sq km block contract will run 3+2+2 years + 25 prod. Meanwhile a Total deal with Eni to farmin to the latter’s offshore blocks 2, 3, 9 + 8 has also been approved. Kogas already partners Eni in blocks 2, 3 + 9.

Battonya-Pusztafoldvar Dél (South) block, Békés sub-basin in SE Hungary, tested 3.4 MMcfg/d during an 8-hour test, WHFP 739 psi, from a 5m net pay between 746-755m in Pannonian sst. PTD is/was ab. 1,000m.

Vermilion Energy Hungary Kft tested gas at a flow rate of 3.4 MMcf/d during an eight-hou in new-field wildcat Battonya Eszak 9 in southeastern Hungary

Cambay PSC, 161 sq km in the onshore Cambay Basin, Oilex is understood to be open to potential farm-in partners. The company has filed a request to the authorities to transfer GSPC’s 55% participating interest in the block (producing since 1964), following the latter’s default on PSC expenses. Contact: Joe Salomon ([email protected]).

Cambay PSC, 161 sq km in the onshore Cambay Basin, Oilex is understood to be open to potential farm-in partners. The company has filed a request to the authorities to transfer GSPC’s 55% participating interest in the block (producing since 1964), following the latter’s default on PSC expenses.

29 Nov '19, Aker BP picked up a 40% stake from Spirit in PL 780 (part block 16/1), 18 sq km round the Sorvesten prospect to be drilled 3Q '20. Spirit (op), partner Aker BP.

Aker BP picked up a 40% stake from Spirit in PL 780 (part block 16/1), 18 sq km round the Sorvesten prospect to be drilled 3Q '20. Spirit (op), partner Aker BP.

Santos has picked up a 45% stake in retention lease WA-55-R, 139 sq km in the N, Carnarvon Basin, partly owed to the withdrawal of previous 20% holder Harriet (Onyx) Pty Ltd.  Quadrant (op) 55%, partner Santos 45%. 

Santos acquired a 45% in retention lease WA-55-R from Quadrant NW and partly from the withdrawal of previous holder Harriet (Onyx) (-> 55%).

On 10 January 2018 Wintershall spudded a well on the Balderbra prospect in PL 894 using the “West Phoenix” S/S. 6604/5-1 targeted a robust structural closure with an amplitude anomaly between the Gullris (6604/2-1) and Gro (6603/12-1) wells. The well was drilled to TD at 3,858 m before a technical sidetrack was kicked-off. This wellbore was drilled to TD at 3,760 m in the Upper Cretaceous Springar Formation and has made a new gas discovery. Three separate gross gas columns, totalling 190 m, were encountered in the Springar Formation. Reservoir quality is moderate to poor and no GWC was encountered. Estimated recoverable reserves are between 247 – 671 Bcfg and 6 – 19 MMbc. On 22 March 2018 the well was abandoned. The Gullris well was drilled by BG in 2011 on the Gjallar Ridge to the north of Balderbra. Sandstone (21% porosity and 200 mD permeability) was encountered in the Springar Formation but it was water-wet. Shell’s 2009 Gro well made a gas discovery, proving a 16 m gas column in the Springar Formation with recoverable reserve estimates in the region of 350-3,500 Bcf. The find was appraised in 2010 and a 50 m gas column was confirmed in the Springar Formation but reservoir quality was poorer than expected. Due to the variation in reservoir quality and gas saturation between this well and the discovery well, reserves were expected to be in the lower part of the range given after the discovery well was drilled. The Gro licence was relinquished in 2011. Interest in PL 894 is held by Wintershall Norge AS (40% + operator), Statoil Petroleum AS (40%) and Petoro AS (20%).  

Norway, PL 894

At the time of writing (April 2018), it is understood that the Government of the Union of Comoros is still offering 32 open blocks on an open-door policy. Of the 32 open blocks, seven blocks are located in the Somali Deep Sea Basin (blocks 01 to 07), four straddle the Somalia Deep Sea and the West Indian Ocean Floor basins (blocks 08 to 11) and the rest lie entirely on the West Indian Ocean Floor Basin (blocks 12 to 34). Block surface of the open blocks ranges from 2780 sq km to 6,530 sq km. The blocks offered included territorial waters of the claimed Mayotte Island. Contact details: H.E. Abdou Nassur Madi Union des Comores Minister of Production, Environment, Energy, Industry and Handicrafts B.P. 41 Moroni – Comoros Phone: +269 775 0000 There are 40 blocks delineated by the government, among which two blocks (17 and 24) awarded in late 2015 to Rhino Resources, three blocks (35, 36 and 37) awarded in 2014 to Bahari Resources and Discover Exploration and three blocks (38, 39, 40) awarded in 2014 to Safari Petroleum and Western Energy Production. Zones around the main islands of the Archipelago are excluded of any petroleum exploration. The Comoros’ acreage is a frontier area. The Comoros Islands are separated from East Africa by the Davie Fracture Zone, although, the Rovuma Delta Fan may extend beyond that ridge. The main potential for oil and gas exploration appears to be the eastern extension of the Rovuma Delta where deep water fan stratigraphic plays are expected to be found. Faulting along the ridge separating the Comoros from East Africa Continent is also known to have created large anticlinal structures. No exploration well has ever been drilled in Comorian waters. The current licensing regulation allows an operator to apply for one permit including up to three blocks, each of them covering a maximum area of about 6,500 sq km. The applicant must initially negotiate the terms of the petroleum contract with the minister in charge of energy. Then, the Council of Ministers gives its approbation, so that the petroleum contract can be signed, before a final approval by the National Assembly. The initial four-year exploration period compels the companies to acquire a 2D seismic survey and to determine prospective exploration targets. Background Information The Union of Comoros became independent from France in 1975. The Comoro Islands consists of three major islands: Grand Comore (also known as Ngazidja), Mohéli (Mwali) and Anjouan (Nzwani). The contested Mayotte (Maore) Island has been an overseas department of France since 31 March 2011, but it is still resolutely claimed by the Comorian authorities. Comoros has a total population of about 800,000 people (excluding Mayotte).

At the time of writing (April 2018), it is understood that the Government of the Union of Comoros is still offering 32 open blocks on an open-door policy. Of the 32 open blocks, seven blocks are located in the Somali Deep Sea Basin (blocks 01 to 07), four straddle the Somalia Deep Sea and the West Indian Ocean Floor basins (blocks 08 to 11) and the rest lie entirely on the West Indian Ocean Floor Basin (blocks 12 to 34).

On 7 February 2019 Frontera Energy and Parex Resources signed a farm-in agreement for 50% interest in the VIM-1 Block of the Lower Magdalena Basin. Per terms of the deal, which is subject to ANH approval, Frontera will fund all costs for the first USD 10 million of drilling, testing and completing the La Belleza 1 exploration well, slated to spud during Q2 2019. After this initial payout, all costs on the block will be divided evenly between Frontera and Parex.

Frontera Energy has farmed into the VIM 1 block in Colombia after striking a deal with Parex Resources. 50/50).

A technical evaluation agreement was signed on 24 Jun ’19 for block 34, 5,930 sq km in deepwaters of the Congo Fan + Kwanza Basin. Pursuant to the studies, a full exploration contract could be signed-up. Partners to the signature are Cabgoc (Chevron), Sonangol and National Agencey for oil, gas + biofuels.

Cabinda Gulf Oil Comp. a wholly owned subsidiary of Chevron and Sonangol E.P, signed a cooperation protocol for the study and evaluation of Block 34 (5930km²) in WD between 1600m and 2600m.

CNOOC issued announcement of notification for 2020 bidding blocks China offshore on 18 May 2020. In 2020, CNOOC offer total 15 exploration blocks, covering an area of 9,453 sq km, offshore China. Among them, one block is located in Bohai Bay, Bohai Gulf Basin, with the acreage of 127 sq km, one block is located in the East Sea Basin with the acreage of 1,784 sq km, 10 blocks are located in the Pearl River Mouth Basin with the acreage of 5,890 sq km, two blocks are located in the Qiongdongnan Basin with the acreage of 1,252 sq km, and one block is located in the Yinggehai Basin with the acreage of 400 sq km. In 2020 bidding round, CNOOC will adopt flexible and preferential business arrangements with foreign enterprises on deep water areas and deep formation exploration in terms of exploration period, relinquishment, signature fee, participating interest and X factor in the hope of achieving the goals of expanding cooperation with foreign enterprises and enhancing foreign investments in China offshore oil and gas exploration and development. Data room will be available from 18 May to 30 September 2020. Closing date for bid is 31 October 2020. For details please contact: Contact: Ms. Zhang Lei, Outbound Cooperation Management Division, Exploration Department, CNOOC No.25, Chaoyangmenbei Dajie, Dongcheng District, Beijing, 100010, P.R. China Tel: (86-10) 84521499   Fax: (86-10) 64011987 E-mail: [email protected]

CNOOC issued announcement of notification for 2020 bidding blocks China offshore on 18 May 2020. In 2020, CNOOC offer total 15 exploration blocks, covering an area of 9,453 sq km, offshore China. Among them, one block is located in Bohai Bay, Bohai Gulf Basin, with the acreage of 127 sq km, one block is located in the East Sea Basin with the acreage of 1,784 sq km, 10 blocks are located in the Pearl River Mouth Basin with the acreage of 5,890 sq km, two blocks are located in the Qiongdongnan Basin with the acreage of 1,252 sq km, and one block is located in the Yinggehai Basin with the acreage of 400 sq km. In 2020 bidding round,

The Ethiopian authorities are promoting the country’s open acreage which is available to companies for direct negotiations. Petroleum contracts are in the form of Model Production Sharing Agreement of 1994 between the government of Ethiopia, represented by the Minister of Mines and Energy, and a contractor. The contracts have an initial exploration term of four years and an optional two year term, with two possible further exploration periods of two years (4+2+2). The development and production period is of 25 years. The minimum exploration and expenditure obligations are negotiable. The signature and production bonuses are also negotiable. The income tax is 30%. For further details, interested companies are invited to contact: Mr. Ketsela Tadesse Head of Petroleum Operations Department Ministry of Mines & Energy 486 Addis Ababa, Ethiopia Phone: + 251 11 646 12 09 Fax: + 251 11 646 34 39   The available blocks as of September 2018 are understood to be as listed below. There are 21 available blocks. Total open acreage amounts to 556,021 sq km, all onshore. Open blocks       Block Name Area (sq km) Situation Block Basin Afar 24,601 onshore Afar Basin Afar Area 63,038 onshore Afar Basin Area 4 3,679 onshore Amhara Massif Block 01 12,207 onshore Ogaden Sub-basin (Somali Basin) Block 02 12,232 onshore Ogaden Sub-basin (Somali Basin) Block 05 18,299 onshore Ogaden Sub-basin (Somali Basin) Block 06 12,232 onshore Ogaden Sub-basin (Somali Basin) Block 07 12,254 onshore Ogaden Sub-basin (Somali Basin) Block 18 12,232 onshore Ogaden Sub-basin (Somali Basin) Block 19 6,466 onshore Ogaden Sub-basin (Somali Basin) Block 21 6,093 onshore Mudugh Sub-basin (Somali Basin) Block AB2 12,069 onshore Amhara Massif Block AB3 12,069 onshore Amhara Massif Block AB5 12,109 onshore Amhara Massif Block AB6 12,109 onshore Amhara Massif Block AB8 12,135 onshore Abbay (Blue Nile) Basin Block AB9 12,128 onshore Abbay (Blue Nile) Basin Gambela 157,100 onshore Amhara Massif Metema 29,827 onshore Mekele Basin North West 82,538 onshore Mekele Basin Omo 30,604 onshore Amhara Massif

Ethiopia, Afar (Gewane-El Wiha)

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

On 15 May 2018 Union Jack Oil Plc announced that it, along its partner Humber Oil and Gas, had each agreed to acquire a 16.25% interest in PEDL 201 and a 12.5% interest in PEDL 181 from Celtique Energie for a payment of GBP 7,500 for each consideration. T

On 19 March 2019, Delek Drilling Ltd Partnership announced that it had reached agreement with Noble Energy Mediterranean Ltd whereby Noble will transfer a 25% interest and operatorship of the Alon D (367) offshore exploration licence to Delek’s wholly-owned subsidiary Ithaca Energy Inc. Noble will also transfer its remaining 22.059% interest to Delek Drilling effectively ending its participation in the licence. The transaction is subject to receipt of all necessary approvals, including that of the Israeli Petroleum Commissioner. Following completion of the transaction, the partners in the licence will be Ithaca Energy (25%, operator) and Delek Drilling (75%). Noble Energy and Delek Drilling had been awarded a 32 month extension for the offshore Alon D (367) licence by the Ministry of Energy on 21 August 2017. The licence had originally expired in March 2016 but an appeal was subsequently launched by the joint venture partners. The extension was conditional on a number of terms: (i) the partners must clarify to the Petrolum Commissioner that they acknowledge that there are still circumstances preventing drilling in the area, (ii) the partners must undertake an environmental survey in the next 18 months and (iii) the partners must ratify their commitment to drilling. Noble was originally awarded the 400 sq km licence in the Levantine Basin on 1 March 2009. There are currently no exploratory wells drilled within the contract.

Balang International, part of the China Changcheng Natural Gas Power Group, has purchased Repsol’s upstream assets in the country. The deal involves 41% of the discovered contingent resources in the Stanley, Elevala-Ketu, Ubuntu and Puk Puk/Douglas g&cond. fields in Western Province of up to 2,5 Tcf of gas and 70 MMb cond.

Azinor has received an LoI for the acquisition of non-operated interests in P2317 (Goose prospect), P2165 (Boaz prospect) and P2179 (Hinson prospect). Preparations for drilling the wells are underway.

