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US-based Noble Energy on 15 February 2018 said it would sell its portfolio of assets in the Gulf of Mexico to Fieldwood Energy for US$ 710 million so that it can focus on the US onshore and Eastern Mediterranean. The proposed deal essentially represents Noble's departure from the GOM. "The sale of our Gulf of Mexico business represents the last major step in our portfolio transformation. This has been done to focus our go-forward efforts on those assets that will rapidly grow our cash flows and margins, primarily the U.S. onshore business and the Eastern Mediterranean," said David L. Stover, Noble Energy's Chairman, President and CEO. Cash proceeds included in the transaction total US$ 480 million. The effective date of the transaction is 1 January 2018. Closing is anticipated during Q2 2018. That's contingent upon Fieldwood successfully implementing its contemplated restructuring process, Noble said. Included in the transaction is Noble's interest in six producing fields and all undeveloped leases. Those producing fields are: Galapagos, Swordfish, Gunflint, Dantzer, Big Bend, and Ticonderoga. For its part, Fieldwood will assume all abandonment obligations associated with the properties, which the company recorded at a book value of approximately US$ 230 million as of 31 December 2017, the terms of the deal state. Noble may also scoop up a cumulative contingent payment of up to US$ 100 million from closing of the transaction through the end of 2022, determined quarterly at a rate of US$ 2 per barrel produced when the average Light Louisiana Sweet oil price exceeds US$ 63 per barrel. Noble forecast that the assets will produce 20,000 boe/d in 2018, while total proved reserves in the US GOM at the end of 2017 totaled 23 million boe. On the same day on the announcement of the sale, Noble said its Board of Directors has authorized a US$ 750 million share repurchase program.

Not Found

Premier announced on 30 April 2018 that it is selling its interest in a number of assets in the Babbage area to Verus Petroleum. The deal will see Verus obtain 47% interest in the Babbage field, 50% interest in the Cobra discovery and a number of exploration commitments. The sale of Babbage amounts to GBP 62.9 million (USD 88.1 million) and exploration commitments of GBP 17 million (USD 23.8 million). If the development of Cobra proceeds then additional payments would take place depending on third party business in addition to a cash payment of GBP 5.5 million (USD 7.7 million). The effective date of the deal is 1 January 2018 and completion is expected during H2 2018 subject to partner and government approval. On 6 July 2018, Spirit Energy announced it has reached agreement to take operatorship of the Babbage and Cobra licences. Spirit plans to drill an exploration well at the Python prospect in Q2 2019 to further prove up reserves in the region. Transfer of operatorship from Premier Oil is subject to completion of the divestment of Premier Oil's 47% interest in Babbage and 50% interest in the Cobra licence to Verus Petroleum and receiving relevant regulatory approvals. Babbage was discovered in 1989 by Amoco’s 48/2-2Z well and appraisal drilling took place in 2006. The field has a Permian Leman Sandstone reservoir. During Phase 1 of development three horizontal multi-fractured wells were drilled between April and November 2009 and a platform was installed in September 2009. Production commenced from the field in August 2010. During phase 2, which took place between 2012 and 2013, there were 2 multi-fracced development wells were drilled. The Not Permanently Attended Installation (NPAI) is tied-back to the West Sole field which is located 28 km to the south. The field is expected to produce over 175 Bcfg over a life of 20 years. Cobra is a segmented structure spread over five separate segments of Rotliegendes Sandstone. The discovery was made by Amoco in November 1984, when well 48/2-1 was reported to have encountered gas, although it would not flow at commercial rates unstimulated. An appraisal well was drilled by EnCore in May 2008, which targeted the same 3-way closure. However, it was abandoned as uncommercial. When tested the well flowed a maximum unstimulated rate of 1.1 MMcf/d dry gas. Verus is planning to drill a new appraisal well in 2019 to test the presence of further volumes of gas, which could be tied-back to the Babbage field. Following completion of the deal interest in Babbage, which is located in block 48/2a and covered by licence P456 will be held by Verus Petroleum UK Limited (47%), Dana Petroleum (E&P) Ltd (40%) and Spirit Energy Southern North Sea Ltd (13% + operator). Interest in P2212, P2290 and P2301 will be held by Verus Petroleum UK Limited (50%) and Sprit Energy Southern North Sea Limited (50% + operator).

Premier announced on 30 April 2018 that it is selling its interest in a number of assets in the Babbage area to Verus Petroleum.

Mari Petroleum Company Ltd (MPCL) has been exclusively awarded the Wali West 3269-1 EL (Pishin-Katawaz Basin) exploration licence on 18 November 2019. The licence covers an area of 1,610 sq km and it is located in the South and North Waziristan districts of Khyber Pakhtunkhwa province. The block was offered under the ‘Onshore Bid Round 2018’ and it is awarded to MPCL after the highest bid from SPEC was rejected by the government. The bidding round was launched from 13 September 2018 to 26 November 2018 under which 10 onshore blocks were offered.

Mari Petroleum was awarded the Wali West 3269-1 EL, offered as part of the 2018 onshore bid round.

25 Years of Independence (Mustakillikning 25 Yilligi) gasfield in the Surhandarya region, Afghan-Tajik Basin, 2018 well, new-pool find, tested 10.3 MMcfg/d from pre-salt Callovian-Oxfordian carbonates. More from GEPS.

Uzbekistan (Surkhandarya Depression (Afghan-Tajik B.)) 25 Years Of Independence

On 12 June 2020, Ukrgazvydobuvannya reported the completion of a new appraisal well at Berezivske field in Kharkiv Oblast (Dnieper-Donets Basin). Berezivska 208 was drilled to 6,000 m by contractor Ukrburgaz in the Berezivska structure of the field. The well tested gas at a rate of 8.9 MMcf/d from the Tournaisian section. The well added 12 Bcf of proven gas reserves at the field. Berezivske, discovered in 1979, has initial 2P reserves estimated at 861 Bcf of gas 44 MMbbl of condensate. Production was started in 1982 and, since then, about 65% of initial reserves have been produced. Aiming at discovery of new reserves in the deeper reservoirs, Ukrgazvydobuvannya completed a 3D seismic survey over the field and started a new exploratory drilling program.

Ukraine (Dnieper-Donets B.) Berezivska 208 op. by NGU (100%) in Berezivske field (Gas) block, The well tested gas at a rate of 8.9 MMcf/d from the Tournaisian section. The well added 12 Bcf of proven gas reserves at the field. Berezivske,

EP 112, Amadeus Basin in NT, last reported at 3,704m (Gallen fm, pre-salt, likely TD), high formation pressures (gas influx) force a possible suspension with a view to re-entry later, Ensign rig 965. The well did not encounter the main Heavitree fm target by this depth. Farmin obligation well for Santos (back in 2013), 30% partner Central Petr. carried.

Dukas 1 nfw, farmin obligation well for Santos (back in 2013), 30% partner Central Petr. in EP 112, last reported at 3704m (Gallen fm, pre-salt, likely TD), high formation pressures (gas influx) force a possible suspension with a view to re-entry later. The well did not encounter the main Heavitree Fm target by this depth.

Pancontinental Oil & Gas NL was offering a farm-in opportunity for interested parties to enter exploration permit EP 447, located in the Perth Basin. However, on 14 June 2018, Pancontinental reported that its own 2016 farm-in deal with operator Strike Energy had been cancelled. Pancontinental, through its subsidiary company Bombora Natural Energy Ltd, had agreed to acquire 70% interest in the permit in return for funding the planned Walyering 3D seismic survey. However, the survey was not completed by the time allocated under the farm-in agreement, and Strike terminated the agreement. The permit contains the Walyering gas field, which 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. After the Pancontinental farm-in agreement was cancelled, Strike Energy’s subsidiary company UIL Energy now continues to hold 100% interest. The agreement was for an area over the Walyering asset, with Bombora negotiating 70% interest and operatorship. The companies had extended the farm-in agreement negotiations to end 2018. Evaluation of Walyering was ongoing as part of the agreement, with the planned 3D seismic survey scheduled for 1H 2019 to provide better definition at the gas reservoir levels. Pancontinental, as part of the farm-in agreement, was planning to conduct the Walyering 3D seismic survey in late 2018 which was then pushed back to 2019.  Pancontinental was to fund the survey, up to a capped amount of AUD 2.5 million, to earn the 70% interest in the Walyering, southern section, of the EP 447 permit.  The survey was being scheduled to be undertaken in conjunction with other seismic plans in the Perth Basin. 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 and that there’s a 57% chance of success in the Central High. In May 2018 Pancontinental released upgraded gas and condensate volumes for the Walyering field to gross figures of 100 Bcf gas and 2.5 MMb condensate. In the case that new 3D seismic data supports the current mapping and size of the undrilled compartments, Pancontinental reports that it will consider an appraisal / development well in 2019. Pancontinental, through its subsidiary company Bombora Natural Energy, was offering a farm-in opportunity for the Walyering field area of EP 447. The offer was reliant on Pancontinental completing a farm-in deal with UIL to gain 70% interest. This deal was terminated on around 14 June 2019. Parties interested in this opportunity were to contact - John Begg, Pancontinental CEO Phone: +61 8 636 7090 Email: [email protected]

Pancontinental Oil & Gas NL was offering a farm-in opportunity for interested parties to enter exploration permit EP 447, located in the Perth Basin

JKX is selling 6 wholly-owned D&P (mining plots) – Emod V (100 sq km), Hajdunanas IV (28 sq km), Hajdunanas V (7 sq km), Jaszkiser II (6 sq km), Pely I (18 sq km) and Tiszavasvari IV (46 sq km) in CE + NE Hungary (Pannonian Basin). Bids invited in 1H ’19, any ensuing deals within the next 12 months. JKX operates in Hungary as Folyópart Energia Kft.

JKX is selling 6 wholly-owned D&P (mining plots) – Emod V (100 sq km), Hajdunanas IV (28 sq km), Hajdunanas V (7 sq km), Jaszkiser II (6 sq km), Pely I (18 sq km) and Tiszavasvari IV (46 sq km) in CE + NE Hungary (Pannonian Basin). Bids invited in 1H ’19, any ensuing deals within the next 12 months. JKX operates in Hungary as Folyópart Energia Kft.

Maria Conchita block, L. Guajira Basin in N. Colombia, re-entered 1980 gas well, large volumes of gas reportedly encountered while repairing a gas leak. Evaluation now required.

Colombia (Lower Guajira B.) ? op. by CRUZSUR (100%) in Maria Conchita block

DEA has been pre-awarded the East Damanhour Onshore block, following the announcement of the winners of the EGAS 2018 International Bid Round on 12 February 2019. Other bidders for the acreage included Aspect Energy, Cheiron and INA. The 1,418 sq km block lies immediately west of the Disouq PSC (DEA 50% equity) in the Nile Delta Basin. Work commitments include expenditure of US$ 28 million and the drilling of seven wells during the initial exploration period. A US$ 11 million signature bonus will be paid. Upon PSC signature, DEA will operate the concession 100% equity.