United Kingdom, P2179

Regarding Cameroon’s 2018 licensing round opened in January, state SNH has removed the obligation to purchase CGG improved data as a condition for participating, which could result in smaller companies taking part as well. Offers are being accepted until 29 June, with winners to be announced on 18 July. The eight blocks on offer can be viewed here.

Regarding Cameroon’s 2018 licensing round opened in January, state SNH has removed the obligation to purchase CGG improved data as a condition for participating, which could result in smaller companies taking part as well. Offers are being accepted until 29 June, with winners to be announced on 18 July. The eight blocks on offer can be viewed here.

On 19 March 2019, BW Offshore announced that’s its wholly owned BW Energy Gabon SA had entered into an agreement with the Gabon Oil Company (GOC) for the acquisition of a 10% interest in the Ruche EEA (Dussafu) production sharing contract. Tullow Oil Gabon has also exercised its back-in right. The GOC transaction is subject to the fulfilment of certain conditions precedents, including approval from government. It entails payment by GOC of USD 28.5 million, representing a reimbursement equivalent to 10% of development and production costs from April 2017 and to-date. Upon completion of the initial agreement BW Energy will operate the permit with an 81.67 % interest, Panoro Energy holds an 8.33% interest and GOC holds a 10% interest. GOC's interest will be retroactive from the date of First Oil, being 16 September 2018, and GOC will assume 10% of historical costs as authorised by government. GOC will contribute to cash calls for the development and production of the field and adhere to the joint operating agreement and lifting arrangements that are currently in force between the contracting parties. Tullow has exercised its back-in right. Upon completion of both agreements the interests in the licence will be as follows: BW Energy will operate the permit with an 73.5% interest, Tullow will hold a 10% interest, Panoro Energy a 7.5% interest and GOC a 9% interest.

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

Bridge Petroleum 5 Ltd has acquired Burgate E&P Ltd, Comtrack (UK) Ltd and Simwell Resources Ltd’s interest in block 113/27d (P2076), which contains the Castletown gas discovery. Prior to the deal with Bridge Petroleum, the three partners were seeking to farm-out Castletown to raise funds to drill an appraisal well. Well 113/27-2 was drilled in 1988 by ESSO which discovered Castletown however the gas accumulation in the Triassic sandstones was considered too small to develop. A new evaluation, using depth migrated 3D seismic data, indicated that the well was drilled down flank and through a major fault causing a large gas accumulation remains to be proven up-dip. The Mercia Mudstone Group provides a regional seal which attains a thickness of 1,000 m across the basin. Gas charge comes from the Carboniferous Coal Measures which underlie much of the basin. Following completion of the deal interest and operatorship of P2076 is held solely by Bridge Petroleum 5.

United Kingdom, P2076

1st of 2 wells planned in SK-408 off Central Luconia, Sarawak, P&A results n/a mid-Feb '20, PV Drilling VI JU. Target M. Miocene Cycle IV/V carbs. SapuraOMV (op), partners Petronas + Shell.

Kesidang 1, nfw. (SapuraOMV 40% op, Shell 30%, Petronas 30%) in SK-408. P&Ad, No well results yet. Targeted the Middle Miocene Cycle IV/V carbonate.

Conventional oil prospect in PEDL 253 in Central Lincolnshire, E. Midlands, understood susp. o&g shows at TD 2,133m, target Basal Westphalian sst poorly-developed. A sidetrack is not ruled-out. Egdon (op), partners Montrose, UJO + Humber O&G.

United Kingdom (Forties-Montrose High (Central Graben)) Montrose

On 25 April 2019, the ANP approved the discovery evaluation plan request by Geopark for the 1-PRC-001D-BA (1-GPK-004D-BA) new-field wildcat (NFW) suspended with oil shows in the REC-T-128 block during mid-January 2019.   The operator plans to conduct an extended well test (EWT) in the coming months. Geopark suspended with oil shows the 1-PRC-001D-BA (1-GPK-004D-BA) new-field wildcat (NFW) in the REC-T-128 block during mid-January 2019.  The NFW reached a final total depth (TD) of 2,569 m.  The operator filed an oil show report with the ANP on 15 January 2019. The NFW was spudded on 12 December 2018.     The well had a proposed total depth (PTD) of 2,563 m.  The Lower Cretaceous Agua Grande Formation and the Jurassic Sergi Formation were the primary targets.  The NPW is located in the east central area of the block approximately 3.1 km south south-east of the 1-CAJ-1-BA plugged and abandoned dry by Petrobras in 1969 in the now, northerly adjoining REC-T-116 block. Geopark is operator with 70% working interest in the ANP Round 13 contract and Geopar-Geosol has 30% working interest.

GeoPark Holdings Ltd - Reconcavo Basin - REC-T-128 block - suspended oil discovery 1-PRC-001D-BA (1-GPK-004D-BA)

A preliminary agreement was signed 20 Jan '20 with ANPG for BP to secure rights to block 18/15, covering the original block 18 area bar devt rights therein. This agreement defines general terms for a risk service contract. The 4,600-sq km block straddles the Congo Fan, Kwanza + Lower Congo basins. Upon award, partnership to be BP (op), Sonangol Sinopec Intl + Sonangol.

A preliminary agreement was signed with ANPG for BP (op), Sonangol Sinopec Intl + Sonangol to secure rights to block 18/15. This agreement defines general terms for a risk service contract. The 4600km² block straddles the Congo Fan, Kwanza + Lower Congo basins.

It was announced on 19 December 2019 that Guney Yildizi Petrol Uretim Sondaj Mut. Ve Tic. A.S. has been awarded the N47-B exploration licence (Zagros Province) on 10 December 2019 for a period of five-year. The licence, covering an area of 471 sq km, is located towards southeast of the country and Guney Yildizi will be 100% owner and operator of the licence. The company had filed the application on 19 March 2019.

Guney Yildizi Petrol Uretim Sondaj Mut. Ve Tic. A.S. has been awarded the N47-B exploration licence (Zagros Province)

On 15 February 2018, Hunt signed the contract with Perupetro and was awarded three new technical evaluation agreements (TEA) contracts for the LXVI, LXVII and LXVIII blocks in the Ucayali Basin. The TEA contract can be requested in frontier areas with little previous exploration and is a way for an operator to explore an area with low financial commitments. If the results are positive, the operator then has preferential rights to convert the TEA to an exploration and production license contract. The blocks are located north of Camisea Block 57 and includes parts of the previous blocks 175, 189 and U-5. <P /><P />

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Petrobras has embarked on the (non-binding phase) sale of its equity in the Lagoa Parda field cluster (Lagoa Parda, Lagoa Parda Norte + Lagoa Piabanha fields) onshore Espírito Santo. Qualified interested parties will receive guidelines for the elaboration and submission of non-binding proposals and access to a virtual data room.

Brazil, Lagoa Parda Norte

PL 167, Utsira High, WD 113m, sidetrack of 16/1-30 S (TMD 2,140m / 2,057m TVD), 15m oil column in the Viking Grp (6m of sst layers), 0.2-1 MMcum oil recoverable. , commerciality to be determined, P&A at TMD 2,037m SS (1,952m TVD) on 19 Jul ’19, West Phoenix SS. Equinor (op), partners Lundin + Spirit Egy.

Norway, PL 167

Timor Gap is understood to b looking for partners in a work programme planned in its onshore application acreage in the Timor Basin. It is thought the offer pertains to block B application, although the company has also rights to blocks A + B, 1,000 sq km apiece.  Contact: [email protected].

Timor Gap is understood to b looking for partners in a work programme planned in its onshore application acreage in the Timor Basin. It is thought the offer pertains to block B application, although the company has also rights to blocks A + B, 1,000 sq km apiece. Contact: [email protected].

Bids are due today for the Erawan field in G1/61 and Bongkot field in G2/61. Chevron, PTTEP, Mubadala, Total + OMV prequalified for Erawan, and Chevron, PTTEP, Mubadala + OMV for Bongkot. Joint offers are a possibility.

Bids are due today for the Erawan field in G1/61 and Bongkot field in G2/61. Chevron, PTTEP, Mubadala, Total + OMV prequalified for Erawan, and Chevron, PTTEP, Mubadala + OMV for Bongkot. Joint offers are a possibility

PEDL 140, Misson Springs in North Nottinghamshire, TD 3,500m reached, >250m hc-bearing shale sequence encountered in the U&L Bowland Shale, significant gas indications in the Millstone Grit, L. Bowland + Arundian shales. IGas (op), partners INEOS, Egdon + eCORP.

Springs Road-1 PEDL 140, Misson Springs in North Nottinghamshire, TD 3,500m reached, >250m hc-bearing shale sequence encountered in the U&L Bowland Shale, significant gas indications in the Millstone Grit, L. Bowland + Arundian shales. IGas (op), partners INEOS, Egdon + eCORP.

G10/48, WNW of Wassana field in Gulf of Thailand, WD 52m, TD 3,169m, no significant hc shows in the target, presumably to be P&A’d and Mist JU off to the Wassana production area for 3 firm infill wells plus 1 contingent. KrisEnergy (op), partner Palang Sophon.

Montha-1 nfw G10/48, WNW of Wassana field in Gulf of Thailand, WD 52m, TD 3,169m, no significant hc shows in the target, presumably to be P&A’d and Mist JU off to the Wassana production area for 3 firm infill wells plus 1 contingent. KrisEnergy (op), partner Palang Sophon.

Available information indicates that Sonatrach drilled an exploration well in the Berkine Ouest / 404a block, Berkine Basin, south-east of the country. Operations at the well were concluded in February 2020 and it is understood that the well may have found hydrocarbons. The well is located around 5 km south east of the Rhourde Ech Chouil Sud-ouest 1 gas discovery operated also by Sonatrach. The Berkine Ouest exploration block was awarded to Sonatrach in 2010, it covers 1,409 sq km and is operated by the company with a 100% interest.

(Berkine B.), Berkine Ouest-3 exploration well, operated by SONATRACH (100%) in Berkine Ouest / 404a block, may have found hydrocarbons.

On 29 April 2020 Woodside Energy Ltd, a wholly owned subsidiary of Woodside Petroleum Ltd, was awarded retention lease WA-93-R, in the Exmouth Sub-basin, North Carnarvon Basin. The permit has been awarded for a period of five years and is scheduled to expire or be eligible for renewal on 28 April 2025. Work commitments have been assigned for the entirety of the permits validity, for a total estimated expenditure of AUD 100,000. Annual works have been scheduled, including a project feasibility review and a technology review. In the last permit year, an assessment of the appropriateness of preliminary engagement with third party infrastructure owners for the proposed development concept, is also required. The retention lease has been granted over part of the exploration license WA-430-P, and covers the Toro gas discovery, which was made in 2014. The field has estimated 2P recoverable reserves of 315 Bcf of gas and 300 Mbbl of condensate. The lease is one of two awarded from the same exploration license on this date, with WA-94-R also awarded. WA-93-R covers an area of 159.44 sq km and was awarded on 29 April 2020. Participants in the permit are Woodside Energy Ltd (70% interest and operatorship) and Mitsui E&P Australia Pty Ltd (30% interest).

(North Carnarvon B.) WA-93-R & WA-94-R blocks awarded to WOODSIDE (70% + op) & MITSUI (30%)

Announced on 22 January 2018, Angus Energy is farming in for 25% operator share of Balcolmbe Field licence PEDL244, by acquiring 18.75% and operatorship from Cuadrilla Resources and 6.25% from AJ Lucas Group for a combined consideration of GBPS 4 million (US$ 5.6 million) subject to OGA approval. Angus will also fund a well test program of the Balcombe-2Z (LR/30-5Z) horizontal well as soon as possible. PEDL244 covers 154 sq km on Weald Basin blocks TQ22a, 22c & 32b in West Sussex, and contains the Balcombe oil field discovered in Late Jurassic Kimmeridge micrite by Balcombe-1 (1986, Conoco, 1,731m). Cuadrilla and Angus were awarded PEDL244 under the 13th Landward Round in 2008, and successfully appraised by Balcombe 2 & 2Z in 2013. The partners believe it is a conventional oil accumulation most likely within a structural closure or combination trap in low porosity limestone that will not require fracking to produce. The appraisal drilling had extended delays to its planned flow testing, and experienced three months of local residents' protests. Permission to flow test was granted in May 2014 but lapsed in May 2017, however West Sussex County Council (WSCC) issued a new flow testing and monitoring permit on 9 January 2018, valid for three years. Pending approval of the Angus farm-in, PEDL244 partners are Cuadrilla Balcombe Ltd (75% + Op) and Lucas Bolney Ltd (25%).

Angus Energy is taking a 25% stake in PEDL 244 in the Weal basin, which hosts the Balcombe find, from Cuadrilla (->56,25% op, Lucas Bolney 18,75%).

Tap reports completion of the sale of its interests in prod. licence TL/2 (10%) + explo permit TP/7 (12.5%), total 800 sq km in the Barrow sub-basin, as well as its associated pipeline licences,  but still does not reveal the buyer (ref. DEA 18 Apr ’18). The sale was completed 18 Jun ’18.

Australia, TL/2

On 7 November 2018, Wintershall with 100% working interest was granted an official award for the CE-M-601 block in the offshore Ceara Basin through the ANP Round 15. On 29 March 2018, Wintershall was granted a preliminary award for the block. 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 an official award for the CE-M-601 block in the offshore Ceara Basin through the ANP Round 15.

GeoPark has farmed-out a 30% interest in so far wholly-owned POT-T-747 + POT-T-882 blocks to Geopar – Geosol Participações, move approved by ANP on 30 May. Both blocks total 60 sq km in the Potiguar onshore.

GeoPark (->70%) has farmed-out a 30% interest in so far wholly-owned POT-T-747 + POT-T-882 blocks to Geopar – Geosol Participações.