DEA has been pre-awarded the East Damanhour Onshore block, following the announcement of the winners of the EGAS 2018 International Bid Round on 12 February 2019. Other bidders for the acreage included Aspect Energy, Cheiron and INA. The 1,418 sq km block lies immediately west of the Disouq PSC (DEA 50% equity) in the Nile Delta Basin. Work commitments include expenditure of US$ 28 million and the drilling of seven wells during the initial exploration period. A US$ 11 million signature bonus will be paid. Upon PSC signature, DEA will operate the concession 100% equity.

Fell block, Magallanes Basin, drilled Jan-mid Feb ’18, suspended prior to test, no details. The company is reportedly considering the re-entry of some past discovery wells in Fell to test the El Salto fm after last month’s Uaken 1 find (DEA 18 Jan ’18).

Jauke-1, Fell block, Magallanes Basin,suspended prior to test, no details. The company is reportedly considering the re-entry of some past discovery wells in Fell to test the El Salto fm after last month’s Uaken 1 find

On 10 October 2019, the consortium of Chevron, Repsol and Wintershall DEA bid on and were granted a preliminary award for the 696.81 sq km S-M-766 block in the deep-water offshore Santos Basin from the ANP Round 16. There were no other bids for the block. The consortium bid a bonus of USD 13.17 million at 1 USD to 4.11 BRL and USD 6.45 million in minimum work commitments.  Chevron is operator with 40% working interest, Repsol holds 40% working interest, and Wintershall DEA holds 20% working interest.

Brazil, not found

In April 2019 it is understood that the Federation of Bosnia and Herzegovina was still in the process of looking for a consultant company to help it preparing a bidding round. It is yet to early to know how many blocks could be available for the bidding. The area to be on offer is believed to be situated in the western part of the Federation. The Republic of Bosnia and Herzegovina is divided in two political entities – the Federation of Bosnia and Herzegovina and the Republic of Srpska – and the district of Brcko which is a self-governing administrative unit in the northeastern part of the country. In early November 2011 the government of the Federation of Bosnia and Herzegovina signed a Memorandum of Understanding (MOU) with Shell to explore potential natural oil and gas accumulations and develop a data room. According to Shell studies the Dinaridi area have oil especially in the area of Gornja Dreznica. Oil was also spotted near the Posavina enclave (north) and Majevica (northeast). The findings made by Amoco between 1989 and 1991 showed up a large oil basin located in the area covering the Glamoc and Livno plains, Gornja Dreznica, and the inland area of Neum. In those areas of the Federation of Bosnia and Herzegovina, oil is estimated to be at depth ranging from 4,000 m to 8,000 m and could reach up to 500 million tons. In the eastern part of the Federation – near Tuzla - Amoco reported four locations with oil at depth between 1,000 m and 1,300 m which could hold around 70 million tons. Following Shell’s decision of early October 2015 to put an end to its exploration project in the country, local paper Dnevni Avaz announced that Croatian INA, Australian Key Petroleum, French Total and British Spectrum had sent letters of intent to the Federation between late October 2015 and mid-February 2016.   .

Bosnia and Herzegovina, not found

It was confirmed in October 2019 that Alkane Energy has completed the acquisition of a 50% interest in PEDL 130 (block SK/66a) from Egdon Resources UK Ltd. The licence houses two Coal Mine Methane projects, one known as Clipstone 1 and the other is Bilsthorpe Colliery. The licence is located next door to the Eakring-Duke's Wood conventional oil field which was discovered back in 1939. Following completion of the deal, interest in PEDL 130 is held by Egdon Resources UK Ltd (50% + operator) and Alkane Energy UK Ltd (50%).

Alkane Energy has completed the acquisition of a 50% interest in PEDL 130 (block SK/66a) from Egdon Resources UK Ltd.

Petroliam Nasional Berhad (PETRONAS) – Malaysia Petroleum Management (MPM) has officially announced the 2020 Malaysia Bidding Round in an event on 30 October 2019. Eight exploration blocks, four DRO (Discovered Resources Opportunity) clusters and three Technical Study opportunities are offered. Four of the exploration blocks are located in offshore Peninsular Malaysia (PM-326, PM-416, PM-417 and PM-524) and four are in shallow to deepwater Sabah (SB-408, SB-410, SB-414 and SB-2T). The available DROs include the Diwangsa Cluster and Rhu-Ara Cluster in offshore Peninsular Malaysia, and the Bambazon Cluster and Kerisi Cluster and in shallow to deepwater Sabah. These assets provide an opportunity for quick monetization of proven oil and gas resources nearby existing facilities. Technical Study opportunities comprise two late life field technical studies (MASA Cluster in offshore Peninsular Malaysia and Tembungo field in offshore Sabah) and one gas field technical study (BIGST Cluster in offshore Peninsular Malaysia). The technical studies represent an opportunity for suitable operators to design cost-effective strategies in order to produce remaining volumes and to unlock further upside in the fields. Data room for exploration blocks and DRO clusters will be open for viewing from 2 January 2020 to 29 May 2020 via Zebra Data Sciences Ltd (EzDataRoom). Access to the data room will be available upon request to PETRONAS MPM, pending company evaluation and approval. Approved companies will be requested to sign a confidentiality agreement. Any request for clarification needs to be submitted by 15 April 2020. Deadline for bid submission is on 29 May 2020. Bids evaluation will be conducted in June-July 2020, followed by PSC approval process in Q3 2020. Finally, PSC award to successful bidders is expected to take place in Q4 2020. For the Technical Study opportunities, approved companies will be requested to sign a confidentiality agreement on 5 November 2019, prior to data review commencement on 20 November 2019. The data review period for late-life assets will end on 30 June 2020 and Expressions of Interest (EOI) will have to be submitted in July 2020. For the high-CO2 asset, deadline for technical report submission is on 30 September 2021. A detailed individual block description will be available in GEPS. The tables below would list the assets on offer. Malaysia: Exploration Blocks 2020 Block Region Basin Terrain Area (sq km) PM-326 Peninsular Malaysia Malay Basin Shelf 7,727 PM-416 Peninsular Malaysia Malay Basin Shelf 6,115 PM-417 Peninsular Malaysia Malay Basin Shelf 14,177 PM-524 Peninsular Malaysia Malay Basin Shelf 4,738 SB-408 Sabah Northwest Sabah Province Shelf 7,458 SB-410 Sabah Northwest Sabah Province Shelf 3,619 SB-414 Sabah Northwest Sabah Province Onshore/Shelf 5,753 SB-2T Sabah Baram Delta / Northwest Sabah Province Deepwater 4,987   Malaysia: DRO Clusters 2020 Asset Region Basin Terrain Fields Diwangsa Cluster Peninsular Malaysia Malay Basin Shelf Diwangsa, Bubu, Korbu, Lerek Rhu-Ara Cluster Peninsular Malaysia Malay Basin Shelf Rhu, Ara Kerisi Cluster Sabah Northwest Sabah Province Deepwater Kerisi, Kikeh Deep, Senangin Bambazon Cluster Sabah Northwest Sabah Province Shelf Bambazon, Tiga Papan   Malaysia: Technical Studies 2020   Asset Region Basin Terrain Fields Study type MASA Peninsular Malaysia Malay Basin Shelf Malong, Sotong, Anding Late life field Tembungo Sabah Northwest Sabah Province Shelf Tembungo Late life field BIGST Peninsular Malaysia Malay Basin Shelf Bujang, Inas, Guling, Sepat, Tujoh Gas field   Fiscal terms for the 2020 Bidding Round include the recent Deepwater R/C (Revenue/Cost) PSC, first introduced in 2018, as well as new non-fiscal incentives. Key features of Deepwater R/C PSC compared with the Shallow Water R/C PSC include longer contract periods for exploration, development and production stages, higher cost ceiling (80%, compared to 70% in Shallow Water R/C), profit sharing up to 80% for both oil and gas (compared to maximum of 70% for oil in Shallow Water R/C). The non-fiscal incentives include the introduction of phased exploration (to be possibly offered for frontier areas), longer exploration period, arrangements for joint studies and improved bank guarantee. For further information on exploration blocks and DROs, please contact: Block Promotion Dr Jaizan Hardi Mohamed Jais Senior General Manager Resource Exploration (REx) Malaysia Petroleum Management (MPM) PETRONAS   Zamri Baseri Head Block Promotion and Marketing Resource Exploration (REx) Malaysia Petroleum Management (MPM) PETRONAS   Email: [email protected]   For further information on Technical Studies, please contact: Asset/Field Promotion Aidil Shabudin Senior General Manager Resource Development & Management Malaysia Petroleum Management (MPM) PETRONAS   Nazrin Banu SH Sajjad Ahmad Head Discovered Resource Arrangement Resource Development & Management Malaysia Petroleum Management (MPM) PETRONAS   Email: [email protected]

Malaysia Petroleum Management (MPM) has officially announced the 2020 Malaysia Bidding Round in an event on 30 October 2019. Eight exploration blocks, four DRO (Discovered Resources Opportunity) clusters and three Technical Study opportunities are offered. Four of the exploration blocks are located in offshore Peninsular Malaysia (PM-326, PM-416, PM-417 and PM-524) and four are in shallow to deepwater Sabah (SB-408, SB-410, SB-414 and SB-2T).

In mid-November 2019, Shell suspended the new field wildcat Aster 1 in the Northeast Obaiyed block, Northern Egypt Basin. The well, which was spudded on 4 October 2019, reached TD at 5,523 m in the Lower Jurassic Ras Qattara Formation. Shell is planning to assess the Middle Jurassic the Khatatba Formation (Safa Member) and the Ras Qattara Formation. The Northeast Obaiyed block, which includes two minor gas discoveries (Jc 18 1 and Daruma 1A) has an area of 565 sq km. It was awarded to Shell Egypt NV in November 2012.

Aster 1 nfw. (Shell 100%) in Northeast Obaiyed block, susp. mid-Nov '19 at TD=5523m in the Ras Qattara Fm. Results are not available.

OKEA has agreed a deal with Equinor to acquire its 40% interest plus operatorship in PL 195 and PL 195 B, subject to government approval. The licences contain the 1988 Aurora gas discovery made by 35/8-3 which OKEA is intending to develop as a tie-back to the nearby Gjoa field without drilling an appraisal well. Estimated recoverable reserves for Aurora are 12-28 MMboe. The deal was announced on 15 July 2020. 35/8-3 encountered a gas column of 70 m (32 m of net pay) in the Upper Jurassic Heather Formation. Average porosity was 16% and average water saturation was 22%. The GWC was not penetrated. The underlying Middle Jurassic Brent Group was the main target for the well but was water-wet. Upon completion of the deal, interest in PL 195 and PL 195 B will be divided between OKEA ASA (40% + operator), Petoro AS (35%) and Wintershall Dea Norge AS (25%).