PetroChina - Xinjiang has made a significant discovery in the Junggar Basin. Gaotan 1, a NFW located in the south margin of the basin, tested 8,500 b/d of oil and 11 MMcf/d of gas, under wellhead pressure of 32.4 Mpa, on 6 January 2019. The successful result indicated great exploration potential in this area. A few wells have been drilled in this area with oil tested from the Cretaceous and Tertiary clastic rock, but without commercial value. Gaotan 1 is believed to achieved commercial oil and gas flow from the deeper formations. In December 2018 PetroChina made an oil discovery in the Junggar Basin. Shatan 1 tested 190 b/d of oil from 5,344 to 5,375 m in the Permian Wuerhe Formation through a 3 mm choke after fracking, then flowed 126 b/d through a 2.5 mm choke. The well also encountered good oil shows in other formations during drilling, such as Triassic Baikouquan and Karamay formations. The well is drilled in the Shawan Sag, geologically, it is very similar to the Mahu Sag where PetroChina has approved a giant field. It is expected to find another similar size of field in the Shawan Sag area. The Junggar Basin is one of the key exploration and production base for PetroChina. The company has approved more than 25 oil and gas fields by 2018 with total of 22 bn bbls of oil and 6 Tcf of gas in place reserves. In 2018 PetroChina produced 11.47 million tons of oil (229,000 b/d) and 2.9 Bcm of gas (290 MMcf/d). The company plans to increase oil production to 260,000 b/d by 2020.

China (Western Uplift (Junggar B.)) Baikouquan

Ref. DEA 18 May ’18, Husky reports a successful explo well in block 15/33, WD 80m in the South China Sea SE of Hong Kong. Four oil-bearing zones totalling 70m were encountered, testing to follow, whereafter a 2nd well will be drilled.  Husky also plans 2 explo wells in nearby block 16/25 in 2H ’18.

Xijiang 34-3 (Pr) 2 (Husky 100%) in Block 15/33, a total of 70m of pay across four oil-bearing zones. WD around 80m.

P2189 / block 29/4e, TD 3,750m in Sep ‘17, light oil and gas-cond in the Paleocene + Cretaceous, re-entered for testing, ops terminated early Nov ’18, Blackford Dolphin SS.

P2189 / block 29/4e, TD 3,750m in Sep ‘17, light oil and gas-cond in the Paleocene + Cretaceous, re-entered for testing,

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

On 15 May 2018 Union Jack Oil Plc announced that it, along its partner Humber Oil and Gas, had each agreed to acquire a 16.25% interest in PEDL 201 and a 12.5% interest in PEDL 181 from Celtique Energie for a payment of GBP 7,500 for each consideration. T

Hitherto unreported, Oranto and 10% partner ZCCM Investments Holdings were granted blocks 17 + 27 on 27 Jul ’18. Block 17 covers 21,149 sq km in the Western Basin, while block 27 is 8,408 sq km in the Luangwa Basin. Meanwhile at the end of July, ZCCM merged its block 08 into its block 01, the latter now some 13,250 sq km in the Western Basin.

Oranto Petroleum acquired 90% interest in Blocks 17 and 27. The remaining 10% will be controlled by ZCCM Investment on behalf of the Zambian govt.

W&T Offshore was the successful bidder to acquire Cobalt Energy's entire interest in the Heidelberg Field, according to reports in mid-March 2018. Heidelberg, which encompasses Green Canyon blocks GC 859 (G24194), GC 903 (G24197) and GC 904 (G26346). Tracy Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "We are pleased that W&T was the successful bidder on this quality asset that meets all of our acquisition criteria. It is being acquired at an attractive valuation and will contribute solid production and reserves, as well as offer upside potential. Finally, this transaction meets an additional objective of being accretive to W&T on a flowing barrel of production." The transaction is anticipated to close in April 2018. Gross production from the Heidelberg Field totalled 33,513 bo/d and 16.7 MMcfg/d (36,300 Boe/d) in February 2018. Cobalt's production from the field, net to its interest, was 2,749 bo/d and 1.4 MMcfg/d in February 2018 (~3,000 boe/d from five wells). The wells flow to the Heidelberg Spar, which is located in GC 860. Prior to the closing of this transaction, equity in GC 859, GC 903 and GC 904 is currently shared between Anadarko US Offshore (44%), Statoil USA E&P (12%), Eni Petroleum US (12.5%), Cobalt GOM #1 (9.375%), ExxonMobil (9.375%) and Marubeni Oil & Gas (USA) (12.75%).

W&T Offshore made the top offer of US$31MM for 9, 375% Cobalt's share in the Anadarko-operated Heidelberg field.

Bidding closes today on 10 blocks totalling 33,200 sq km (230-8,000 sq km apiece) across the Galilee, Eromanga, Bowen-Surat and Carpentaria basins, released under the PLR2019-2 blocks offer:

Bidding closes today on 10 blocks totalling 33,200 sq km (230-8,000 sq km apiece) across the Galilee, Eromanga, Bowen-Surat and Carpentaria basins, released under the PLR2019-2 blocks offer:

Premier Oil has entered into a sale and purchase agreement to sell its interests in Licences PL089 and P534, containing the Wytch Farm field, to Perenco UK on materially the same terms as have been previously disclosed in an announcement released on 12 September 2017 and in a trading update released on 16 November 2017. These include unchanged cash consideration of US$200 million and the release of Premier from letters of credit totalling approx. US$75 million.Wytch Farm oil field (Source: Perenco) Original article link Source: Premier Oil

United Kingdom (Dorset Sub-basin (Wessex B.)) Wytch Farm

Repsol continued offering a farm-in opportunity in the Andaman III PSC, located in offshore North Sumatra Basin, with a data room open in September-October 2018. The company is targeting to drill a commitment exploration well in the block in late 2019, targeting the Rencong prospect. The Rencong prospect is a large, faulted four-way closure. The main fault block has been estimated to contain prospective resources of around 1.8 Tcfg and 30 MMbc, likely within Upper Oligocene to Lower Miocene Parapat sandstone reservoirs. In late November 2017, the company completed a commitment 3D seismic survey that covered over than 3,000 sq km in the block. The survey, acquired using Elnusa’s “Elsa Regent” vessel, was reported as the largest 3D seismic survey acquired in Indonesia at the time. Local media outlets in mid-September 2016 indicated that Repsol was seeking the necessary permits for the seismic acquisition. The operator reportedly held meetings with the local Aceh administration in preparation of the survey. The block is operated by Repsol’s fully owned subsidiary Talisman, with 100% interest. Prior to the acquisition by Repsol, Talisman had offered a farm-in opportunity in the block in 2014. At the time, several companies reportedly expressed interest in the highly prospective block. The Andaman III PSC, awarded in 2009, covers approximately 8,500 sq km and lies between shelf and over 1,300 m water depth. The block was offered during Phase II 2008 Tender Round under the regular tender mechanism and was officially awarded to Talisman (100%, operator) on 30 November 2009. The company paid a signature bonus of USD 7.5 million for the block. Firm commitments include G&G studies worth USD 2 million, acquisition of 2,500 sq km 3D seismic (USD 15 million) and drilling one well (USD 30 million). The seismic acquisition commitment was initially planned in 2010 but has been pushed back to a later date. The well commitment likewise has not been fulfilled. This deep water area in the southern Andaman Sea is vastly under-explored. Three exploration wells have been previously drilled within the current block boundaries. All are situated in the southern of the block, on the North Sumatran shelf. Samalanga 1 (P&A/dry - 1986) and Glumpang Minyeuk 1 (P&A/dry, 1987) were both drilled by Inpex, under the North Aceh Offshore PSC. EAO-B-1, which lies at the edge of the block, was also a dry hole. This well was drilled by Mobil in 1982 under the NSO PSC. Background Information Multiple play types exist in the area, including carbonate build-up on a basement high or on an anticline, syn-rift clastics with combined stratigraphic-structural trap component, inverted syn-rift clastics close to the Mergui Ridge, carbonate build-ups on flanks of the Mergui Ridge and Barisan fold-belt anticlines. Potential source rocks in the area in include the shales of the Eocene Parapat (lacustrine syn-rift), Oligocene Bampo, Lower Miocene Peutu/Belumai and Middle Miocene Baong formations. Potential reservoirs which could have commercial accumulations in this deepwater area are the Belumai carbonates and Parapat syn-rift sandstones. Shales of the Bampo and Baong formations would be the likely seals. Second exploration phase commitments (Year 4 to 6) include G&G studies (USD 0.6 million), acquisition of 500 sq km 3D seismic data (USD 3 million) and drilling one exploration well (USD 30 million). Directly east of the Andaman III block are Eni's Krueng Mane block, where two out of the planned three exploration wells were drilled in 2008/2009, and Zaratex's Lhokseumawe PSC. The 1985-1997 North Aceh Offshore PSC, operated by Inpex, previously covered a portion of this new block. This contract was held under moratorium for several years while Inpex attempted to re-negotiate the terms of the PSC to take into account the deep water nature of the area. Failure to settle the terms and the subsequent unjustifiable economics of exploration led to Inpex prematurely relinquishing the block. Vintage 2D seismic does exist, after Geco Prakla shot several 100 km lines over the area (North Sumatra Basin - Mergui Ridge) in 1995.

Indonesia, Andaman III PSC

On 31 July 2019, Eni SpA and BP plc announced that they had signed an exploration and production sharing agreement (EPSA) with the Ministry of Oil and Gas for Block 77. The block covers an area of >2,700 km and is located 30 km to the east of Block 61 (Khazzan-Makarem Gas Field). Eni Oman (a wholly owned subsidiary of Eni SpA) will act as operator during the exploration phase and both companies will take a 50% share.  The two companies had entered into a Heads of Agreement (HoA) for the block in January 2019. Block 77 contains a number of existing discoveries and fields including Qarn Alam, Ghaba North and Saih Nihayda Southeast.

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

63/94 Pruchnik-Pantalowice contract, enclaved within block 21/2001/p Zalesie-Jodlowka-Skopow, Outer Carpathian Foredeep in SE Poland, TD 1,969m reached, target gas in Miocene sandstones, testing began in early Jan '20.

Pruchnik-37K appr 63/94 Pruchnik-Pantalowice contract, enclaved within block 21/2001/p Zalesie-Jodlowka-Skopow, Outer Carpathian Foredeep in SE Poland, TD 1,969m reached, target gas in Miocene sandstones,

Panyu 4-8-1 (PY 4-8-1) was suspended (results TBC) in early November 2018 after having been spudded in mid-October 2018 using the "Haiyangshiyou 943" jack-up. The oil exploration well was likely to be targeting the Zhujiang and Zhuhai formations. Panyu 4-8-1 is in the CNOOC operated Xijiang 25 Block in the offshore Pearl River Mouth Basin.

Not Found

BSOG is looking to scale-down its involvement in the XIII-Pelican & XV-Midia licence from 70% to around 50%, other partners being Petro Ventures Europe + Gas Plus Intl. The 4,207-sq km acreage contains the Ana + Doina field devt project (in the XV-Midia West block), first production in 2021. Contact: [email protected].

Romania (Black Sea B.) XIII-Pelican op. by EBRD (35%), CARLYLE (35%), PETRO VENT (20%), GAS PLUS (10%), BSOG is looking to scale-down its involvement in the XIII-Pelican & XV-Midia licence from 70% to around 50%, other partners being Petro Ventures Europe + Gas Plus Intl. The 4,207-sq km acreage contains the Ana + Doina field devt project (in the XV-Midia West block), first production in 2021.

According to official reports in late-January 2020, Equinor and Shell have completed a joint acquisition of 49% participating interest on the Bandurria Sur block from Schlumberger’s Argentinean subsidiary, SPM Argentina, for USD 177.5 million from each company. State company YPF remains as the operator on the block with 51% stake, while Equinor and Shell each holds 24.5% equity with effective date of 1 January 2020. In a separate transaction, Equinor and Shell have also reached a preliminary agreement to acquire additional 11% interest from YPF (5.5% for each company). Bandurria Sur block covers 228.5 sq km of land in the Neuquen Embayment part of the Neuquen Basin and located in one of the most active areas of unconventional development in Neuquen Province. On the southern side, the block is situated directly next to YPF and Chevron’s Loma Campana block where the best producing Vaca Muerta shale oil field of the same name is located. On the eastern side, it is situated directly next to YPF’s La Amarga Chica block where the operator and its Malaysian state partner Petronas are currently in the development phase on their Vaca Muerta shale oil project. In addition, the block shares a border on the western side with Shell and YPF's Bajada de Anelo block, where the state company reportedly intends to develop shale oil in 2020 as part of its 1.6 billion investment plan for 2020 to 2021. Bandurria Sur block itself is currently in the late pilot phase of development that began in 2017 with latest daily production of 8.3 Mbo/d and 15 MMscf/d in December 2019. Background Information The Bandurria block was originally held by YPF (operator with 54.54%) with partners Wintershall (27.27%) and Pan American Energy/PAE (18.19%), before it was divided into three areas in July 2015, where YPF then received the designated area of Bandurria Sur with 100% equity before the farm-out to Schlumberger in October 2017. As part of a larger agreement between YPF and the Neuquen Province government in October 2016, YPF received a validity extension to execute a pilot project on the block for five years until July 2020.

Equinor and partner Shell have jointly acquired Schlumberger's 49% in the Bandurria Sur block in the Vaca Muerta play, for US$177,5 MM. YPF holds the remaining 51%, from which 11% is under a prelim. agreement for sale to Equinor and Shell, leading to 30% each. The block is in the late devt pilot phase, currently yielding ab. 10,000 boe/d.