Norway (Viking Graben Province), OKEA has agreed a deal with Equinor to acquire its 40% interest plus operatorship in PL 195 and PL 195 B, subject to government approval. PL 195 operated by EQUINOR (40%), PETORO (35%), BASF (17%), L1 EN (8%).

AE-0009 block, offshore Sureste Basin, WD 43m, P&A late Sep ’18 at TD 3,730m, results not released. Target U. Miocene.

Mexico, not found

Beach Energy Ltd spudded the Barry 1 exploration well in PRL 129, located in the Cooper-Eromanga Basin, on 19 June 2018.  On 30 June 2018 the operator plugged and abandoned the well, after reaching a total depth of 2,790 m, encountering only gas shows. The well was one of several in Beach’s Cooper-Eromanga Basin exploration programme in mid-2018.  Barry 1 is located in the same licence as the Admella gas and condensate discovery, which was made in 2012.  The licence is surrounded by a number of appraising and producing gas discoveries. PRL 129, which covers an area of 87 sq km, was awarded on 8 October 2014.  Beach Energy Ltd holds 100% interest in the licence, with 50% held through wholly owned subsidiary Great Artesian Oil and Gas Pty Ltd.

Barry 1 (Beach 50%, Great Artesian O&G 50%) in PRL 129 block, P&A gas shows.

One petroleum exploration permit has been granted for Block Offer 2018. The successful bid was granted to Todd Exploration Management Services for PEP 60573, which covers an area of 105km2, east of Inglewood, in onshore Taranaki. Todd Exploration Management Services is owned by Todd Corporation, the largest privately-owned energy company in New Zealand. A number of bids were submitted for Block Offer 2018 and all underwent a robust and thorough evaluation by New Zealand Petroleum and Minerals, which is part of the Ministry of Business, Innovation and Employment. The release area for Block Offer 2018 was restricted to the onshore Taranaki region, covering 2,188 km2. It followed a law change in November 2018 that gave effect to the Government’s announcement that it would no longer grant offshore petroleum exploration permits and would restrict future block offers to the onshore Taranaki region. The change to legislation also prohibits access to conservation land, as part of the Block Offer process, except for minimum impact activities. The permit does not include any land listed in Schedule 4 of the Crown Minerals Act (including national parks, nature reserves, and wildlife sanctuaries), World Heritage sites, or areas of importance to Maori identified in section 3.1 of the Petroleum Programme (such as Mount Taranaki and the Pouakai, Pukeiti and Kaitake Ranges). More information on the permit granted is available here Original article link Source: New Zealand Petroleum & Minerals

New Zealand (Taranaki) The successful bid was granted to Todd Exploration Management Services for PEP 60573, which covers an area of 105km2, in onshore of east of Inglewood.

East Abu Sennan block, Abu Gharadiq Basin, susp oil at TD 2,409m (Kharita) late Dec ’17, Sino Tharwa “Tanmia-1” (ST-13) rig. Target Abu Roash G.

Abu Sennan E. H1 explEast Abu Sennan block, Abu Gharadiq Basin, susp oil at TD 2,409m (Kharita) . Target Abu Roash G.

UJO has further increased its 27% interest in PEDL 253 (Biscathorpe), 95 sq km south of Grimsby in Lincolnshire, by 3% from partner Montrose Industries for GBP 115,000 cash. PEDL 253 will be held by Egdon (op) 35.8%, UJO 30%, Montrose 19.2%, Humber O&G 15%.

(Anglo-Dutch) UJO has further increased its 27% interest in PEDL 253 (Biscathorpe), (95km²) south of Grimsby in Lincolnshire, by 3% from partner Montrose Industries for GBP115,000. PEDL 253 will be held by Egdon (op) 35.8%, UJO 30%, Montrose 19.2%, Humber O&G 15%.

On 18 October 2019, the Federal Agency for Subsoil Use announced an auction for five blocks in Bashkortostan Republic (Volga-Ural Province). The auction will be held on 17 December 2019. Applications must be submitted by 19 November. Each participant must make a refundable deposit equal to the starting price for the block. The deposit will be non-refundable if the winner fails to pay its winning bid. Additional information regarding the auction may be requested from: Bashnedra 450006, Ufa, Krupskoy St., 8 E-mail: [email protected] The Ashinskiy block covers 31 sq km. Hydrocarbon resources (category D1) of the block are estimated at 1 MMbbl of oil. The starting price amounts to RUB 0.355 million (USD 5,550). The winner will obtain a 25-year E&P license. The Kazayakskiy block covers 22 sq km and encompasses the Amirovskaya prospect with oil resources estimated at 5 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 2 MMbbl of oil. The starting price amounts to RUB 10.537 million (USD 0.16 million). The winner will obtain a 25-year E&P license. The Mayskiy block covers 22 sq km. Hydrocarbon resources (category D1) of the block are estimated at 2 MMbbl of oil. The starting price amounts to RUB 0.429 million (USD 6,700). The winner will obtain a 25-year E&P license. The Podolskiy block covers 20 sq km and encompasses the Boguslavskaya prospect with oil resources estimated at 2 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 1 MMbbl of oil. The starting price amounts to RUB 3.39 million (USD 0.05 million). The winner will obtain a 25-year E&P license. The Pervomayskiy block covers 82 sq km and encompasses the Alinskaya and Alinskaya Severnaya prospects with combined oil resources estimated at 3 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 9 MMbbl of oil. The starting price amounts to RUB 6.674 million (USD 0.1 million). The winner will obtain a 25-year E&P license.

Russia, not found

Metgasco Pty Ltd reported on 22 May 2019 that is has executed a Heads of Agreement (HoA) with Vintage Energy to farm-down 50% interest in exploration licence ATP 2021-P to Vintage. The permit, which is located in the Cooper-Eromanga basins, was awarded to Metgasco on 29 May 2018 and the company had been seeking a farm-in partner since acquiring the permit ahead of further exploration operations. The Agreement remains subject to regular required approvals, including ministerial approval. This is expected to finalized by 30 June 2019, after which, a formal farm-in agreement will be signed by both parties. Under the terms of the HoA, Vintage is required to contribute 65% of costs associated with drilling a first exploration well (up to AUD 5.3 million) and to also cover 65% of past exploration costs already incurred by Metgasco (AUD 527,800). The initial work programme over the permits focused on better identifying the leads, completing regional geological evaluation and refining play types. To further define existing leads, Vintage will also fund up to AUD 70,000 relating to reprocessing of 2D and 3D seismic data. ATP 2021-P is mainly prospective for Permian gas and Jurassic oil accumulations. The primary drill target, which could be tested in 2019 with an exploration well, is the Vali Prospect – an anticlinal structure at the Toolachee and lower Patchawarra levels with independent closure at a depth of around 2,250 m. Metgasco has reported that the prospect is likely to contain reservoir characteristics similar to that of the nearby Kinta 1 gas discovery. The Kinta 1 well intersected 37 m of interpreted gas pay but did not retuned hydrocarbons to surface. Vali has been assigned P50 recoverable resources of 19 Bcf. The Odin Prospect is another identified prospect, comprising an anticlinal structure on the western boundary of the permit with an independent closure at a depth of around 2,300 m. The Strathmount 1 exploration well, which was drilled in 1987, lies within the extent of the prospect. The well encountered 21 m of reservoir sands and 13.7 m of interpreted gas pay. Gas flow testing indicated returned gas to surface but at rates were too small to measure. On the 2016 Snowball 3D seismic data, Metgasco reports that the well appears to have intersected the sands outside of the Toolachee and lower Patchawarra level. Odin has been assigned P50 recoverable resources of 8.7 Bcf. ATP 2021-P, which covers an area 363 sq km, is currently 100% owned and operated by Metgasco. If the farm-in agreement is completed, participants will become: Metgasco Ltd (50%) and Vintage Energy Ltd (50%).

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

Edison (under takeover offer by Energean) farmoued out a 70% stake in its so far wholly-owned NE Hapy block to to Eni sub IEOC, who took over operatorship at the same time in March. NE Hapy covers 2,458 sq km in the deeper waters of the E. Nile Delta:

Edison (under takeover offer by Energean) farmoued out a 70% stake in its so far wholly-owned NE Hapy block to to Eni sub IEOC, who took over operatorship at the same time in March. NE Hapy covers 2,458 sq km in the deeper waters of the E. Nile Delta:

Eni and its partner Qatar Petroleum have been awarded rights to Block 24 located in in the deep waters of the Cuenca Salina Basin in Mexico. Eni will be Operator of Block 24 with 65% in joint venture with Qatar Petroleum with 35%. Block 24 is the outcome of the fourth international competitive bid round called under 'Ronda 2' by the National Hydrocarbon Commission (CNH), and allows Eni to build up and consolidate a new core area with significant operational synergies in the Country. In Mexico Eni already holds a 100% stake in Area 1 in the Cuenca Salina Basin, and it has already submitted the Development Plan to the approval of the local authorities. Eni also holds operatorship in other 3 exploration and production blocks in the same basin: Block 7 (Eni 45%), Block 10 (Eni 100%), Block 14 (Eni 60%). Eni has been present in Mexico since 2006 and established its wholly-owned subsidiary Eni Mexico S. de R.L. de C.V. in 2015.Mexico - R1 and R2 Eni awarded blocks (Source: Eni) Original article link Source: Eni

Mexico, not found

On 3 December 2018 EnQuest announced that it has completed its deal with BP to acquire the remaining 75% interest in the Magnus field, an additional 0.9% interest in the Sullom Voe Oil terminal and additional interests in associated infrastructure from BP. The deal has an economic date of 1 January 2017. EnQuest had an option on the assets following a previous deal with BP. It exercised this option on 7 September 2018. The consideration for the exercise of the option was USD 300 million (base consideration) along with the entry of a cash flow sharing agreement whereby EnQuest and BP will share the net cash flow (50:50) subject to a cap of USD 1 billion to BP. EnQuest drilled two infill development wells in 2018 targeting un-swept areas of the field. This drilling has given EnQuest a greater understanding of the subsurface and two further wells (Canute and T10/T11) are planned at Magnus. Deal completion comes approximately a year after EnQuest acquired a 25% interest and operatorship in Magnus, a 3% interest in the Sullom Voe terminal and supply facility, a 9% interest in the Northern Leg Gas Pipeline (NLGP) and a 3.8% interest in the Ninian Pipeline System (NPS) also from BP. Magnus was discovered in 1974 and is a giant Jurassic oil, gas and condensate field. The field was initially developed via a single platform with seven subsea satellite wells for production and injection located in the northern and southern parts of the field. The field was brought onstream in 1983. Following a decline in production in 1995 there was a change in the development strategy adding 13 new wells, completed with gas lift. In the same period six injectors were drilled targeting particular compartments. Then in 2000 an EOR scheme for the field was launched with WAG injection. This was followed in 2003 with miscible hydrocarbon gas injection. At the time gas from the field was a light methane/ethane gas which was too lean for optimal miscible recovery. The gas supply pipeline was therefore re-routed around Sullom Voe where the gas was enriched by injecting propane and butane. This gas supply came from Schiehallion via the West of Shetland Pipeline System to Sullom Voe and then on to Magnus for EOR. Interest in Magnus following the completion of the exercised option is EnQuest Plc (100% + operator).

BP plc, EnQuest Plc Magnus (P193), Sullom Voe Terminal, NLGP & NPS - Deal completed

Pilot Energy Ltd, (previously Rampart Energy), is looking to farm-down its 80% interest in exploration permit WA-503-P, located in the Barrow Sub-basin, North Carnarvon Basin. However, the offer remains subject to a pursued sales agreement with joint venture partner Black Swan Resources. On 27 July 2018 Pilot announced that it would be exiting the permit, assigning all interest over to joint venture partner Black Swan Resources. On 19 December 2018 Black Swan terminated the agreement upon notification that the National Offshore Petroleum Titles Administrator (NOPTA) did not approve the transaction. If the deal completed, Black Swan was required a farm-out of around 40-50% interest to fund committed 3D seismic acquisition (part of the Davros multi-client survey). As it stands, Pilot is required to free-carry Black Swan’s 20% interest through the initial work programme which provides additional security to ensure funding is available to cover the existing programme. Pilot has reported that it will look to farm-down as it seeks to develop a low-cost portfolio. Black Swan remains committed to increasing its interest in the permit which could see negotiations between Pilot, NOTPA and seismic contractor CGG. Gaining access to a seismic vessel within Australian waters during 2016/17 had been difficult due to demand and costs, thus the current phase of work commitments were suspended and extended for 24 months. The acquisition of new 3D seismic acquisition covering 80 sq km is required by 12 May 2019, as well as post-seismic interpretation and analysis. Pilot had contracted a seismic company to complete the work but cost efficiencies required a multi-client approach. Pilot subsequently reported that low acquisition costs had been contracted for the seismic programme with CGG which is scheduled to complete the Davros multi-client 3D seismic extension survey in 2019, which includes the WA-503-P area. The first well is then required between May 2021 and May 2022 but remains contingent at this stage and subject to structure mapping and the identification of suitable prospects. Pilot identified three leads within WA-503-P which have been assigned prospective resources. The Lower Cretaceous to Upper Jurassic sandstone reservoirs are located along the eastern flank of the Lewis Trough, within the oil rich Legendre Trend. The Updip Janus lead has been assessed to contain a best estimate of 14.3 MMbo within the Legendre and Eliassen formations. The Updip Orion lead has been assessed to contain a best estimate of 49 MMbo within the Legendre, Eliassen and M Australis formations. The Bojangles lead has been assessed to contain a best estimate of 8.6 MMbo within the Angel and M Australis formations. WA-503-P covers an area of 80.75 sq km and was awarded on 13 May 2014 after being offered as block W13-11 in the 2013 Federal Offshore Acreage Release. Pilot holds 80% interest in the permit and is seeking an additional farm-in partner to join with joint venture partner Black Swan Resources Pty Ltd.  Parties interested in pursuing this opportunity should contact: Iain Smith        email: [email protected] Conrad Todd   email: [email protected]

Pilot Energy Ltd, (previously Rampart Energy), is looking to farm-down its 80% interest in exploration permit WA-503-P, located in the Barrow Sub-basin, North Carnarvon Basin.

The authorities have reportedly granted block D, offshore in the Khmer Trough, to (Chinese) Cambodian Resources, the agreement signed in Dec '19. The 5,300-sq km unit (outline yet n/a) lies west of KrisEnergy's block A in shallow waters, previously run by Mirach Energy.

The authorities have reportedly granted block D, offshore to (Chinese) Cambodian Resource Energy Development Co, the agreement signed in Dec '19. The 5,300-sq km unit (outline yet n/a) lies west of KrisEnergy's block A in shallow waters, previously run by Mirach Energy.

On 17 July 2018, Parex Resources said it may trim its Colombian E&P portfolio with the Southern Casanare (SoCa) LLA-32, LLA-34 and Cabrestero blocks ear-marked for possible divestment. The move is part of an initiative to reposition itself as an "exploration driven, industry leading, high growth Colombia focused junior oil company." The SoCa asset package encompasses three contiguous blocks in the Llanos Basin that will be offered in a separate wholly-owned subsidiary, according to the company. Parex unveiled the divestment option after its board of directors determined that it is "timely, prudent and in the best interests of the company to initiate a formal process to explore, review and evaluate strategic repositioning alternatives with a view to enhancing shareholder value." While Parex indicated that the assets are perfect for a corporate buyer, it is keeping its options open for "other strategic actions that would result in the creation of additional value for shareholders." In the meantime, Parex said operations in the fields are ongoing. Parex holds 100% in the Cabrestero Block. That's where Parex in April spudded the Totoro-2 appraisal well on with the "Petrex 5857" rig. This is the first of three appraisal wells to be drilled to delimit the Q1 2018 Totoro discovery. The Totoro-1 NFW discovered oil in the Guadalupe Formation. Meanwhile, in the Parex-operated LLA-32, the company holds 87.5%. On 21 December 2017, GeoPark announced that it has signed an agreement with the operator of LLA-32, Parex, to fund the drilling of the Zamuro exploration prospect in the north of the Llanos Basin block in the second half of 2018. GeoPark Colombia (GeoPark 80% & LG 20%) already holds 12.5% non-operated working interest (WI) in the block and will increase its economic interest in the Zamuro field area to 56.25% in the event of a commercial discovery. As for LLA-34 Block, GeoPark Colombia is operator there. Parex holds 55% WI in the Llanos Basin acreage. GeoPark Colombia is planning an active drilling programme in the block. Plans include the Chiricoca-2 appraisal well as a follow up to the Chiricoca-1 discovery made in early 2017 on the northern boundary of the block. The SoCa trio produced (in Q2 2018) 38,510 boe/d, or about 9% of the company's total haul for Colombia. <P /> <P /><P />

On 17 July 2018, Parex Resources said it may trim its Colombian E&P portfolio with the Southern Casanare (SoCa) LLA-32, LLA-34 and Cabrestero blocks ear-marked for possible divestment.

On 25 March 2019, it was announced that Tullow Pakistan (Developments) Ltd had assigned its entire 30% working interest in the OGDCL-operated Kohlu 2968-3 EL (Sulaiman Fold Belt) onshore licence to Ocean Pakistan Ltd effective from 13 March 2019. As a result of this transaction the revised equity split is as follows: Oil and Gas Development Company Ltd (OGDCL) (40%, operator), Mari Petroleum Co Ltd (30%) and Ocean Pakistan Ltd (30%). OGDCL was granted an additional one-year extension to the initial exploration period of the licence from 1 January 2019 till 31 December 2019. The licence, located in the Balochistan province, covers an area of 2,459 sq km. The company has not drilled any well in the licence area to date.  Background Information The licence was awarded to OGDCL (60%, operator) and Mari Gas Co Ltd (MGCL) (40%) on 29 December 2004. MGCL subsequently changed its name to Mari Petroleum Company Limited (MPCL) with effect from 19 November 2012. One well is known to have been drilled previously on the acreage - Tadri 1, which was P&A dry at a depth of 1,826m in the Jurassic Chiltan Formation by Amoco in December 1975. The work programme for the initial three-year exploration phase is believed to include G&G studies and gravity / seismic acquisition during the first year, the drilling of three exploration wells during the second year and the drilling of one optional exploration well during the third year. OGDCL assigned a 20% working interest to Tullow Pakistan (Developments) Ltd with effect from 25 February 2006 and the company received a further 10% working interest from MGCL with effect from 20 May 2006.

Tullow sells its 30% in Kohlu 2968-3 EL, 2,459 sq km in Balochistan, Sulaiman Fold Belt, to Ocean Pakistan. Resulting partnership (OGDC (op), Ocean Pakistan + Mari Petr.

As of 20 June 2019, ConocoPhillips announced plans to purchase 11 tracts covering an area of 21,004 ac (85 sq km) on the North Slope from Caelus Natural Resources. The acreage is located around 5 mi (8 km) southwest of the Oooguruk field, operated by Eni, and encompasses the 2012 Nuna oil discovery, which could hold between 75 and 100 MMbbl in reserves. The transaction is subject to the authorities’ approval and, upon completion, will enable ConocoPhillips to further strengthen its position in the North Slope Basin. The next step for the company will be to appraise the find and potentially develop it to expand the current production. ConocoPhillips is Alaska’s largest producer with an output of 186 MMboe/d (92% oil, 7.5% NGL and 0.5% gas) in 2018, and largest owner of exploration acreage with some 1.3 million of net undeveloped acres (5,260 sq km) at year-end.

ConocoPhillips is picking 11 North Slope ADLs: 355036-355039, 390434, 390505, 390506, 390697 and 392158. of acreage near the Kuparuk field (North Slope B.) from Caelus Natural Resources. This includes the Nuna oil discovery.

Black Swan Resources Pty Ltd is looking to farm-down its 100% equity in exploration permit WA-503-P, located in the Barrow Sub-basin, North Carnarvon Basin. Black Swan reports that the opportunity offers a low-cost entry to complete the third-year work programme which involves the licensing of speculative 3D seismic data at a cost of AUD 1 million for 350 sq km. In return for the purchase of the seismic data, plus a cash component, Black Swan is offering 40 to 50% interest in the permit. One contingent exploration well is scheduled in the final permit term - by May 2022. By this time, Black Swan may look to further farm-down its interest to attract a drill partner. In July 2018, previous operator Pilot Energy was also looking to farm-down its interest before exiting the permit by transferring all interest to joint venture partner Black Swan. The licensing of 80 sq km of new Broadband 3D seismic data is required by 12 May 2019. The acquisition of data was initially required by May 2015, however the joint venture applied to alter the work programme to combine the first three years’ work programme into one period. This was allowed after alterations to the offshore permit guidelines were made in May 2015, offering operators the option to change to the more streamlined work programme process. A number of work programme variations were granted, pushing back the required work programme. Gaining access to a seismic vessel within Australian waters during 2016/17 had been difficult due to demand and costs. Pilot contracted a seismic company to complete the work but cost efficiencies required a multi-client approach. It’s thought that the two wells present within WA-503-P: Janus-1 and Orion-1, where drilled off structure on 2D seismic data. Black Swan has identified three, up-dip, prospects which have been assigned prospective resources. The Lower Cretaceous to Upper Jurassic sandstone reservoirs are located along the eastern flank of the Lewis Trough, within the oil rich Legendre Trend. The Updip Janus lead has been assessed to contain a best estimate of 14.3 MMbo within the Legendre and Eliassen formations. The Updip Orion lead has been assessed to contain a best estimate of 49 MMbo within the Legendre, Eliassen and M Australis formations. The Bojangles prospect has been assessed to contain a best estimate of 8.6 MMbo within the Angel and M Australis formations. WA-503-P covers an area of 80.75 sq km and was awarded on 13 May 2014 after being offered as block W13-11 in the 2013 Federal Offshore Acreage Release. Black Swan Resources Pty Ltd is offering a farm-in opportunity in return for funding the upcoming exploration work programme. Parties interested in pursuing this opportunity should contact: Conrad Todd, Director Black Swan Resources Email: [email protected] Phone: +61 (0) 425 771 960