On 29 November 2018 the National Offshore Petroleum Titles Administrator (NOPTA) approved an option agreement, for Skye Resources Pty Ltd to acquire Quadrant Energy’s interest in exploration permits WA-155-P and TR/3, located in the North Carnarvon Basin.  The deal had been entered into by the companies on 23 October 2018. It was reported by NOPTA, that the agreement gives Skye Resources the option to acquire Quadrant’s interest in the permits.  The deal is pending final approval to be completed.  Quadrant is now owned by Santos after a successful takeover in November 2018. WA-155-P, which covers an area of 289 sq km, was awarded on 1 March 1981.  Quadrant holds a 71.5% interest, with joint venture partner Carnarvon Petroleum holding the remaining 28.5%.  Carnarvon has been looking to farm-out a portion of its interest in the permit.  WA-155-P contains the Outtrim discovery, which was made in 1984. TR/3 covers an area of 32 sq km and was awarded on 20 November 2001.  Quadrant Energy Ltd holds 100% interest in the permit.  TR/3 contains the Blencathra discovery, which was made in 1995.

Quadrant Energy Pty Ltd WA-155-P, TR/3, North Carnarvon Basin - option agreement signed with Skye Resources

Dráva 2 block, NE Croatia, Somogy-Dráva sub-basin, drilled 14-30 Nov '19, TMD 1,635m (1,598m TVD, Mesozoic), o&g reportedly encountered, testing planned end 2Q '20.

Croatia (Pannonian B.) Jankovac 1 op. by INA (100%) in Block DR-02, total depth 1635 m o&g reportedly encountered, testing planned end 2Q '20.

Talos intends to dilute its 100% stake in the Hershey subsalt Miocene prospect in Green Canyon blocks 326 (lease G34977), 327 (G34978), 370 (G34980) + 371 (G34981), only weeks after taking over from ExxonMobil (DEA 20 Sep '19).

United States, not found

Discoveries announced 25 May '20: - Moskvichevskaya Zapadnaya-1 nfw, Izbynskaya structure west of Moskvichevskoye field in Pripyat Basin, spudded Dec '19, sidetracked, tested ~1,100 bo/d at 4,400m in sub-salt carbs. - Omelkovshchinskaya Severnaya-2, spudded 6 Apr '20, tested 365 bo/d from 2,660m in Middle Frasnian Sargayevskiy carbs. Combined reserves of both 18 MMbo, to be placed on stream this summer.

Omelkovshchinskaya Severnaya 2, (BelorusNeft 100%) tested 365 bo/d from 2,660m in Middle Frasnian Sargayevskiy carbs. Reserves 18 MMbo, to be placed on stream this summer.

Industry rumours suggest Eni may be looking to opt out of Pakistan, where it has a number of up- and downstream assets. These include the Bhit/Badhra (operated), Tajjal + Kadanwari fields and interests in 6 onshore blocks, Gambat, Latif, Mubarak, Sawan, Sukhpur + Zamzama. The offshore Indus-G 2265-1 EL, 5,928 sq km in Indus Fan deepwaters, was due to be relinquished at the end of its explo term on 31 May '20. There is also a 10MW solar plant at Bhit.

Industry rumours suggest Eni may be looking to opt out of Pakistan, where it has a number of up- and downstream assets. These include the Bhit/Badhra (operated), Tajjal + Kadanwari fields and interests in 6 onshore blocks, Gambat, Latif, Mubarak, Sawan, Sukhpur + Zamzama.

According to IHS Markit sources, Tullow Oil is reportedly about to be a partner of the South African Strategic Fuel Fund (SFF) in South Sudan's Block B2 under the NILE-ORANGE new venture. Details of the agreement have not yet been disclosed, but it is known that Tullow showed interest on several South Sudanese blocks before. In late 2019, SFF's GCOO Kholly Zono reportedly said to South African local media that some international companies have expressed interest in sharing/offloading some equity in Block B2. Mr Zono also reported that exploration cost was estimated at USD 48 million to be spent in six years. As of late 2019, the South African company was looking for partners to explore its awarded Block B2 in South Sudan, ministerial sources reported. On 6 May 2019, the South African state-owned Strategic Fuel Fund (SFF) was awarded Block B2 in Muglad/Melut basins, South Sudan. SFF will operate the block in partnership with Nilepet with the 90% and 10% interest respectively. See here for further details.   2019 IHS Markit 1

According to IHS Markit sources, Tullow Oil is reportedly about to be a partner of the SFF (South African Strategic Fuel Fund) in Block B2 under the NILE-ORANGE new venture. Details of the agreement have not yet been disclosed.

In late April 2020 Europa completed a deal with a company called Four Trees Energy Limited in DL 003 which contains the West Firsby field. Four Trees has acquired a 1% interest in the licence. The West Firsby field is located onshore UK, approximately 15 km north of Lincoln, and produces through two wells at a rate of 60 bo/d. West Firsby was discovered by Enterprise Oil in January 1988. Appraisal wells West Firsby-2 and 3 delineated the field's eastern part. It came onstream in 1991 and at the time of first production was estimated to produce for five to seven years. Interest in DL 003 is held by Europa Oil and Gas Limited (99% + operator) and Four Trees Energy Limited (1%).

Europa completed a deal with a company called Four Trees Energy Limited in DL 003 which contains the West Firsby field.

PL 199, south of Kristin in central Norwegian Sea, WD 278m, P&A’ing gas-cond find, TMD 4,944m (4,880m TVD, Tilje fm),  10m column in the Tofte fm which totals ab. 140m, of which effective reservoir sst of 120m, poor-to-moderate reservoir quality. The Garn and Ile fm are water-wet. The secondary target (Lange fm) features several gas-bearing sst layers (1-5m ea.), poor reservoir quality. 6-25 MMboe recoverable, devt + tie-in to the Kristin field to be evaluated. West Phoenix SS. Equinor (op), partners Petoro, ExxonMobil + Total.

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

Sacgasco Ltd announced on 19 November 2018 that it had signed an exclusive option agreement to acquire all the issued shares in RL Energy Pty Ltd.  Under the terms of the deal, Sacgasco will initially make a payment of AUD 200,000 cash and 2 million Sacgasco shares to the RL Energy shareholders.  An exclusive option is then to be exercised, by 30 January 2019.  Once this is complete, Sacgasco will pay a further AUD 25,000 and 4 million Sacgasco shares to the RL Energy shareholders. RL Energy had previously entered an agreement to farm-in, for up to 60% interest into exploration permit PEP 11, located in the Sydney Basin.  As part of the acquisition by Sacgasco, it will assist in the lodgement for and environmental approval for 3D seismic over the permit, which is part of RL Energy’s farm-in commitments, at an estimated cost of AUD 326,000. Under the terms of the farm-in agreement, RL Energy can earn an initial 5% interest by arranging environmental proposals for a new 3D seismic survey over the permit area.  RL Energy can then earn up to a further 55% by funding Advent Energy’s share of a 500 sq km 3D seismic survey, up to a capped amount of AUD 4 million.  The seismic acquisition is under the work programme for the permit and is scheduled between February 2020 and February 2021.  It was reported that joint venture partner Bounty Oil and Gas NL supports the farm-in.  However, it has been subsequently reported, in mid-October 2018 that operator Advent Energy Ltd, had issued a notice to joint venture partner Bounty Oil and Gas it was exercising an option to acquire 100% interest in exploration permit PEP 11 as it is in default of payments for a number of outstanding costs.  Bounty reports that it currently retains its 15% interest, and that it was conducting discussions with Asset Energy around the disputed cash calls. PEP 11 covers an area of 4,573 sq km and was awarded on 24 June 1999.  Participants in the permit are currently Asset Energy Pty Ltd, a wholly owned subsidiary of Advent Energy, 85% and Bounty Oil and Gas 15%, though this is being disputed.  RL Energy has the option to farm-in for up to 60% interest. .

Sacgasco Ltd announced on 19 November 2018 that it had signed an exclusive option agreement to acquire all the issued shares in RL Energy Pty Ltd.

In February 2019 Beach Energy Ltd reported that it had reached a deal with Santos Ltd to align several assets within the Bonaparte Basin.  Under the terms of the agreement, the companies will align interest in four permits: NT/P82, NT/P84, NT/P85 and WA-454-P.  The interests in all four permits will become Santos (50% and operator) and Beach Energy (50%).  Beach Energy holds its interest through wholly owned subsidiary Lattice Energy. In NT/P85, no change to interests is required, while in NT/P84 the interests will remain the same, but Santos will be assigned operatorship.  In NT/P82, which is currently held 100% by Santos, Beach will acquire a 50% share.  In WA-494-P, Beach holds 100% at the time of the deal and so Santos will take 50% and become operator of this permit. No cash consideration is to be paid in the deal, but Santos will make a payment of USD 2.7 million covering the acquisition and processing costs of the Bethany 3D survey, which was completed in 1H 2018, with processing now ongoing.   Santos operated the survey, which was acquired over exploration permits NT/P85 and NT/P82 on behalf of the NT/P85 joint venture. NT/P82, NT/P84, NT/P85 and WA-454-P cover a combined area of 24,900 sq km within the Bonaparte Basin.  Once the transaction is finalised, holdings of the four permits will become Santos Ltd (50% + Operator) and Lattice Energy (50%).

Beach is acquiring a 50% stake in the NT/P85, NT/P84, NT/P82 and WA-454-P blocks from Santos (->50% op).

The Agence de Gestion et de Coopération entre la Guinée-Bissau et le Sénégal (AGC) is the joint commission established by Senegal and Guinea Bissau to manage their joint maritime zone. One of AGC’s tasks is to offer open exploration acreage blocks in the Joint Exploration Zone (JEZ). Note about the Joint Exploration Zone (JEZ) Senegal's former President Abdou Diouf and his Guinea-Bissau counterpart President Joao Bernardo Vieira signed an agreement on 12 June 1995 settling the maritime border dispute in southern Senegal and northern Guinea Bissau. A Joint Exploration Zone (JEZ) for hydrocarbons was established in the region, which encloses Senegal’s Dome Flore oil accumulation. The Agence de Gestion et de Cooperation (AGC) was set up in 1996 to administer the area. The resources split for fisheries is 50% Guinea-Bissau / 50% Senegal. The resources split for hydrocarbons is 15% Guinea-Bissau / 85% Senegal. The licensing authority is the AGC. Interested parties should contact the address below. Agence de Gestion et de Coopération 122, Avenue André Peytavin PoBox 11195 Dakar Peytavin, Sénégal Téléphone : +221 33 849 1349 Fax : +221 33 821 8702 Email: [email protected]   Contact person for petroleum rights Mr. Boucar Faye Email: [email protected]   The available blocks as of April 2020 are listed in the table below. No block is available. There was no change from the previous list.

The Agence de Gestion et de Coopération entre la Guinée-Bissau et le Sénégal (AGC) is the joint commission established by Senegal and Guinea Bissau to manage their joint maritime zone. One of AGC’s tasks is to offer open exploration acreage blocks in the Joint Exploration Zone (JEZ).

It was reported in November 2018 that Mari Petroleum Company Ltd (MPCL) has acquired operatorship of Block 28 EL (Sulaiman Fold Belt) onshore licence from Oil and Gas Development Company Ltd (OGDCL) with effect from 31 July 2018. MPCL holds 95% interest in the licence whereas remaining 5% is held by OGDCL. The licence covers an area of 5,833 sq km and it is located in the Balochistan province. MPCL had farmed-in in Block 28 EL by acquiring Tullow Pakistan (Development) Ltd’s full 95% working interest with effect from 8 June 2018.   Background Information The Block 28 EL licence was originally awarded to Tullow Oil on 14 January 1991 – the company had 95% interest in the block whereas the remaining 5% was held by OGDCL. Operatorship of Block 28 EL was changed from Tullow Oil to OGDCL with effect from 19 July 2016. MPCL announced on 19 July 2017 that it signed the Head of Terms (HoT) agreement with Tullow Pakistan (Development) Ltd for acquiring Tullow’s entire working interest in three onshore blocks in Pakistan – Bannu West, Block 28 and Kalchas blocks. MPCL acquired Tullow Pakistan (Development) Ltd’s full 95% working interest in Block 28 EL with effect from 8 June 2018, as a result, the revised equity split was as follows: OGDCL (5%, operator) and MPCL (95%).

Pakistan, Block 28 EL

On 20 July 2020 Strike Energy Ltd reported that it has agreed terms with Talon Petroleum Limited to farm out 45% non-operated interest in the Walyering exploration permit EP 447, located in the Perth Basin. The agreement includes the formation of an unincorporated joint venture for the appraisal and future development of the Walyering field. Talon will receive interest in the license in return for a USD 6 million free carry in the upcoming appraisal well. The farm out completion remains subject to the execution of definitive transaction documentation and ministerial approval. Talon will pay the first USD 6 million of the Walyering appraisal well, up to a total gross USD 9 million spend, with all costs post this to be incurred on a pro-rata basis. The company has also issued a five year right of first refusal if Strike commence the marketing of Ocean Hill for farm out. Farming out the Walyering field will accelerate the appraisal drilling into CY2021, with Strike adding the Walyering well into its Perth Basin drilling programme, which will likely realise a potential cost saving. The Walyering field was discovered in 1971 and produced a total of 261 MMcf of gas from the Lower Jurassic Cattamarra Coal Measures over a four-month period before the reservoir was considered depleted and production ceased. Conventional sandstone reservoirs of Jurassic age, similar to the Gingin West and Red Gully gas and condensate trend, have been identified in the permit area over a structure area of approximately 10 sq km. It’s considered that original drilling failed to target the highs due to poorly positioned 2D seismic data. The field is located in close proximity to existing infrastructure and existing industrial gas users. Strike reported that the farm out is inline with the company's strategy of accelerating production of large volumes of domestic gas in its Perth Basin assets, where a supply shortage is predicted in the mid to late 2020's. Successful appraisal drilling will prove up a commercial development, which may result in a material uplift in valuation of Strike's 1,853 sq km acreage across the Jurassic West Gas Play in the Cattamarra sequence. EP 447 covers an area of 1,108.21 sq km and is scheduled to expire on 22 February 2022. Current interest in the permit is Strike North West Pty Ltd (50% interest and operatorship) and Strike South Pty Ltd (50% interest). Once the farm in is complete, Strike will hold 55% interest and operatorship, and Talon Petroleum will hold 45% interest.