Australia Black Swan Resources Pty Ltd looking for a partner in WA-503-P, North Carnarvon Basin

On 27 March 2018, the consortium of DEA, Premier, and Sapura, was granted a preliminary award for the 528 sq km Area 30, AS-CS-14 block from the CNH-RO3-LO1/2017 Bid Round.  The final official contract signature award is to take place within 90 days or 1 July 2018. The consortium bid the maximum state take of 65.00% over the minimum of 22.5% for the Area 30 block and a work units factor of 1.5 equivalent to two wells.  Additionally the company bid a tie-break bonus of USD 51.15 million to win the block. The provisional consortium working interest breakdown is estimated to be DEA, operator with 33.34% working interest, Premier with 33.33%, and Sapura with 33.33% working interest. There were six other bids for the block.  The second highest bidder was the consortium of ENI and Lukoil who bid 65% state take, 1.5 additional work units factor, and a tie-break bonus of USD 46.87 million.  This was the most contested block in the bid round.  

the consortium of DEA, Premier, and Sapura, was granted a preliminary award for the 528 sq km Area 30, AS-CS-14 block from the CNH-RO3-LO1/2017 Bid Round.

Petrobras was drilling with oil shows on the 9-MLL-079D-RJS (9-MLL-079D-RJS) special directional outpost in the Marlim Leste production concession block during early-March 2018.  Petrobras filed an oil show report with the ANP for the well on 28 February 2018. Petrobras has 100% working interest in the Marlim Leste contract.       

9-MLL-079D-RJS op. by Petrobras (100%) in Marlim Leste lease, P&A oil shows, Target assumed Macabu fm.

As of 19 August 2018, BPZ E&P has plugged and abandoned the Delfin Sur-1X exploration well located in Block Z-1 offshore in the Tumbes Basin. The well is located approximately 2 km southeast of the Delfin-05 wildcat well drilled in 1973 which discovered oil & gas in the Lower Miocene Zorritos Formation. As dry after reaching an approximate depth of 7,250 ft (2,210 m). The Delphin-1X spud on 15 July 2018 using the Petrex-10 rig. The well is targeting was large structure with a proposed total of approximately 10,550 ft (3,216 m) looking at deeper formations below the Lower Miocene Zorritos and Cardalitos formations which have already proven productive to the northwest. The 1,892.67 sq km Block Z-1 was officially awarded in January 2002 and was originally comprised of 3,144 sq km to Syntroleum Peru Holdings Ltd (95%) and BPZ Energy Inc, Sucursal Peru (5%). In March of 2004 Nuevo Energy Co acquired Syntroleum Peru Holdings Ltd working interest. Nuevo Energy Co sold its interest to Plains Exploration & Production Co who in turn sold the interest in the block to partner BPZ in February 2005. BPZ then brought in Pacific Rubiales Energy Corp in December 2012 who became Frontera Energy. BPZ was acquired by Zedd Energy Holdco Ltd in July 2015 but the company continues under the name of BPZ E&P.

Delfin Sur 1X (Zedd Energy Holdco op. 51%, Frontera Egy. 49%) in Block Z-1, offshore Jambeli sub-basin. P&A, evaluated the Miocene Zorritos Fm where hydrocarbon shows were encountered but not in sufficient quantities to justify further evaluation. TD=2203m in Miocene Heath Fm.

Luntai area, Tabei Uplift in Tarim Basin, ops terminated at TD 8,882m on 17 Jul ’19, reportedly record depth onshore in Asia. Target Cambrian carbonates.

China (Tabei Uplift (Tarim B.)) Luntai

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 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.

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

Somalia’s 2019 licensing round is scheduled to launch on 7 Feb ’19 in London, although a last-minute postponement is not excluded. A final block delineation will then be revealed, about 50 units totalling over 173,000 sq km will be presented, as well as the country’s legal + regulatory framework, petroleum laws, local capacity, fiscal terms, round timing, inter alia. Spectrum-supported presentations are also planned in Dubai and Houston and Dubai, details to follow. The round closes on 11 Jul ‘19. Spectrum has acquired and processed 20,185km of 2D long-offset seismic data in WD 30-4,000m, complementing 20,500km of 2014 data. Map extract below Spectrum.

Somalia’s 2019 licensing round is scheduled to launch on 7 Feb ’19 in London, although a last-minute postponement is not excluded. A final block delineation will then be revealed, about 50 units totalling over 173,000 sq km will be presented, as well as the country’s legal + regulatory framework, petroleum laws, local capacity, fiscal terms, round timing, inter alia.

Arenal block, Magallanes Basin, completed gas (tight Zona Glauconitica fm) in Dec '19, no specifics.

Chile (Austral B.) ? op. by ENAP (100.0%, ENAP 100.0%) in Arenal block

Lattice Energy Ltd, a Beach Energy subsidiary, spudded the Beharra Springs Deep gas exploration well in L 11, located in the Canning Basin, in early October 2019. The well is being drilled by the "EWG 106" land rig. On 28 October 2019 Beach Energy reported that it was completing wireline log operations, after reaching a total depth of 4,170 m. Initial results of the logging have indicated a gas discovery within the Kingia Formation. During drilling, a 65 m reservoir interval was intersected within the Kingia unit, between 3,935 and 4,000 m, with the operator reporting estimated net pay of 36 m. Wireline logging is being undertaken across this unit and have determined average porosity of 14.5% and preliminary interpretations indicate reservoir porosity could be up to 21%. The well was targeting gas within the Kingia and High Cliff sandstones, with possible additional targets in the Dongara and Wagina units. It was targeting stacked gas pools, like those seen in the Waitsia field, discovered in September 2014. Waitsia was considered to be the largest onshore gas discovery in 50 years in the basin. Beharra Springs Deep 1 spudded a little later than planned, being outlined for Q3 2019. The well was reported to be a drill ready prospect as of February 2018, with well planning then taking place in 2H 2018. Beharra Springs Deep 1 was originally planned to be spudded in 1H 2019, but this was revised part way through the year. L 11, which covers an area of 75 sq km, was awarded on 15 May 1992. Participants in the permit are Lattice Energy Resources Pty Ltd (50% + Operator) and AWE (Beharra Springs) Pty Ltd, a Mitsui subsidiary, (50%). The companies hold this interest after an alignment agreement was entered into on 3 July 2019, which saw Beach and AWE agree to share 50:50 ownership of their shared assets in the basin, including L 11.

Australia (Beharra Springs Terrace (Perth B.)) Waitsia

On 20 February 2018, the award of the Somogyvámos contract in southwestern Hungary, pre-awarded to Magyar Olaj- es Gazipari Rt (MOL) in November 2017, was signed off by the Minister for National Development and thus became official. The 1,280 sq km Somogyvámos area is located in the Somogy and Zala political provinces, within the Pannonian Basin. Background Information On 13 June 2017, acting on behalf of the Hungarian State and in cooperation with the Hungarian Office for Mining and Geology, the Minister for National Development published an invitation to tender for a concession over the Somogyvámos area. The tender closed on 25 September 2017. On 17 November 2017, following recommendation of the tender committee from the Hungarian Office for Mining and Geology, MOL was selected as the winner of the bid round for the prosection, exploration and production of hydrocarbons in the Somogyvámos area. The company had two months (plus additional two months extension) to negotiate the final contract.

Hungary, not found

Zennor Petroleum exited licence P1242 and CalEnergy acquired the 11% interest in licence P1242 from Zennor Energy on 21 July 2020. The licence covers two blocks (47/5b and 48/1a) and an area of 53 sq km. Block 48/1a hosts the Platypus gas discovery and the Platypus East prospect. The Platypus Field Development Plan (FDP) and Environmental Statement was submitted to the Oil and Gas Authority (OGA) and Offshore Petroleum Regulator for Environment and Decommissioning (OPRED) in October 2019 but sanction has been delayed from Q2 2020. The FDP involves drilling two development wells down to around 3,100 m. The wells are to be connected to a subsea manifold and gas will be transported to the Cleeton Wellhead platform through a 23 km pipeline. The field is forecast to achieve peak production of approximately 47 MMcfg/d and have a field life of approximately 20 years. The project was expected to be sanctioned in Q2 2020 but, due to COVID-19 and the low oil and gas price, the project sanction has been delayed. First gas will be achieved less than two years after sanction. The Platypus gas field was discovered by Dana in 2010. The discovery well (48/1a-5) encountered a 66 m thick Rotliegend Lower Leman Sandstone reservoir section and it was suspended as a future producer. In 2012, the 48/1a-6 horizontal appraisal well drilled through 945 m section of reservoir and flowed gas before also being suspended as a future producer. Partner in the licence, Parkmead, disclosed in 2019 that Platypus is estimated to contain 105 Bcfg of recoverable reserves in the mid-case. In addition, the acreage could also have potential upside in the Platypus East prospect, which may contain 51 Bcf of reserves. Interest in P1242 is held by Korea National Oil Corp (KNOC) through subsidiary Dana Petroleum (E&P) Ltd (59% + operator), CalEnergy Gas Ltd (26%) and Parkmead (E&P) Ltd (15%).

United Kingdom (Anglo-Dutch B.) Cleeton op. by PERENCO (100%)

West of CA-1 field in BOFF ML, Bombay offshore, P&A'ing at TD 2,130m during early May '20, Sagar Shakti JU.

India (Bombay B.) CA C op. by ONGC (100%), total depth 2130 m, water depth 28 m

Pakistan Petroleum Ltd (PPL) has been exclusively awarded the Punjab 3073-5 EL (Indus Basin) exploration licence on 18 November 2019. The licence covers an area of 2,411 sq km and it is located in the Pakpattan, Bahawalnagar, Sahiwal and Okara districts of Punjab province. The block was offered under the ‘Onshore Bid Round 2018’ and it is awarded to PPL after the highest bid from SPEC was rejected by the government. The bidding round was launched from 13 September 2018 to 26 November 2018 under which 10 onshore blocks were offered.

Pakistan Petroleum Ltd (PPL) has been exclusively awarded the Punjab 3073-5 EL (Indus Basin) exploration licence

EP 469, onshore Perth Basin, ops terminated at TD 5,100m after completion of perfs in the Kingia sst + installation of the 3-1/2" tubing, EWG rig 106 released. Two weeks of testing are planned in October. Strike (op), partner Warrego.

EP 469, onshore Perth Basin, ops terminated at TD 5,100m after completion of perfs in the Kingia sst + installation of the 3-1/2" tubing, EWG rig 106 released. Two weeks of testing are planned in October. Strike (op), partner Warrego.

Wellesley acquired 40% interest from Total and 20% interest from Spirit in PL 685 with effect from 1 July 2018. Four months later, in the same licence, Wellesley then transferred 40% of its equity to Aker BP with effect from 30 November 2018. Both deals were announced on 6 December 2018. The licence covers a 407 sq km area over parts of blocks 34/6, 35/1 and 35/4. The acreage covered by the licence has yet to be drilled. It lies in between the Peon and Garantiana discoveries. The Peon discovery well was located on the apex of a mound structure and targeted a Pleistocene fluvio-glacial / glacio-marine sand body at a very shallow level. A 38 m thick, homogenous, unconsolidated sand was encountered at 574 m (named the Peon Sandstone of the Nordland Group) and 19 m of this contained very dry gas (99.5 vol% methane). The well was re-entered for testing in 2006 but the planned test could not be carried out. Equinor is currently considering developing Peon. If the development of Peon does go ahead it is likely to use an unmanned, remotely operated, stand-alone platform. Estimated recoverable reserves are approximately 690 Bcfg. Total discovered Garantiana in 2012 with 34/6-2 S. The Cook Formation was oil-bearing (gross oil column of 100 m) and was tested at a rate of 4,300 bo/d through a 28/64” choke. Downdip sidetrack 34/6-2 A found the OWC which had not been encountered in the original hole. In 2014 the find was appraised by 34/6-3 S. This well proved a 120 m gross oil column in a very good quality Cook Formation reservoir with no OWC. On test the well flowed at a stable rate of 5,912 bo/d through a 24/64” choke and a maximum rate of 6,919 bo/d through a 28/64” choke. Recoverable reserve estimates were increased to 38-88 MMbo. The reservoir lies at a depth of approximately 3,810 m and has a porosity of 20%. Garantiana partner Point Resources confirmed in April 2018 that the Equinor-operated field will be developed as a subsea tie-back. The host facility was due to be chosen later in 2018. Earlier reports from Wood Group in 2017 showed that the hosts which were being considered were Equinor’s Gullfaks B and Visund facilities. Following the completion of both deals, interests in PL 685 are divided between Aker BP ASA (40% + operator), Wellesley Petroleum AS (40%) and Petoro AS (20%).

Norway (Tampen Spur (Viking Graben Province)) Visund

Guzor District in Kashkadarya, S. Uzbekistan, TD 3,300m, tested 8.5-10 MMscf/d + condensate from between 3,065-3,133m. The reservoir is to be evaluated, appraisal drilling planned. Target Callovian-Oxfordian carbs. The discovery is likely Yangi Guzar-1 (ca. 2012).

Yormok-3 appr Guzor District in Kashkadarya, S. Uzbekistan, TD 3,300m, tested 8.5-10 MMscf/d + condensate from between 3,065-3,133m. The reservoir is to be evaluated, appraisal drilling planned. Target Callovian-Oxfordian carbs. The discovery is likely Yangi Guzar-1 (ca. 2012).

It is understood that Naftna Industrija Srbije (NIS) has made a discovery with Bradarac-Maljurevac 1X (Bra-Malj-001X) NFW. It was drilled in Q1 to Q2 2019, and tested during the second half of the year. Bra-Malj-001X is located near the Romanian border on the NE corner of the Juzna Srbija exploration licence. This is the first of a planned eight well Bradarac-Maljurevac exploration and appraisal programme. Juzna Srbija covers 66,000 sq km in the Pannonian Basin, southern Serbia, and was awarded on 1 April 2010 until 31 December 2020. Previously in Q2 2014 NIS acquired the Sirakovo 3D seismic survey which covered 71 sq km in the NE of the licence. NIS operates the licence with 100% equity.

Naftna Industrija Srbije (NIS) has made a discovery with Bradarac-Maljurevac 1X (Bra-Malj-001X) NFW.

Petrobras has submitted an expression of interest to exercise a 30% pre-emption right for the Sudoeste de Tartaruga Verde area to be offered in the upcoming 5th round under the production-sharing régime.  Assuming auction results confirm the minimum stake in the block, signature bonus will be USD 5.5 MM. The 5th PS round will be held on 28 Sep ‘18.

Petrobras has submitted an expression of interest to exercise a 30% pre-emption right for the Sudoeste de Tartaruga Verde area to be offered in the upcoming 5th round under the production-sharing régime. Assuming auction results confirm the minimum stake in the block, signature bonus will be USD 5.5 MM. The 5th PS round will be held on 28 Sep ‘18.

Zennor Petroleum is offering an opportunity for interested parties to farm-in to licence P2310 (2/5b) containing the Middle Jurassic Brent SW Heather discovery. Zennor is looking for parties to fund the development of SW Heather. The development concept involves a 35 km subsea tieback to the Ninian Central platform. An alternative development option could involve using a standalone FPSO.  Zennor has derived a best technical reserve estimate of 31 MMboe. P2310 was awarded in May 2017 during the 29th Licensing Round. In Q3 2017 Zennor reprocessed its 3D seismic data to develop a new structural interpretation of the discovery. Zennor is currently undertaking reservoir modelling while also integrating well data from analogue fields in the area. As of January 2019, the opportunity was still available. SW Heather is interpreted as a faulted anticline located 8 km south of the Broom field and discovered from Union’s three well drilling campaign to define the trap. Discovery well 2/5-10 drilled in 1979 tested a cumulative 6,000 bopd from the Emerald, Brent and Triassic sands. The shallow marine transgressive Emerald and Brent sands comprised of a 144 ft package with reservoir parameters of 60% N/G, 18% porosity and 40% Sw. Based on RFT data the sands are in pressure communication. The recovered oil from the Brent was 33.8-34.8° API and a 330-350 m GOR was derived. The underlying Triassic Cormorant Formation is also oil bearing and flowed on test after acidisation. The interval consisted of a 78 ft net reservoir, 16% porosity and 48% Sw.   Well 2/5-11 was drilled down-dip in 1979 but encountered water bearing Brent. Well 2/5-16ST drilled in 1983 and targeted reservoirs up-dip but was interpreted as dry. However, Zennor believe the well was drilled heavily overbalanced from poor hole conditions encountering several drilling problems. More recent geochemical analysis indicates the presence of oil in the well cuttings which were previously interpreted poorly.   Zennor North Sea Limited holds 100% interest in P2310. A data room will be available in Zennor’s Guildford offices in Q2 2018. For further information please contact: Graham Cooper, Commercial Director Tel+44 (0)1483 500940 Email: [email protected]

Zennor Petroleum is offering an opportunity for interested parties to farm-in to licence P2310 (2/5b) containing the Middle Jurassic Brent SW Heather discovery. Zennor is looking for parties to fund the development of SW Heather.

Hibiscus's July agreement to acquire licence P2366 from United O&G and Swift Exploration for up to USD 5 MM cash is now a done deal effective 4 Dec '19. Anasuria Hibiscus now holds a 100% stake in the 13.6-sq km unit (blocks 15/18d + 15/19b NE of Aberdeen) which contains the Crown discovery, 4-8 MMbbl contingent 2C. Given proximity to the company's Marigold + Sunflower oilfields a tie-back devt could be envisaged. http://www.hibiscuspetroleum.com.

United Kingdom, P2366

Chengdao field area, Bohai Gulf shallow waters, tested 416 bo/d from the Dongying fm during Feb ‘18.

Chengbei-Xie 822 appr China (Bohai Gulf B.) ? op. by SINOPEC SH (100.0%) in Chengdao block tested 416 bo/d from the Dongying fm.

Chachahuén Sur block, NE Neuquén Basin in Mendoza, drilled May ’19, TD 1,353m. Target L. Centenario fm. YPF (op), partners Phoenix Global Res + EMESA.

Cerro Guadal (2019)-4 nfw Chachahuén Sur block, NE Neuquén Basin in Mendoza, drilled May ’19, TD 1,353m. Target L. Centenario fm. YPF (op), partners Phoenix Global Res + EMESA.

According to local reports in late-September 2019, state company YPFB‘s subsidiary, YPFB Chaco, has suspended the Colorado X10D shallower pool wildcat (SPW) well in El Dorado Oeste block with unreported result in early-August 2019. The well was previously tested in July 2019 after reaching the total depth (TD) of 4,360 m (14,304 ft) earlier in the same month. Colorado X10D was spudded in April 2019 on the El Dorado Oeste gas field area with planned total depth (PTD) of 4,400 m (14,436 ft) and objectives in shallow Oligocene Upper to Pliocene Chaco Group as well as the field’s producing Iquiri Formation. El Dorado Oeste block covers 888 sq km of land in the Foothill Belt of Chaco Basin. Background Information El Dorado Oeste field was discovered and put on-stream in February 2014. The field has produced over 19 Bscfg and 933 Mbc from the Iquiri Formation sandstone as of early-2019.

Bolivia (Chaco Foothill Belt (Chaco B.)) El Dorado Oeste

On 13 August 2018, partner Echo Energy reported the conclusion of initial testing on the Estancia La Maggie x-1004 new pool wildcat well on the Santa Cruz I Fraccion C Block, Austral Basin. Dry gas was produced to surface and the well was suspended for further hydraulic stimulation. The well was drilled into the Lower Tobifera pyroclastic layer at 1,760m TD. In last May over 40m of gas shows were reported in the Upper Tobifera level with gas peaks of more than 195,500 ppm of C1-C5 hydrocarbons. 14.5m of net pay were identified within the section. It was spud on 8 May using the Petreven H-205 rig. The well is located 4km northeast of the Estancia la Maggie Field gas facilities. It ended drilling on 18 May and the mean gas initially in place was estimated to be 38 Bcfg. The Quintana-1 rig was used for completion but will be moved to the Santa Cruz I Fraccion D to complete and test the Canadon Seco 2001(d) well where the company announced a potential 30m net pay in the Upper Tobifera series. The company, is also calling for tenders for a planned 2,000 sq km 3D seismic survey to be acquired across Fraccion C, D and the Tapi Aike licenses. The survey is expected to start in the third or fourth quarter of 2018.

Echo Energy reported the conclusion of initial testing on the Estancia La Maggie x-1004 new pool wildcat well on the Santa Cruz I Fraccion C Block, Austral Basin. Dry gas was produced to surface and the well was suspended for further hydraulic stimulation. The well was drilled into the Lower Tobifera pyroclastic layer at 1,760m TD.