(Perth b.), EP 447 block, Strike has agreed to farmout a 45% non-operated interest in so far wholly-owned EP 447, 1,108 sq km onshore Perth Basin, to Talon Petroleum.

On 26 February 2020, Crown Point Energy reported it suspended as a gas discovery the Sur Rio Malargue 1001d new-field wildcat (NFW) in the Cerro de Los Leones block. The operator reported it tested a zone in the Tertiary Agua de Piedra Formation over a seven day period with an average flow rate of 3.5 MMcfg/d. The flow rates varied from 1.25 MMcfg/d to 3.54 MMcfg/d with the flowing tubing pressure (FTP) ranging from 760 psi to 1,060 psi through varying choke sizes of 6 mm to 12 mm. There was an average of 17 bw/MMcfg produced during the test period. The operator shut-in the well to analyze the test results. The NFW was spudded on 20 October 2019 and completed in late-January 2020 at a final total depth (TD) of 1,450 m measured depth (MD) and 1,353 m true vertical depth (TVD). The well had a proposed total depth (PTD) of 1,450 m. The NFW is located in the north central area of the northern block. Crown Point Energy holds 100% working interest in the Cerro de los Leones contract which is separated into two blocks, covering a total of 409 sq km in the Mendoza Province portion of Neuquen Basin. Background Information Crown Point Energy have previously identified several prospects with both unconventional (Vaca Muerta Formation) and conventional targets in Cerro de los Leones. To date there had been only one producing field in the block, namely the Vega del Sol field. The field produced oil and gas from the Lower Cretaceous Chachao Formation when it was discovered and put on-stream in 1995 before it was abandoned in the same year after attempts to improve recovery were unsuccessful. A redevelopment plan was approved in 2015 in which Crown Point planned to re-entered and re-test the Vega del Sol X-1 and Vega del Sol X-3 wells. The field produced 2.113 Mbo before it was ultimately shut-in again in 2016.

Sur Rio Malargue 1001D (Crown Point 100%) in N-C part of northern Cerro de Los Leones block, Mendoza, TMD 1,450m (1,353m TVD), 7-day test in the Tertiary Agua de Piedra averaged 3,5 MMscfg/d, well shut-in for evaluation.

Eni has farmed-out a 25% interest to BP and 20% to Mubadala in the Nour North Sinai Offshore block, 739 sq km in the offshore East Nile Delta Basin in WD 50-400m. The deal has been approved by the govt, resulting partnership Eni (op), 40%, BP 25%, Mubadala 20% + Tharwa 15%.

Egypt, Nile Delta (Dev)

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

Cooper Energy Ltd has opened a data room for parties interested in farming into its Gippsland Basin Gas Hub assets: VIC/L32, RL13, RL14, RL15 and VIC/L21. The assets that are available to interested parties include the Sole gas project and tie-in option from the Manta gas field. Cooper is hoping to acquire a partner in the assets, by farming out interest. In doing so Cooper reports that it should allow commercial alignment and create an optimum funding process across the Sole and Manta assets which will provide feedstock to the Orbost Gas Plant. The Sole gas field is contained within production licence VIC/L32, which is available as part of the farm-out. Cooper Energy currently holds 100% interest after completing a deal with Santos in April 2017. Santos received a total cash consideration from Cooper of AUD 81 million for the assets held in Victoria within the Gippsland and Otway basins. Cooper paid AUD 61 million upon completion of the deal and a further AUD 20 million upon the Final Investment Decision (FID) of the Sole Gas Project. Cooper Energy announced on 29 August 2017 that FID for the Sole gas project had been reached after a finance package was completed to fund the project. The package is worth around AUD 400 million which is large enough to support FID for the Sole gas project and also to finance other offshore and onshore Otway and Cooper Basin operations and required Gippsland Basin facility maintenance. The financing for the project, which was reported as commencing on 29 March 2017, initially saw Cooper aim to raise AUD 151 million to put towards the development of Sole. The full upstream development programme, which Cooper is wholly funding as the individual owner and operator, is expected to cost around AUD 355 million. The Sole field, discovered in February 1973, once developed and onstream, is expected to provide 25 PJ/yr (~23.5 Bcf/yr) to the southeast Australian market, via the Orbost Gas Plant that will process the gas.  All offshore works are expected to be completed by 31 May 2019 and first production in Q3 2019. Cooper Energy has reported a number of signings of gas sales agreements for gas from the Sole project. The Orbost Gas Plant was purchased by APA for AUD 20 million, with Sole reaching FID being one of the conditions of acquisition. There is also the option to process gas from Cooper Energy’s Manta gas field, as well as other fields in the region (pending a successful appraisal programme). APA has reported that the total cost for the acquisition and then subsequent upgrades and operations, is expected to be in the region of AUD 270 million. The Manta field, along with Basker and Gummy, is centred in VIC/RL13, and crosses adjacent VIC/RL14 and VIC/RL15. Gas from Manta could also provide feedstock to the Orbost Gas Plant pending a successful appraisal programme of the gas resources which is due to commence in 2019 with Manta 3 well (subject to approvals). If FID is subsequently reached, first production could be achieved by 2021/22. The fields produced around 8.6 MMbbl of oil between December 2006 and August 2010 and associated infrastructure is now being removed. Reinjected associated gas was will now be considered for a gas production phase upon Sole reaching FID. VIC/L21 contains the Patricia Baleen field and Sperm Whale discovery. Patricia Baleen was discovered in 1981 and produced around 18.8 Bcf gas between 2003 and 2005. The shallow reservoirs are now depleted and the wells were shut-in during 2008. Despite holding a depleted field, Cooper believes that the permit offers a significant access point for the Orbost Gas Plant for other, surrounding fields. A data room as been opened and Cooper has been in discussions with several interested parties. Parties interested in this opportunity should contact: David Maxwell, Cooper Managing Director    Tel: +61 8 8100 4900 Eddy Glaves, Commercial & Business Development Manager         Tel: +61 8 8100 4900 Don Murchland, Investor Relations    Tel: +61 439 300 932

Cooper Energy Ltd has opened a data room for parties interested in farming into its Gippsland Basin Gas Hub assets: VIC/L32, RL13, RL14, RL15 and VIC/L21. The assets that are available to interested parties include the Sole gas project and tie-in option from the Manta gas field.

Dommo Energia SA through a press release on 17 October 2017 indicated that it agreed to sell 30% of its 40% working interest to Azibras Exploracao de Petroleo e Gas Ltda in the BS-004 contract, Atlanta and Oliva production concessions.  The terms of the deal are for Azibras to pay the cash calls in arrears of approximately USD 33 million and contingent payments of USD 30 million.  The transaction is subject to various creditor, BS-004 contract partner, and ANP approvals.  Queiroz Galvao is operator of the BS-004 contract with a 30% working interest while partners were Dommo with 40%, and Barra Energia with 30%.  After formal approvals Queiroz Galvao will have a 30% working interest as operator, Azibras will have 30%, Barra Energia will have 30%, and Dommo will retain a 10% working interest.  The operator is preparing for production startup in the Atlanta production concession in 1st quarter 2018, delayed from 4th quarter 2017.  Azibras is a subsidiary of the Seacrest Group. On 10 November 2016 Queiroz Galvao reported its 3rd quarter 2016 earnings and highlighted the progress of the BS-004 contract, Atlanta production concession pilot production scheme.  The operator reported that the FPSO Petrojarl I arrival and installation would be delayed until 3rd quarter 2017 and first oil is now expected in the 4th quarter.  The delay of the FPSO’s arrival is due to modifications to the topsides.  The following information is the detailed information regarding the development project as reported in 2014.  Queiroz Galvao reported more recently that the project drilled horizontal sections in the two development wells of 750 m with 9 1/2” casing set.  The company gravel packed the completion sections and will utilize some innovative production techniques to produce the heavy oil similar to what has been utilized by Statoil in the Peregrino field and which it has many similarities except for being in deep water, 1,550 m. Queiroz Galvao reported on 17 December 2014 that it signed a contract with Teekay Offsore for a 30 Mbo/d capacity FPSO for its pilot production scheme for the Atlanta production concession.  The FPSO was originally contracted for USD 480,000/day, but reduced to USD 410,000/day in 2017, and will be utilized to start first production in the Atlanta Field by connecting two horizontal wells completed and tested in 2014.  The total cost through the pilot development phase of the project was reported to be USD 520 million.  First production for the unit was scheduled for mid-2016 after the ANP on 23 December 2014 granted the operator authorization to postpone production startup until 2016.  In 2015 the operator will contract for umbilicals and flexible lines to tie-in the two producing wells. The operator projects that the two current wells will produce approximately 25,000 bo/d and plans to drill a third producer for USD 100 million may be postponed due to the current oil price situation.  Queiroz Galvao has plans to tender for a definitive FPSO of 100 Mbo/d production capacity in 2017 that would come online in 2019 or 2020 with 10 additional production wells.  Dommo Energia SA, formerly OGX Petroleo e Gas SA and successor in bankruptcy Oleo e Gas Participacoes SA (OGPar), issued a press release on 19 September 2017 indicating that shareholders officially approved a corporate name change from OGX Petroleo e Gas SA to Dommo Energia.  The company recently emerged from bankruptcy.  OGPar has 25.89% of the equity in the company.   Dommo still operates two active contracts 100%, the BM-C-039 contract, Tubarao Martelo production concession and the BM-C-041 contract, Tubarao Azul production concession with the official ANP operator name changed to Dommo from OGPar on 20 September 2017.  The company also has a 40% non-operating working interest in the BS-004 contract, Atlanta and Oliva production concessions under the OGX Petroleo e Gas SA subsidiary name.  The official name changes were approved by the ANP on 20 September 2017.  Dommo, through OGX also has 6.22% equity in Eneva that is operating all of the gas producing and electrical generating assets in the Parnaiba Basin through various subsidiaries.  The company is in the process of decommissioning the Tubarao Azul field in 3rd and 4th quarter 2017 and will relinquish the contract once completed.  It also reported it may sell its 40% working interest in the BS-004 contract.   

Dommo Energia (->10%, Queiroz Galvao E&P 30% op, Barra Energia 30%) has agreed to sell a 30% working interest in the Atlanta heavy oilfield in BS-004 block to AziLat Petroleum for US$63 MM.

Brazilian operator Dommo Energia, formerly known as OGPar, which emerged from bankruptcy in August 2017, agreed to sell a 30% stake in the offshore BS-4 license including Atlanta and Oliva fields to AziBras Exploracao de Petroleo e Gas (Azimuth). Dommo had a 40% interest in BS-4 and now will retain 10% when the deal is complete. BS-4 is operated by Queiroz Galvao E&P (30%) with Barra Energia also holding 30% as a partner. The board of Dommo approved the deal, which is still subject to conditions and regulatory approval, according to the company on 18 October. US based Azibras committed to US$ 33 million capital expense for the block and a US$ 30 million contingency fee as well as covering some unspecified overdue cash calls. Dommo claims the deal will improve its cash position and capital structure. Located in the post salt Santos Basin, the heavy oil Atlanta and Oliva fields are in a water depth of about 1,500m. First production from Atlanta Field is expected in first quarter 2018. The floating production, storage and offloading (FPSO) unit for Atlanta is expected to eventually produce from 10 wells. Oliva is forecast to begin production by 2021 with estimated reserves of 300-400 MMbo. OGPar disclosed on 10 May 2017 that the company owed the operating consortium for Atlanta US$ 29 million and was trying to sell its 40% stake in the project. OGPar said it was trying to divest part of its share in Atlanta in order to pay its debt and avoid intervention by the ANP in the consortium. In March operator Queiroz Galvao announced the postponement of first oil from Atlanta to 2018. The delay is due to difficulties faced by the contractor, Teekay Offshore Partners in adapting the FPSO Petrojarl I, which will be used for the early production system. OGPar previously on 21 March 2017 confirmed its intent to farm-out part of its share in Atlanta Field and its intent to do so before first oil is produced in the field in early 2018. The first production phase for Atlanta is estimated to produce between 25,000 and 30,000 bo/d with the hookup of two or three production wells for extended well testing (EWT). The productive capacity of the wells is roughly 10,000 bo/d. Shell discovered Atlanta Field in 2001. The field is expected to reach peak production in 2021 of about 76,000 bo/d. The deepwater Atlanta Field has estimated proven oil recoverable reserves of 147 MMbo with a 2P estimate of 191 MMbo and 3P estimate of 269 MMbo.

Not Found

On 13 November 2017 Hague and London Oil (HALO) reported that the takeover of non-operated offshore licences from Tullow was completed. Consequently HALO is a producer of more than 2,500 boe/d, having 2P reserves in excess of 12 MMboe and more than 19 MMboe in contingent resource The table below shows Tullow’s assets and its participation interest: Asset Operator Tullow’s participation E10 ENGIE 30% E11 ENGIE 30% E14 ENGIE 30% E15c ENGIE 25% E15a Wintershall 4.69% E15b Wintershall 21.12% E18a Wintershall 17.6% F13a Wintershall 4.69% J9 NAM 9.95% K8 NAM 9.95% K11 NAM 9.95% K7 NAM 9.95% K14 NAM 9.95% K15 NAM 9.95% L13 NAM 9.95%   HALO was formed in 2012 and combined with Wessex Oil in 2014. The company’s portfolio is so far comprised of assets in the United Kingdom, Western Sahara, French Guyana and the Scattered Islands.  