In June 2017, BG Egypt SA (Shell) was awarded the Harmattan Deep (Dev) lease after relinquishing the El Burg Offshore exploration block. BG was the operator of the El Burg Offshore exploration block with 60% interest. BP was holding the remaining 40%. Background information In January 2007, BG completed a 575 sq km 3D seismic survey in the block. The contractor is PGS and CGG will process the data. The survey started in October 2006. On 5 May 2006, the group completed a 1,113 sq km 3D shallow marine seismic survey in the block. In August 2008, BG plugged and abandoned El Burg 1 (Jf 67-1) wildcat in the 1,463 sq km El Burg Offshore exploration block at a TD of 3,032m. The well was spudded on 18 June 2008 with a PTD of 3,026m and objectives in the Pliocene and Miocene. In late July 2012, BG Egypt SA completed the Harmattan Deep 1 wildcat in the El Burg Offshore concession as a gas and condensate well. The well was spudded in early June 2012, using the “Senusret” J/U and was drilled to TD of 2,775m in the Qawasim Formation. It has objectives in the Pliocene and Miocene layers. In August 2012, BG Egypt SA completed a 3D seismic data over El Burg Offshore concession. On 1 May 2014, BG Egypt SA reported that the Notus 1 wildcat in the El Burg Offshore concession had discovered gas in several zones. The results are being assessed ahead of discussions with the government regarding possible development plans. The well was spudded in September 2012 with the “Ralph Coffman” Jack-Up and drilled to a depth of 7,200 m by the end of 2013. BG is the operator of the concession with a 60% interest and its partner Petronas Carigali Overseas Sdn BHD, holds the remaining 40%.

BG Egypt SA (Shell) was awarded the Harmattan Deep (Dev) lease after relinquishing the El Burg Offshore exploration block. BG was the operator of the El Burg Offshore exploration block with 60% interest. BP was holding the remaining 40%.

The Ministry of Energy and Petroleum is offering 33 open blocks on an open door policy. As of early 2018, the open blocks were:  Basin Names Block Name Block Sqkm Chad Basin~Termit Trough - Chad Basin Aborak 24,760 Chad Basin~Grein-Kafra Trough~Tenere Rift - Chad Basin Achegour 17,012 Iullemmeden Basin~Tahoua Depression (Iullemmeden Basin) Ader 31,174 Chad Basin~Bilma Trough - Chad Basin~Djado Basin Araga 28,196 Iullemmeden Basin~Mantass Depression (Iullemmeden Basin) Azawak 29,085 Iullemmeden Basin~Mantass Depression (Iullemmeden Basin)~Tahoua Depression (Iullemmeden Basin) Dallol 41,248 Chad Basin~Iullemmeden Basin Damagaram 29,680 Chad Basin~Termit Trough - Chad Basin Dibella 1 20,418 Chad Basin~Bodele Sub-basin (Chad Basin) Dibella 2 29,628 Djado Basin~Chad Basin Dissilak 19,924 Djado Basin Djado 1 14,121 Djado Basin Djado 2 12,694 Djado Basin Djado 3 11,288 Djado Basin Djado 4 11,981 Chad Basin~Tenere Rift - Chad Basin~Grein-Kafra Trough Grein 16,010 Chad Basin Homodji 33,118 Tamesna-Talak Depression (Iullemmeden Basin)~Iullemmeden Basin Irhazer 25,758 Djado Basin~Chad Basin Karama 30,347 Chad Basin~Termit Trough - Chad Basin Manga 1 12,258 Chad Basin~Termit Trough - Chad Basin~Ngel Edji Trough - Chad Basin Manga 2 11,712 Termit Trough - Chad Basin R5 2,710 Tihemboka Arch R6 3,055 Chad Basin~Djado Basin~Grein-Kafra Trough~Hoggar Massif Seguedine 22,570 Iullemmeden Basin~Tahoua Depression (Iullemmeden Basin) Tadarast 39,972 Chad Basin~Hoggar Massif Tafassasset 21,965 Iullemmeden Basin~Tamesna-Talak Depression (Iullemmeden Basin)~Tahoua Depression (Iullemmeden Basin)~Air Massif Talak 30,120 Iullemmeden Basin~Tamesna-Talak Depression (Iullemmeden Basin) Tamesna 25,711 Tahoua Depression (Iullemmeden Basin)~Iullemmeden Basin~Nigerian Shield Tarka 43,342 Djado Basin Tchigai 21,160 Iullemmeden Basin~Chad Basin~Nigerian Shield Tegama 32,193 Chad Basin~Termit Trough - Chad Basin~Tefidet Rift - Chad Basin~Tenere Rift - Chad Basin Tenere Ouest 22,367 Iullemmeden Basin~Mantass Depression (Iullemmeden Basin)~Voltaian Basin Tounfalis 37,741 Mantass Depression (Iullemmeden Basin)~Iullemmeden Basin Yaris 30,807 Source, IHS Markit 2018

The Ministry of Energy and Petroleum is offering 33 open blocks on an open door policy.

Rumours abound that prior to the recent formation of the ANPG, the 2019 Bid Round was set to include around 10 blocks in the Namibe and Kwanza basins, as well as on the Congo Fan. An offshore bid round is now not expected until Q3 ’19, while an onshore one may wait until 2020.

Rumours abound that prior to the recent formation of the ANPG, the 2019 Bid Round was set to include around 10 blocks in the Namibe and Kwanza basins, as well as on the Congo Fan. An offshore bid round is now not expected until Q3 ’19, while an onshore one may wait until 2020.

On 10 February 2020, Wintershall Dea signed a concession agreement with the Egyptian Ministry of Petroleum and Natural Resources to operate the East Damanhur block, onshore Nile Delta. According to the initial commitments stated in the award procedure, the agreement should include a minimum expenditure of USD 43 million for exploration operations and a signature bonus (undisclosed amount) for the drilling of 8 exploration wells. During the first exploration phase of three years, starting in 2020, the company is planning to drill several exploration wells. The East Damanhur block is located to the west of Wintershall Dea’s Disouq development block. It covers an area of 1,464 sq km and includes four dry exploration wells drilled between 1968 and 2011. It was awarded to Dea in February 2019, three months before Dea and Wintershall completed the merger of the two companies.

Wintershall Dea GmbH signed E&P operation agreement for East Damanhur block, onshore Nile Delta

Arrow Exploration has reached an agreement with Canacol to acquire much of Canacol’s Colombian assets for USD 40 MM in a cash-and-share deal. It is expected to close by end-July. Concurrently with this, Arrow has agreed to become a wholly-owned subsidiary of Front Range Resources. Each move should close concurrently and completion of either is required for the other to become effective. The Canacol – Arrow deal excludes Canacol’s interest in the Rancho Hermoso block and its unconventional oil portfolio in the Mid-Mag.

Arrow Exploration has reached an agreement with Canacol to acquire much of Canacol’s Colombian assets for USD 40 MM in a cash-and-share deal. It is expected to close by end-July.

Total and Sonatrach have signed agreements as part of their partnership announced in 2017, - A new concession contract to jointly develop the Erg Issouane gasfield in the Tin Fouyé Tabankort Sud permit, signed between Total (49%), Sonatrach (51%) + Alnaft. TFTS sports over 100 MMboe, project investment ab. USD 400 MM, to tied-back to the existing TFT gas treatment unit by a 22km pipeline with 1st gas late 2021. This deal comes with a gas marketing agreement. - A shareholder agreement to create the ‘STEP’ (Sonatrach Total Entreprise Polymères) 51:49 JV, designed to run a  joint petchem (propane dehydrogenation + polypropylene production) project in Arzew, W. Algeria. The FEED stage starts after Nov ’18.

Total and Sonatrach have signed agreements as part of their partnership announced in 2017, - A new concession contract to jointly develop the Erg Issouane gasfield in the Tin Fouyé Tabankort Sud permit, signed between Total (49%), Sonatrach (51%) + Alnaft. TFTS sports over 100 MMboe, project investment ab. USD 400 MM, to tied-back to the existing TFT gas treatment unit by a 22km pipeline with 1st gas late 2021.

Los Caldenes block, Neuquén Basin, P&A o&g shows at TD 2,890m in Sep ‘18. PTD was 3,020m, targets Sierras Blancas + Quintuco fm’s.

Argentina (Neuquen Embayment (Neuquen B.)) Los Caldenes

On 22 January 2018 Lundin announced that it has increased the ultimate recoverable reserves at Edvard Grieg by 51 MMboe (since the end of 2016) to 274 MMboe and that this represents a 47% increase compared with the PDO. Good drilling results and production performance have indicated that the oil in place volumes are 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). In early 2017 Lundin drilled Edvard Grieg appraisal well 16/1-27 on the southwestern flank of the field. It proved a 15 m gross oil column in a 94 m thick Cretaceous and Triassic / Jurassic sandstone, considerably thicker than the pre-drill estimates of 38 m, with excellent reservoir quality. Top reservoir was penetrated deeper than expected and the OWC was confirmed at 1,948 m, 9 m deeper than prognosed for this part of the field. Results indicated a resource upside of between 10 and 30 MMboe for this part of the field and provided information which will help with the placement of future production and water injection wells. During 2016 Lundin announced a reserves upgrade from 186 MMboe (in the PDO) to 223 MMboe (including the adjacent Tellus field) following the success of appraisal well 16/1-23 S, drilled on the southeastern part of the field in 2015, and two water injection wells drilled in 2016 which proved more oil in the western flank. Lundin achieved first production from Edvard Grieg on 28 November 2015. The field has been developed using a processing platform with oil piped to Grane for onward export to Sture and gas exported to the UK through the SAGE pipeline. Plateau production was reached in December 2016 at 100,000 boe/d and the platform processes 160,000 boe/d with production from neighbouring Ivar Aasen. Interest in Edvard Grieg is held by Lundin Norway AS (65% + operator), OMV (Norge) AS (20%) and Wintershall Norge AS (15%).

Lundin (65% + op, OMV 20%, Wintershall 15%) announced that it has increased the ultimate recoverable reserves at Edvard Grieg by 51 MMboe (since the end of 2016) to 274 MMboe and that this represents a 47% increase compared with the PDO. Good drilling results and production performance have indicated that the oil in place volumes are 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 Ministry of Climate (Ministry of Environment previously) is preparing to open new tender call – Round 4 – for five areas located in the country's various tectonic units. The acreage inventory includes the areas Bestwina-Czechowice (83 sq km), Krolowka (189 sq km), Pyrzyce (1,172 sq km), Zloczew (702 sq km) and Zabowo (1,000 sq km). As disclosed in late December 2019, the tender documents have been submitted for publication in the EU Official Journal (EUOJ) - the opening of the tender is expected during the first quarter of 2020. In preparation for the tender, the officials have set up a data-room that is available for the potential participants immediately. Further information on the upcoming bid round is available at the Departament Geologii i Koncesji Geologicznych (Department of Geology and Geological Concessions), Wawelska 52/54, 00-922 Warszawa, Poland, Tel.: +48 22 369 2449, E-mail: [email protected] The Bestwina-Czechowice and Krolowka areas are located in southern Poland (Upper Silesian Coal Basin and frontal part of the Carpathian Flysch Zone, respectively). The Zloczew area is located in central Poland (eastern limit of the Fore-Sudetic Monocline), while the Pyrzyce and Zabowo areas are located in northwestern Poland (Northeast German-Polish Basin). Background Information The Department of Geology and Geological Concessions announced a catalogue of the areas for licensing in Round 4 (planned for 2019) on 28 June 2018. From the operational point of view, the targets of exploration are as follows: 1)         Bestwina-Czechowice: the main targets are conventional (Palaeozoic basement of the Carpathians, autochthonous Miocene) and unconventional (CBM), 2)         Krolowka: the main targets are conventional (Palaeozoic basement of the Carpathians, Carpathian flysch series and autochthonous Miocene), 3)         Pyrzyce: the main targets are conventional and unconventional (Carboniferous and Permian developed in porous and tight facies), 4)         Zloczew: the main target, Permian, is both conventional and unconventional (porous and tight facies), 5)         Zabowo: the main target, Permian, is both conventional and unconventional (porous and tight facies).