Netherlands, J9

Pathfinder Energy Pty Ltd is seeking farm in partners to its entire, 100% owned portfolio located along the eastern border of a Lower Triassic trend, northeast of the Phoenix South and Roc discoveries: WA-479-P and WA-487-P (Rowley Sub-basin). Pathfinder initially opened the offer in 2014 with negotiable equity on offer along with the possibility of operatorship. Potential deals include a conventional type farm out with a carry-on activities and a cash component as a package deal, or individually. Pathfinder has 3D seismic surveys planned across the permits over the next two years to further define large prospects which are yet to be tested. Pathfinder is seeking partners to help fund the surveys and provide back costs associated with previous activity, with the option of earning further interest via subsequent, non-committed exploration drilling. Around 1,200 sq km of 3D seismic acquisition is currently planned across the permits which was scheduled by August 2018. A farm-in opportunity was also being offered for exploration licences WA-508-P and WA-509-P. However, the permits were cancelled on 1 November 2018 due to non-compliance of the guaranteed work programme of 3D seismic acquisition. The deadline for the seismic acquisition passed on 16 November 2017. Pathfinder has been awarded an Environmental Permit (EP) which spans the existing permits and also provides additional coverage, particularly between the north/south permit separation, over the Bellini/Barcoo prospects (area now cancelled) and to the west of WA-487-P over the Pina Colada Prospect and Mai Tai lead. On 3 July 2017 Pathfinder received approval to make changes to the work commitments for WA-479-P and WA-487-P. The scheduled 3D seismic data acquisition increased from 530 sq km to 1,200 sq km, with associated data processing, across the permits in the second terms. To facilitate the significant increase in data acquisition, both second work commitment terms have been extend by a further 12 months to 12 August 2018. The term schedule for WA-487-P was aligned with WA-479-P to match the seismic commitment deadline which is valid under the covering EP. The permit is valid until end-2018 and covers the exploration permits, plus two others, held by Pathfinder in the basins. The subsequent terms three to five have not been extended, with geological studies required by August 2017/18 and associated interpretations in the sixth and final terms. The sixth term commitments replace the requirement to drill the first exploration wells which were forecasted to cost around AUD 25 million each, therefore presenting a relatively cheap, low-risk opportunity for interested parties. Permit Term two of both permits have been extended by Pathfinder year after year as the search for a seismic vessel, contractors and farm-in partners has continued. However, Pathfinder remains committed to carry out the survey independently and has stated it will seek reimbursement if a partner is secured. Currently one survey, covering a minimum of 1,200 sq km across both WA-479-P and neighbouring WA-487-P, is planned for the purpose of mapping in more detail the Pina Colada Prospect, which to date has only been mapped from historic 2D seismic data with line spacing around 5 km. Pathfinder has reported that a survey around 3,000 sq km would be required from the basin binding fault to provide complete confidence and understanding of the Pina Colada high, source rocks, reservoirs and seals. Although the EP is valid until end-2018, a seismic contract must be in place by August 2017. A Letter of Intent has already been signed between Pathfinder and a seismic contractor for the work but the size and timing is likely to be dependent on securing a farm-in partner to share costs. Upon the award of the permits in 2012/13, the survey across both permits was expected to cost around AUD 11 million for a combined 530 sq km. Under the latest work revision, the planned 1,200 sq km survey is expected to cost around AUD 3.7 million due to significant reductions in costs to acquire seismic data. Potential farminees to the permits would be expected to help fund the surveys and provide back costs associated with previous activity, with the option of earning further interest via subsequent, non-committed exploration drilling. A contract had been signed with Dolphin Geophysical to commence seismic acquisition covering 2,500 sq km across WA-479-P and WA-487-P including the Pina Colada Prospect and Mai Tai lead. However, upon Dolphin filing for bankruptcy in late-2015, Pathfinder began seeking a new provider through either a proprietary or multi-client arrangement and is continuing with survey planning. NOPTA has continued to support Pathfinder by approving extensions to the second term work commitments in both permits. Pina Colada is a dip and fault closed prospect situated adjacent to a thick Permian-Triassic half graben. The prospect is estimated to contain mean prospective resources of 180 MMb oil or 1.3 Tcf gas with 80 MMb condensate and is currently defined by multiple 2D seismic data sets but requires additional 3D seismic data to better define the structure which is in an ideal position to receive charge from a down-dip petroleum system. Pathfinder has mapped a series of Triassic depocentres northeast of the proven Phoenix area that may contain liquids and gas-prone source rocks similar to those charging the Phoenix South and Roc discoveries. In particular Pathfinder identify the Triassic Locker Shale and the Keraudren Formation in a graben setting between Pina Colada and Mai Tai, which are late oil to gas mature with a recent expulsion pulse created by Tertiary loading. Reservoir objectives are within these Upper Keraudren Formations, sealed by regional and intra-formational shales. The recent success stories for Quadrant Energy at Phoenix South and Roc has sparked life into the Roebuck Basin after previous failures by the likes of BP and Woodside. Confirmation of a working petroleum system was kicked off by Phoenix South 1ST1 in 2014. The well was drilled within WA-435-P permit, making a new oil play discovery with potentially 300 MMb oil in place. Quadrant drilled the Roc 1 located within WA-437 in November 2015 as a follow up well for the new oil play. Roc 1 subsequently made a liquids rich gas discovery within the Keraudren 1, 2 & 3 sands reservoir section ~90 m down dip from the crest of the gas structure, with 40 sq km of up dip potential within the deeper 4 and 5 sands. A net hydrocarbon interval of 10 m over a 40 m gross sand column was intersected within three discrete sand units between 4,380 and 4,420 m.  Gas, with around 20 – 40 bbl/MMcf condensate, was recovered from the well during the evaluation programme. After an initial assessment, Finder Petroleum reported that estimated liquids content had been increased to 46-60 bbl/MMcf. To the west of Pathfinder’s permits, a large exploration programme was planned by Woodside/Shell in 2013 to 2015, including 11,000 sq km 3D seismic data acquisition and eight wells. BP farmed in and subsequently withdrew following two dry wells: Hannover South 1 in WA-466-P and Anhalt 1 in WA-462-P. Hannover South 1 spudded in July 2014 and was drilled to a total depth of 5,512 m before being plugged and abandoned. The well was targeting a large gas prospect, with over 100 MMboe potential reported by Woodside, but failed to encounter hydrocarbons. Hannover South 1 was the first of three initial wells in an eight-well programme, with Anhalt 1 and Steel Dragon 1 (WA-464-P) following. Anhalt 1 spudded on 8 November 2014 and was drilled to a total depth of 5,105 m before being plugged and abandoned as a dry hole. Anhalt 1 was reported to be targeting a large gas prospect within the permit and had a planned total depth of 5,559 m. Steel Dragon 1 was also dry in the neighbouring permit WA-464-P. Pathfinder Energy Pty Ltd is offering a farm-in opportunity to its 100% owned and operated permits: WA-479-P and WA-487-P located within the Roebuck and offshore Canning basins. The permits cover approximately 14,430 sq km in water depths between about 60 and 400 m. Companies interested in pursuing this opportunity should contact: Ian Boserio, Technical Director Tel: +61 419 932 175 Email:  [email protected] Or Greg Channon, CEO Tel: +61 404 879 307 Email:  [email protected]

Australia (Barrow Sub-basin (North Carnarvon B.)) Crest

In late March 2018, US Company Springfield E&P Co. Ltd (Springfield E&P) informed that an Web Geotechnical Virtual Data Room (VDR) was made available during its farm-down process, regarding the West Cape Three Points Block 2 (WCTP Block 2) offshore exploration permit. Water depths in the permit range from 100  to 1,700 m. To access the EZDataRoom® Web VDR, a formal contract between the interested party and Springfield E&P will be required. Springfield E&P is planning to drill, likely not before late 2018 or early 2019, its first exploratory well over the permit, that was awarded in 2016. In May 2017, Springfield E&P completed a 850 sq km 3D seismic survey over the tract and the company is optimistic for future exploration. The WCTP Block 2 coverage includes the oil discoveries Odum 1 and Banda 1, as well as the unsuccessful exploratory well Makore 1, all drilled by Kosmos Energy between 2008 and 2011. The 673 sq km block is bounded by Kosmos’ Offshore West Cape Three Points (Prod) development area to the west, and Eni’s newly reshaped Offshore Cape Three Points Block 4 to the east. Springfield E&P was granted West Cape Three Points Block 2 in March 2016 (82% WI), alongside with state oil company GNPC (carried interest). Contact details: Geoffrey Grant - Principal Geophysicist Phone Number: +233 302 797 923 Email: [email protected]    

Ghana (Cote d'Ivoire B.) Cape Three Points

On 17 January 2020, Gazprom Neft announced a new deal with Royal Dutch Shell plc in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Their joint venture Salym Petroleum Development (SPD) will acquire a 100% stake at newly created company Salymskiy-2 LLC from Gazprom Neft-Khantos. Prior to the deal, license KhMN02196NR shall be transferred from Gazprom Neft-Khantos, the current license operator, to Salymskiy-2. The Salymskiy-2 license covers 376 sq km in the Ural-Frolov Province and it is adjacent to the Salymskoye Zapadnoye, Vadelypskoye and Verkhnesalymskoye fields developed by SPD. Two wells have been drilled in the license. Also, the operator is in the process of interpretation of recently acquired 3D seismic data. SPD is equally owned by Gazprom Neft and Shell. It must be noted that Gazprom Neft invited Shell to join several projects in Russia. In Western Siberia, two companies may team for development of the Achimov reservoirs in the Yamburgskoye field where Gazprom Neft operates as a contractor for Gazprom. In the Okhotsk Sea (offshore Sakhalin), Shell is invited to explore and develop the Ayashskiy license including the recent Neptune and Triton oil discoveries.

Salym Petroleum, has agreed to buy a 100% stake in Salymskiy 2 (380km²) block from Gazprom Neft’s regional subsidiary, Gazprom Neft Khantos

Total (20%) has exited onshore licences PEDL273, PEDL305 and PEDL316, with its 20% stake assigned to operator IGas, effective from 28 May 2020. IGas reported on 12 September 2019 that the three licences had received three year initial term extensions, alongside a handful of other onshore licences. 21 July 2016 in the 14th Landward Licensing Round. The licences are all unconventional - shale gas, in the East Midlands Province and have been extended to 20 July 2024. PEDL273 (SE31c & SE41e) has firm commitments to shoot 70 sq km of 3D seismic and drill a well to the shallower of 3,000m or 50m below the top Dinantian. PEDL305 (SK49 & SK59b) has firm commitments to shoot 70 sq km of 3D seismic and drill a well to the shallower of 2,250m or 50m below the top Dinantian. PEDL316 (SK87c, SK89e & SK88b) has firm commitments to shoot 70 sq km of 3D seismic and drill a well to the shallower of 2,000m or 50m below the top Dinantian. Total’s exit is likely due to the current moratorium on unconventional operations introduced by the UK government on 1 November 2019. Licence partners are now Island Gas Ltd (IGas, 55% + Op), Egdon Resources UK Ltd (15%) and INEOS Upstream Ltd (30%).

United Kingdom, Total (20%) has exited onshore licences PEDL273, PEDL305 and PEDL316, with its 20% stake assigned to operator Island Gas Ltd (IGas, 55% + Op), Egdon Resources UK Ltd (15%) and INEOS Upstream Ltd (30%).

Some good news: The global imbalance between oil supply and demand, which has built to 26.4 million barrels per day (bpd) in April due to the Covid-19 pandemic, is set to halve to 13.6 million bpd in May and fall further to just 6.1 million bpd, according to a Rystad Energy analysis. However, despite the improvement, the stock build will still overwhelm remaining global storage, which will fill in weeks. Global supply is expected to fall in May to 92.8 million bpd, from 98.3 million bpd in April, and further decline to 91.1 million bpd in June. We expect June to see the lowest supply level this year unless further production cuts are announced, with output rebounding from July. Demand on the other hand, which Rystad Energy estimates will reach its lowest point at 71.8 million bpd in April, will rise to 79.2 million bpd in May and to 85.1 million bpd in June, as governments ease Covid-19-related restrictions and some industrial activity resumes. This supply figure already includes the cumulative 6.5 million bpd cuts we expect from OPEC+ countries, as well as more than 2 million bpd of production shut-ins from non-OPEC+ countries (such as Norway) suffering under the unprecedented market squeeze. 'While this may seem like a drastic improvement from April, the oil market is not magically fixed. The storage issue still looms large and will spill over onto trading floors, as buyers are left with crude they cannot physically cannot place, and into the boardrooms of oil companies which must make very costly but necessary decisions to scale back production and give the market some breathing space,' says Rystad Energy oil market analyst Louise Dickson. The demand-supply gap will become narrower in practice as we believe the market will be forced to tighten the stock build gap during May when countries run out of local storage. After local storage is exhausted, tankers will be packed with oil barrels seeking refuge in the country with the most remaining storage capacity – the US. Until this gap is filled by additional shut-ins (possibly even within OPEC+ countries themselves), we can expect further downward pressure on oil prices, especially those that lack a clear conduit to the export market. If sufficient production isn’t shuttered by 19 May 2020 (the expiration of the WTI June 2020 contract), then the potential remains for another nightmare WTI price collapse, which we do not rule out spreading to other crude blends. However, given that most oil futures outside of WTI do not require the buyer to physically take oil delivery, and instead have cash settlement options, the destruction to other benchmarks should be tamer. The negative price crash is most clearly linked to the shortage in global storage. Currently, global storage for crude is about 90% full and for crude oil products, that figure is closer to 80%. Rystad Energy currently estimates that there is 400 million barrels of available global crude storage left, and that crude stocks will build by 13.6 million bpd on average in the month of May. The math isn’t overly complicated, and at this rate, assuming storage tanks can only be filled to about 95% capacity due to technical reasons, Rystad Energy forecasts storage is already hitting the wall in the markets. And, it could reach capacity at the last storage facility standing, the US, towards the end of May. Cushing, Oklahoma could top up even sooner. 'No matter how this physical rebalancing occurs during May, we still expect that the oil price bottom is right in front of us rather than behind us. The next question for markets now is what the recovery will look like and how many oil companies are able to weather the storm and bring inevitable field shut-ins back onstream,' adds Dickson. We still believe in an oil price recovery, possibly starting as early as June, and see a risk for a tight market in 2022 with prices much higher than pre-crisis levels. This will be facilitated by a recovery in demand to above pre-Covid-19 levels in 2022, ongoing OPEC+ cuts, and a loss of supply capacity in both US shale and long-cycled global production. Not all production that is currently being shut-in will be able to swiftly return. For more analysis, insights and reports, clients and non-clients can apply for access to Rystad Energy’s Free Solutions and get a taste of our data and analytics universe. Original article link Source: Rystad Energy

United States, not found

PL 51, Cooper-Eromanga, drilled 15-19 Dec '19, TD 1,158m, P&A oil shows.

Thungo N. 1 expl. (Santos 100%) in PL 51, P&A oil shows. TD=1158m.

Kul-Bas contract area (block 1897RD Kul-Bas), W. of Doris oilfield in North Ustyurt Basin, testing completed of Jurassic between 2127.4-2145.4m, ab. 2,700 bo/d on 11 mm choke, no water, testing continues (2nd zone of interest identified). PTD was 2,500m. Release here.

Kazakhstan (North Ustyurt B.), Klymene-2 (KBD) expl, operated by TETHYS PT (100%) in 1897RD Kul-Bas block, testing completed of Jurassic between 2127.4-2145.4m, ab. 2,700 bo/d on 11 mm choke, no water, testing continues (2nd zone of interest identified). PTD was 2,500m.

It was announced on 22 October 2019 that Turkiye Petrolleri A.O. (TPAO) has been awarded the L47-D3 exploration licence (Zagros Province) on 15 October 2019. The licence, covering an area of 87 sq km, is located towards southeast of the country and TPAO will be 100% owner and operator of the licence. It was earlier announced on 22 March 2019 that TPAO had filed the application for this block on 12 March 2019 covering an area around 150 sq km.

Turkey, L47-D3

On 27 January 2020, ExxonMobil, through its affiliate Esso Exploration and Production Guyana Limited (EEPGL), announced its sixteenth oil discovery with the Uaru 1 new-field wildcat (NFW) on the Stabroek Block offshore Guyana. The Uaru 1 NFW was drilled in 1,933 m (6,341 ft) of water and encountered some 29 m (94 ft) of high-quality oil-bearing sandstone reservoir. The Uaru 1 was spud on 28 December 2019 utilizing Noble’s ““Tom Madden” drillship (DS). The Uaru 1 is located 16 km (10 mi) northeast of the Liza field where first oil production commenced on 20 December 2019. The Stabroek Block is operated by EEPGL (45%) partnered with Hess Guyana Exploration Ltd. (30%) and CNOOC Petroleum Guyana Limited (25%).

Uaru 1 (ExxonMobil 45% op, Hess 30%, CNOOC-Nexen 25%) in Stabroek block located approximately 16km NE of the Liza fild, sixteenth discovery, encountered approximately 29m of high-quality oil-bearing sandstone reservoir. Operator stimated gross discovered recoverable resources, includes 15 discoveries, for the block to more than 8 Boe, up from the previous estimate of 6 Boe.

In mid-July 2018, General Petroleum Company (GPC) completed the Amer North Offshore 2 9 exploration well in the North Amer Marine HH-83 block as an oil well. The well was spudded on 17 April 2018 with the “Admarine VI” J/U, then was sidetracked and drilled to a TD of 3,307 m in the Miocene Kareem Formation. It had a planned TD of 3,284 m and the Miocene Rudeis and the Upper Cretaceous Matulla and formations as the targets.  GPC is the operator of the North Amer Marine block with a 100% interest.

Amer North Offshore 2 9 exploration in North Amer Marine HH-83 block comleted as an oil well. . It had a planned TD of 3,284 m and the Miocene Rudeis and the Upper Cretaceous Matulla and formations as the targets. GPC is the operator of the North Amer Marine block with a 100% interest.

Iraq’s 11-block E&P round assignments are reportedly being signed. Crescent inked on 3 June, having bid for the Gilabat, Khidhr Almaa + Khashm Al Amar blocks. China’s Geo-Jade Petroleum Corp is signing today (4 June) for 3 contracts, having bid for the Naft Khaneh + Huwaiza blocks. There is yet no mention of United Energy Grp’s Sindbad block. Details/confirmation sought.

Iraq’s 11-block E&P round assignments are reportedly being signed. Crescent inked on 3 June, having bid for the Gilabat, Khidhr Almaa + Khashm Al Amar blocks. China’s Geo-Jade Petroleum Corp is signing today (4 June) for 3 contracts, having bid for the Naft Khaneh + Huwaiza blocks. There is yet no mention of United Energy Grp’s Sindbad block. Details/confirmation sought.

ONGC has bagged 7 onshore explo blocks totalling 18,510 sq km offered under the OALP-4 round, the contracts signed yesterday. OALP-4 had attracted only 8 bids (7 ONGC, 1 OIL). ONGC's new rights lie in Madhya Pradesh, West Bengal + Rajasthan, w.o. details.

ONGC has bagged 7 onshore explo blocks totalling 18,510 sq km offered under the OALP-4 round, new rights lie in Madhya Pradesh, West Bengal + Rajasthan.

On 23 November 2017, Novatek announced that it completed the acquisition of Severneft-Urengoy operating the Yaroyakhinskiy Zapadnyy license in Yamalo-Nenets Autonomous Okrug (Western Siberia). Novatek-Yurharovskneftegaz bought 100% of the operator from EuroKhim for undisclosed price. The previous owner acquired Severneft-Urengoy for USD 403 million in 2012. Yaroyakhinskiy Zapadnyy license covers 897 sq km in the central part of the Nadym-Taz Province and encompasses the Novoventoyskoye oil discovery and parts of the Urengoyskoye Vostochnoye and Urengoyskoye fields. Combined remaining 3P reserves of the license are estimated at 196 MMbbl of oil, 2.1 Tcf of gas and 61 MMbbl of condensate. In 2016, Severneft-Urengoy produced 76 MMcf/d of gas and 2,033 b/d of condensate.

Russia (West Siberian B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Yaroyakhinskiy Zap. op. by SEVER URE (100.0%) to be check.Urengoyskoye Vost. op. by ROSPAN (100.0%) to be check.Zapadnyy op. by RUSSNEFT (100.0%) to be check.Vostochnoye op. by SAMARA NG (100.0%) to be check.Urengoyskoye op. by GAZPROM (100.0%) to be check.

Low-angle well in PPL-242, Cooper Basin, P&A oil shows at TD 1873m on 30 Aug ’18, Saxon rig-185. Senex (op), partner Beach.

Growler NE-1 (Senex (op), partner Beach) Low-angle well in PPL-242, Cooper Basin, P&A oil shows at TD 1873m

On 4 January 2018, SDX Energy announced that it had abandoned the ELQ-1 wildcat in the Gharb Centre permit after encountering non-commercial gas. The well has encountered 22.6 net m of reservoir interval and 2 m of marginal net gas pay in the Hoot formation, which is estimated to be insufficient to proceed to the completion of the well. The ELQ-1 well was spudded on 21 December 2017 and drilled to a TD of 1,484 m. The well is the fourth well in the Company’s nine well campaign and the first of two commitment wells planned on the Gharb Centre permit. The Gharb Centre permit was acquired in June 2017 after the acquisition of Circle Oil’s assets in Egypt and Morocco in January 2017.

Morocco (Rharb-Prerif B.) ? op. by SDX ENERGY (75.0%, ONHYM 25.0%) in Gharb Centre block

On 26 March 2020 3D Oil Ltd reported that its Farm Out Agreement (FOA) with ConocoPhillips Australia (COP), in relation to exploration permit T/49P, is close to completion, with government approval now required to seal the deal. The companies have signed a Joint Operating Agreement for the permit, which covers over 4,500 sq km in the Tasmanian Otway Basin. Initially, COP was to acquire 75% interest, but under the terms of the FOA, 3D Oil will now retain 20% to reduce its future operational expenses. Once government approval has been received, COP will pay 3D Oil an AUD 5 million cash payment to enter the permit and become operator. COP will also undertake 3D Oil's planned Dorrigo 3D seismic survey, covering all costs, and could elect to drill an exploration well, in which 3D Oil would be free carried for up to USD 30 million. The companies entered the FOA on 18 December 2019 and were required to sign a Joint Operating Agreement and gain government approvals to fulfil the conditions of the agreement. Completion of the deal will see COP move into the Otway Basin for the first time At the time of the JOA, the Dorrigo 3D survey was planned for September/October 2020 to gather new data over the central and southern areas of T/49P. Under the work commitments, at least 750 sq km of new data is required, which will take place in water depths of between 100 and 840 m. The FOA requires COP to acquire, and fully fund, at least 1,580 sq km of data acquisition. 3D Oil had been offering a farm-in opportunity to assist in drilling a well to target the Flanagan Prospect, which lies in the north. A total of around 10 Tcf prospective resources have been estimated across the permit as a whole. The Dorrigo 3D will target acquisition over the Harbinger lead, which has estimated prospective resources of 790 Bcfg, and the Seal Rocks lead, which has prospective resources of potentially over 4 Tcfg. Both have been mapped on old 2D seismic, and the new 3D is hoped to better define the leads and determine a drill location. T/49P, which covers an area of 4,551 sq km, was awarded on 22 May 2013. 3D Oil T49P Pty Ltd has entered into a farm in agreement with ConocoPhillips Australia SH1 Pty Ltd, which remains subject to government approval after meeting all other conditions. Upon completion of the deal, interests will become: 3D Oil T49P Pty Ltd (20%) and ConocoPhillips Australia SH1 Pty Ltd (80% + operator).

ConocoPhillips has secured a majority operated stake 75% (3DOil 25%) in an exploration block T/49 P.

The Neuquén authorities have granted Retama Argentina 4-year (initial) rights to the 128-sq km Parva Negra Oeste shale concession, a result of the company’s successful bid under the Neuquén V round in September. Parva Negra Oeste lies NW of the Sierra Chata field on the Chihuidos High, adjacent to the Los Toldos I Sur (ExxonMobil, DEA 31 Oct ’17). Retama (op) 90%, partner GyP Neuquén.

Retama Argentina (op 90%, GyP Neuquén 10%) awarded Parva Negra Oeste (Vaca Muerta) concession.

Total spudded exploration well 30/12d-11 in licence P1820 on 13 October 2019 targeting the Isabella prospect. The HP/HT (12,960 psi and 175 degrees centigrade) gas condensate prospect was understood to be located on one of the largest undrilled fault blocks in the Central North Sea. The well was drilled with the Noble Sam Hartley (J/U). On 17 March 2020 Total announced that it had made a discovery. A total of 64 m net pay of lean gas and condensate and high quality light oil in Upper Jurassic and Triassic sandstone reservoirs has been encountered. Partner Neptune announced that hydrocarbons had been encountered in three separate formations. Further analysis of the discovery is ongoing to determine the discovered resources, subsequent appraisal programme and confirm commerciality. On 25 March it was confirmed that plug and abandonment operations are ongoing and are scheduled to finish around the 30 March 2020. The Isabella trap is formed by closure on a salt pierced anticline. The reservoir target was the Triassic Joanne and Judy Sandstones. The well was planned to be slightly deviated with an estimated TD of 5,607 m. P1820 was awarded in the 26th Offshore Licensing Round to Valiant and Apache North Sea Ltd. On 23 September 2013 Ithaca announced that it has agreed to farm down a 10% interest in licence P1820 (blocks 30/6b, 30/11a and 30/12d) to Edison subsidiary EDF Production UK Limited in return for a cash payment. It was confirmed that the deal completed on 31 December 2013. On 13 August 2018 Neptune announced that it had agreed to acquire Apache’s interest in the licence and then late 2018 / early 2019 the operatorship was transferred over to Total. Interest in P1820 is held by Total E&P North Sea UK Limited (30% + operator), Neptune E&P UK Limited (50%), Edison subsidiary, Euroil Exploration Limited (10%) and Ithaca Energy (UK) Limited (10%).

otal spudded exploration well 30/12d-11 in licence P1820 on 13 October 2019 targeting the Isabella prospect. The HP/HT (12,960 psi and 175 degrees centigrade) gas condensate prospect was understood to be located on one of the largest undrilled fault blocks in the Central North Sea.

Angus is joining Cuadrilla and Lucas Bolne with a 25% interest and operatorship in PEDL 244 which contains the Balcombe field in Sussex. Plans are to run a test programme of the Balcombe-2Z (no fracking) ahead of a field devt plan being submitted to the OGA.

Angus Energy is taking a 25% stake in PEDL 244 in the Weal basin, which hosts the Balcombe find, from Cuadrilla (->56,25% op, Lucas Bolney 18,75%).

Tri-Star Petroleum Co, through wholly owned subsidiary Tri-Star Australia Holding Co, acquired 100% interest and operatorship in exploration permits ATP 666-P, ATP 667-P and ATP 668-P, located in the Galilee-Eromanga Basin, on 23 April 2018. Tri-Star acquired its interest from the Australia Pacific LNG joint venture, which previously held sole interest in the permits. The permits don’t contain any discoveries, but do contain some wells. ATP 666-P is host to the historical BMR Hughenden 1, 1A and 2 wells, drilled in 1966 by the Bureau of Mineral Resources, and the GSQ Hughenden 1-2R well, drilled in 1974 by the geological survey of Queensland. All four wells were stratigraphic holes and plugged and abandoned as dry. ATP 667-P contains the Hexham 1 well, also a plugged and abandoned dry stratigraphic test, drilled in 1974.  Finally, ATP 668-P contains the GSQ Jerico stratigraphic hole, plugged and abandoned as a dry hole in 1973.  ATP 666-P and ATP 667-P cover areas of 1,685 sq km and 1,898 sq km respectively and were both awarded on 6 April 2006.  ATP 668-P covers 1,333 sq km and was awarded on 23 April 2007.  Tri-Star Australia Holding Co now holds 100% interest and operatorship of the three permits.

Tri-Star Petroleum Co, through wholly owned subsidiary Tri-Star Australia Holding Co, acquired 100% interest and operatorship in exploration permits ATP 666-P, ATP 667-P and ATP 668-P, located in the Galilee-Eromanga Basin, on 23 April 2018.

In August 2019, Total SA was still waiting for production licences at the Mpyo and Jobi East fields to be issued by the Ministry of Energy and Mineral Development (MEMD). The fields are located in the Exploration Area 1/1A licence which contains the Lyec and Para blocks. Moreover, in April 2020, Total and Tullow signed an agreement in which Tullow will sell its interest in the Lake Albert project to Total. The deal is expected to be completed in 2H 2020 with an effective date of 1 January 2020. The Mpyo and Jobi East discoveries were made in July 2010 and May 2011, respectively. The Mpyo and Jobi East fields hold oil recoverable resources in Upper Pliocene sands estimated at 89 MMbbl and 190 MMbbl, respectively. The most recent seismic acquisition in the area was performed by Total in mid-2014, when a 340 sq km 3D seismic survey was completed over the former EA1 licence and included the Mpyo, Gunya, Ngiri, Jobi-Rii and Jobi-East discoveries. Before Tullow and Total's deal, interest in the Exploration Area 1/1A licence was held by Total E&P Uganda (33.33% + operator), CNOOC Uganda Ltd (33.33%) and Tullow Uganda Ltd (33.33%). Background Information On 30 August 2016, the MEMD granted three petroleum production licences to Total over other oil fields located in the EA1 (Ngiri, Jobi-Rii and Gunya). Jobi-East In May 2011, Jobi East 1 well encountered 20 m of net hydrocarbon bearing reservoir in a fault block adjacent to the Jobi structure and reached a TD of 567 m. Logging and sampling confirmed the presence of oil in two zones of high quality reservoir totalling 15 m of net pay. Gas was also found within sands totalling 5 m of net pay. The first appraisal well, Jobi East 5/5ST, was found to be water bearing in August 2011. The second appraisal well, Jobi East 2/2ST, successfully extended the field five kilometres northward by intersecting a total net hydrocarbon bearing reservoir of 22.5 m in October 2011 and the well was suspended at a TD of 495 m. The well was subsequently tested and reached a maximum flow rate of 40 b/d of oil. Jobi East 6 (TD of 380 m) and Jobi East 7 /7A (TD of 444 m) were spudded between July and August 2013, using the Caroil #2 land rig. The Jobi East 7 /7A well was side-tracked, cored and suspended on 28 August 2013. Jobi East 3/3A was spudded on 3 September 2013, reaching a TD at 254 m in late September 2013. The well was further completed in October 2013 and tests yielded maximum flow rate of around 12.6 b/d of oil. In early November 2013, operator Total completed the appraisal well Jobi East 4 at a TD of 235 m. The well was spudded with the OGEC 600 land rig, immediately after the completion and flow testing at the Jobi East 3/3A appraisal well. Mpyo Tullow discovered oil with the Mpyo 1 in August 2010 (32 m net hydrocarbon bearing sands in two zones). The Mpyo 3 well was drilled in May 2011 (at TD of 584 m) and it waslocatwed1.6km southeast of the Mpyo 1 wildcat in a down-dip location and within an adjacent fault block. Mpyo 3 well found a 21 m net hydrocarbon bearing sands in June 2011 at a depth of 340 m, in line with pre-drilling expectations. Total re-entered the Mpyo 1 (TD of 465 m) in August 2012 and tested it. The Mpyo 3 well yielded a maximum flow rate of 174 b/d of oil. Mpyo 4 was drilled between June and July 2013. Flow tests on that well yielded maximum rates of 210 b/d of oil. The Mpyo 5, 6 and 7 were drilled in between September and November 2013.

Tullow has agreed the sale of its 33.33% interests in the Lake Albert devt project to Total for USD 575 MM cash plus post first oil contingent payments, CNOOC has rights of pre-emption on 50% of the Uganda Interests on the same terms and conditions as Total.

The authorities yesterday signed formal contract awards for blocks secured under the 2014 round: Exxon bags A5-B, 6,080 sq km in the Zambezi Deep Sea Fan, Z5-C, 5,821 sq km and Z5-D, 4,384 sq km offshore Zambezi Delta, partners RN Expl (Rosneft) 20% + ENH 20%. Eni gets A5-A, 5,145 sq km offshore in the Angoche Basin, Eni (op) 59.5%, Sasol 25.5%, ENH 15%. Signature is still pending but assumed imminent for PT5-C, 3,012 sq km onshore Pande-Temane, with Sasol (op) 70%, ENH 30%.

The authorities yesterday signed formal contract awards for blocks secured under the 2014 round: Exxon bags A5-B, 6,080 sq km in the Zambezi Deep Sea Fan, Z5-C, 5,821 sq km and Z5-D, 4,384 sq km offshore Zambezi Delta, partners RN Expl (Rosneft) 20% + ENH 20%. Eni gets A5-A, 5,145 sq km offshore in the Angoche Basin, Eni (op) 59.5%, Sasol 25.5%, ENH 15%. Signature is still pending but assumed imminent for PT5-C, 3,012 sq km onshore Pande-Temane, with Sasol (op) 70%, ENH 30%.

The Faroes' 5th round (run in conjunction with the UK's 32nd round) closed after 120 days on 12 Nov '19. No offers were submitted for any of the 59 blocks or parts thereof on offer, total 9,418 sq km. The Faroe designated offshore area is now under open door status.

The Faroes' 5th round (run in conjunction with the UK's 32nd round) closed after 120 days on 12 Nov '19. No offers were submitted for any of the 59 blocks or parts thereof on offer, total 9,418 sq km. The Faroe designated offshore area is now under open door status

Central part of block C-9, MSGBC Basin, WD 2,500m, ops terminated of late, Pacific Santa Ana DS off to Las Palmas for a cleanup, to return to Mauritania for perhaps 1 year's P&A work for Petronas, then back to Total.  Total (op), partner SMHPM.

Richat-1 nfw Central part of block C-9, MSGBC Basin, WD 2,500m, ops terminated of late, Pacific Santa Ana DS off to Las Palmas for a cleanup, to return to Mauritania for perhaps 1 year's P&A work for Petronas, then back to Total. Total (op), partner SMHPM.

Santos Ltd and Quadrant Energy Ltd, now a wholly owned subsidiary of Santos after a takeover completed in November 2018, altered their respective interests in retention lease WA-45-R, located in the Dampier Sub-basin, North Carnarvon Basin, on 27Q November 2018, upon the withdrawal of joint venture partners Harriet (Onyx) Pty Ltd and Hydra Energy (WA) Pty Ltd. Harriet and Hydra had both held 12.5% interest within the licence, which has now been assigned to Santos.  Santos has redistributed the interests between its holders with Quadrant holding 55% and operatorship and Santos Ltd holding 45%. The licence was awarded on 23 November 2011 and is valid until May 2022. It contains part of the Corvus gas discovery, which was made in April 2000.  The operator is reportedly planning appraisal during 2019. WA-45-R, which covers an area of 81 sq km, saw an interest change completed on 27 November 2018.  Participants in the licence are now Quadrant Northwest Pty Ltd (55% + Operator) and Santos Offshore Pty Ltd (45%).

Santos Ltd and Quadrant Energy Ltd, now a wholly owned subsidiary of Santos after a takeover completed in November 2018, altered their respective interests in retention lease WA-45-R, located in the Dampier Sub-basin, North Carnarvon Basin, on 27Q November 2018, upon the withdrawal of joint venture partners Harriet (Onyx) Pty Ltd and Hydra Energy (WA) Pty Ltd. Harriet and Hydra had both held 12.5% interest within the licence, which has now been assigned to Santos.

Santos Ltd spudded the Mountain Goat 1 exploration well in ATP 1189-P, located in the Cooper-Eromanga Basin, on 7 April 2018. The well was drilled by the “Ensign 970” land rig.  On 22 April 2018 the well was suspended as a gas discovery, after reaching a total depth of 3,237 m. The well is one of several in an ongoing exploration drilling programme in ATP 1189-P and follows the Bantam 1 well, which encountered a total 5.5 m net pay, and the Tigris 1 well which was a dry hole. ATP 1189-P, which covers an area of 9,151 sq km, was awarded on 1 January 2015.  Participants in the block containing the well are Santos Ltd (57.5% + Operator), Santos subsidiaries Santos Australia Hydrocarbon Pty Ltd (5%) and Vamgas Pty Ltd (7.5%) and Beach Energy subsidiary Delhi Petroleum Pty Ltd (30%).

Australia (Cooper - Eromanga B.s) Bantam 1

Lundin used the “Leiv Eiriksson” S/S to spud exploration well 16/1-31 S targeting the Jorvik prospect in PL 338 on 10 March 2019. The objective was the Jorvik conglomerate. The company drilled to TD at 2,220 m and the well was plugged back on 10 May 2019. The following day Lundin kicked-off exploration sidetrack 16/1-31 A targeting the Tellus East prospect (weathered and fractured Basement with a potential sandstone drape) and on 18 June 2019 it was plugging and abandoning. The two prospects have combined potential recoverable reserves of 23 MMboe and results are expected to be announced shortly. As it is not possible to target both with a single well, the two wells are being used in a Y formation. Duration was expected to be up to 186 days, which provided for a sidetrack and test at each prospect. The top hole is located approximately 4 km northwest of the Edvard Grieg platform, between the Edvard Grieg and Ragnarrock fields. In 2013 Lundin drilled the first well on the Jorvik prospect which lies immediately east of Edvard Grieg and is a continuation of the same play onto the Haugaland High. 16/1-17 proved mobile oil, but the reservoir (pre-Jurassic conglomerate and pebbly sandstone) was tight with haematite cementation. Potential reserves were estimated at 46 MMboe (in PL 338) prior to drilling. Tellus was drilled in early 2011, just to the north of Edvard Grieg. 16/1-15 made a new discovery in the Lower Cretaceous/Basement with potential reserves (given at the time) of 11-55 MMboe. The field was developed as part of Edvard Grieg and the reserves are now included in the overall field volumes. The completion of drilling of the 14 development wells at Lundin’s Edvard Grieg field was achieved in July 2018. The results exceeded pre-drill expectations and there is no material water production. Earlier in 2018 Lundin announced a reserves increase of 51 MMboe (since the end of 2016) to 274 MMboe, representing a 47% increase compared with the PDO. Good drilling results and production performance indicated that the oil in place volumes were higher than originally calculated and that more of the oil is in the better quality sandstone part of the reservoir (with less in the poorer quality conglomerate zone). The field was producing at a facilities-capacity rate of 95,000 boe/d in July 2018 but double this rate is actually possible. The nearby Lundin-operated Solveig (Luno II) and Rolvsnes discoveries will be tied-back to Edvard Grieg and the 2018 discovery made by Equinor at Lille Prinsen could also potentially be tied-in. Lundin Norway AS operates PL 338 with a 65% interest. It is partnered by OMV (Norge) AS (20%) and Wintershall Dea through Wintershall Norge AS (15%).

016/01-31 S (Jorvik) 31A (Tellus East) appr. (Lundin 65 op, OMV 20%, Wintershall 15%) in PL 338, P&A results n/a.

In May 2018, Petrobras launched a process inviting companies to bid on a project to revitalize the onshore fields of the Canto do Amaro complex. The contract covers 15 assets in the state of Rio Grande do Norte and is called Polo Canto do Amaro. It includes the Barrinha, Barrinha Leste, Barrinha Sudoeste, Benfica, Boa Vista, Canto do Amaro, Fazenda Canaa, Morrinho, Mossoro, Pedra Sentada, Pintassilgo, Poco Verde, Redonda Profundo, Serra do Mel and Serra Vermelha field blocks. The winning company will get a 15-year service contract and must conduct at least 65 completion/workover operations and 34 lifting method changes in the second half of 2019 and the first half of 2020 for the areas. The winning company will have to make investments and contribute knowledge and technologies to boost the recovery factor of the fields and increase the return to Petrobras. The company's compensation will be based on the total production obtained by Petrobras in Canto do Amaro fields. The contract model has the winning bidder contracted to be responsible for all the investment in the fields and for the cost of operation, maintenance and abandonment of all the wells it drills while Petrobras will continue to operate the fields, hold the reserves and be responsible for the other operating costs of the production system. The production baseline curve set by Petrobras for the first 12 months of the contract, beginning on 30 June 2019 calls for an average daily production in the fields, ranging from 13,400 bo/d in July 2019 to 12,700 bo/d in June 2020.

Petrobras launched a process inviting companies to bid on a project to revitalize the onshore fields of the Canto do Amaro complex. The contract covers 15 assets in the state of Rio Grande do Norte and is called Polo Canto do Amaro. It includes the Barrinha, Barrinha Leste, Barrinha Sudoeste, Benfica, Boa Vista, Canto do Amaro, Fazenda Canaa, Morrinho, Mossoro, Pedra Sentada, Pintassilgo, Poco Verde, Redonda Profundo, Serra do Mel and Serra Vermelha field blocks.