The Ministry of Climate (Ministry of Environment previously) is preparing to open new tender call – Round 4 – for five areas located in the country's various tectonic units. The acreage inventory includes the areas Bestwina-Czechowice (83 sq km), Krolowka (189 sq km), Pyrzyce (1,172 sq km), Zloczew (702 sq km) and Zabowo (1,000 sq km). As disclosed in late December 2019, the tender documents have been submitted for publication in the EU Official Journal (EUOJ) - the opening of the tender is expected during the first quarter of 2020. In preparation for the tender, the officials have set up a data-room that is available for the potential participants immediately.

Europa Oil and Gas plc is offering interested parties to farm-in to Licence Option (LO) 16/20. Europa has identified 2.5 Tcf undiscovered GIIP in six prospects and leads on LO 16/20 in the Triassic gas hydrocarbon play. Europa has started fast-tracking technical work on its flagship Inishkea prospects with the intention of delivering a new prospect inventory in H1 2019. Furthermore, subject to meeting technical and commercial criteria, Europa plan to identify a firm drilling target for an exploration well in 2020 with a data room planned to open in January 2019. The six prospects include the Inishkea prospect (1,098 Bcf), 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). The 6 prospects have been mapped by Europa on legacy 3D seismic data originally acquired in 2002. Europa are currently in the process of merging and PSDM reprocessing existing 3D seismic data and aim to complete the process by the end of 2018. The additional clarity should enable some of the prospects to be upgraded to a drillable status during H1 2019. The targeted Triassic gas play comprises of Triassic Sherwood sandstone reservoirs, Carboniferous source rocks, Triassic Mercia mudstone seal and structural traps. The play is well understood and proven to work both technically and commercially by the Corrib gas field. Europa believe the play risk is lower than in other Atlantic Ireland basins where play risk remains to be conclusively proven by a commercially successful exploration discovery. Europa has interpreted the Inishkea prospect complex to have been less deeply buried than the Corrib field and therefore recovery factors should be at least as good as Corrib. The water depths are relatively shallow (400 - 600 m) and do not require harsh environment sixth generation drillships, reducing drill costs. Europa 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 prevailing 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. Interest in LO 16/20 is held solely by Europa Oil & Gas (Inishkea) Ltd. Murray Johnson Email: [email protected]

Ireland (Slyne Sub-basin (NW Ireland Offshore B.)) Corrib

Sapura Energy (previously known as SapuraKencana Petroleum) has plugged and abandoned new-field wildcat Jarak 1 in SK-408, located in the offshore Central Luconia Province, on or around 23 January 2018. Results have not been released. The well, spudded on 29 November 2017 using the Transocean “Deepwater Nautilus” S/S, tested the Middle Miocene Cycle IV / V carbonate play. The well was part of a three well exploration campaign. Remunjung 1 (first well in the campaign) and Pepulut 1 (third well in the campaign) was drilled between mid November 2017 and mid January 2017. Both wells were drilled using the “Hakuryu-11” J/U and tested the Middle Miocene Cycle IV / V carbonate play. Results have not been released. The last activity in the block was the Luconia Terumbu 3D survey acquired using the CGG’s “Geo Caspian” S/V between October 2015 and May 2016. The survey covered an area of approximately 12,500 sq. km over the blocks SK-320, SK-408, SK-319 and SK-318 in the Central Luconia Province. It was a joint acquisition by Mubadala Petroleum, Sapura Energy and Sarawak Shell Berhad. Sapura Energy is the operator of SK-408 with 40% interest. Partners include Shell (30%) and Petronas Carigali (30%). The gas discoveries made by Sapura Energy are Teja 1 (2014), Gorek 1 (2014), Legundi 1 (2014), Larak 1 (2014), Bakong 1 (2014), Jerun 1 (2015) and Jeremin 1 (2015).

Jarak 1 op. by Sapura (40% op, Shell well op 30%, Petronas 30%) in SK-408 block, off Central Luconia, P+A results n/a.

i3 Energy is offering the opportunity to interested parties to farm into licences P1987 (block 13/23d) & P2358 (block 13/23c) to take part in the development and appraisal programme of the Liberator field. i3 Energy announced on 17 October 2018, that it appointed an acquisitions and divestitures advisor to assist with the farmout of Liberator. i3 Energy previously announced on 27 June 2018, that it had entered into a 90-day exclusivity period with a prospective partner for Liberator. During this period contractual negotiations were underway and if successful would result in i3 Energy being fully funded for Liberator and the appraisal of Liberator West. The potential farminee has not delivered on key assurances and while these remain outstanding i3 Energy is ready to consider the farminee’s proposal once it’s structural issues have been resolved. The company is aiming to achieve final Field Development Plan (FDP) approval in early 2019 where an enlarged FDP will be presented to the OGA before the end of 2018. In June 2018, i3 Energy began planning to drill the Liberator West appraisal well (A3) in licence P2358 (block 13/23c). The company is hoping that an extension of Liberator to the west could enlarge the Field Development Plan and potentially form Phase II of a stand-alone field development. Liberator West is thought to have 2C Contingent Resources of 22 MMbbls and Best Case Prospective Resources of 47 MMbbls. The well could spud late 2018 / 2019. Liberator was discovered by Dana Petroleum in November 2013 by well 13/23d-8 in P1987 located immediately west of the Blake field. The overall chance of success was estimated to be 35% with the presence of the reservoir and trap configuration being considered the main risks. Well 13/23d-8 encountered a 7.3 m hydrocarbon column in 96 m of high quality Lower Cretaceous Captain sandstone reservoir. Permeabilities are estimated to be greater than 2 Darcy’s and PVT analysis proved 30.3° API with a 1.9 cP viscosity and an established water contact that mapped a potential oil column ranging from 7 m to 24 m within an elongated four way structure at approximately 1,600 m. The discovery is located in licence P1987, covering an area of 14.5 sq km and was awarded in the 27th Offshore Licensing Round and consists of just the one block (13/23d). The field extends into licence P2358 which was awarded in the 30th Offshore Licensing Round and consists of block (13/23c) on 1 October 2018 with an area of 187 sq km. P1987 and P2358 is held solely by i3 Energy.

i3 Energy is offering the opportunity to interested parties to farm into licences P1987 (block 13/23d) & P2358 (block 13/23c) to take part in the development and appraisal programme of the Liberator field.

The Greenland Government is planning to launch a series of acreage offerings in 2020 and beyond into 2021 and 2022. In association with the bid rounds the Greenland Government is hosting two events to launch the process. On the 5 February 2020 an event is Houston is being held and then on 10 February 2020 an event in London is being held. Details of the events can be found here - www.aipn.org. Region (area) Opening for licensing Type of Procedure Nuussuaq Basin/Disko West (onshore) Feb - 2020 Open Door Procedure Davis Strait Sep - 2020 Open Door Procedure Baffin Bay Sep - 2020 Open Door Procedure Nuussuaq Basin/Disko West (offshore) Sep - 2020 Open Door Procedure Northeast Greenland Jul - 2021 Licensing Round Central East Greenland Jan - 2022 Licensing Round

The Greenland Government is planning to launch a series of acreage offerings in 2020 and beyond into 2021 and 2022. In association with the bid rounds the Greenland Government is hosting two events to launch the process. On the 5 February 2020 an event is Houston is being held and then on 10 February 2020 an event in London is being held.

Cairn announced on 27 November 2019 that it has agreed to sell its wholly-owned subsidiary Capricorn Norge AS to Solveig Gas Norway AS for the sum of USD 100 million. Capricorn holds interests in 17 licences in Norway and operates five of these. The licences include three small discoveries (Agat, Jette, Skaugumsasen) and the Nova field which is under development and due onstream in Q3 2021. Capricorn drilled its first two operated wells on the NCS in 2019 – both were dry holes. It is planning two further wells in 2020. The company was pre-qualified as an operator in Norway in late 2015 and in February 2016 it was awarded its first licence. The sale is subject to various regulatory approvals and is expected to complete in early 2020. Cairn will use the proceeds of the sale to support its ongoing business (which includes assets in the UK). Solveig Gas Norway, established in 2011, was acquired in 2019 by HitecVision. It is a significant owner in Gassled and has recently been involved in deals to acquire interests in Polarled and Duva. Its strategy is to become an integrated, infrastructure-based E&P operating company. Capricorn's first NCS operated well was 6508/1-3 which targeted the Lynghaug prospect in PL 758. A 170 m section of Are Formation (the primary objective) was encountered with around 50 m of net sandstone interbedded with claystones and coals. Failure was put down to migration. If it had been successful it would have been a play opener for the Nordland Ridge and could have been developed as a tie-back to the Norne FPSO. Pre-drill reserves estimates were 70 MMboe. Its second well, 6608/11-9, was drilled on the Godalen prospect in PL 842. Godalen had an Upper Jurassic Rogn Formation objective with potential to contain 90 MMboe and could also have been tied-back to Norne in the event of a discovery. The Rogn Formation was absent, although there were some sands (total 40 m) in the Upper Jurassic Melke Formation (118 m total section). Nova was previously called Skarfjell and was discovered in 2012 by 35/9-7. Its reservoir is the Upper Jurassic Heather Formation. The discovery was appraised over the following year and the PDO was submitted in May 2018 (and received approval four months later). Operator Wintershall Dea intends to recover 77 MMboe from the field over an eight-year period using two 4-slot subsea templates (installed in May 2019) sited one kilometre apart (the northerly template will host three water injectors and the southerly one will have three producers). The templates will be tied back to Gjoa which lies approximately 16 km to the northeast. There is also provision for a third template with four more wells if needed. Gjoa will supply Nova with power (from shore), gas lift and water injection. Drilling of six wells will commence in H1 2020 and the installation of the other facilities will take place in 2019 / 2020. A new topsides module will be installed at Gjoa in May 2020 where processing will take place prior to export via the Troll oil pipeline to Mongstad. Maximum production is expected to be 50,000 boe/d and investment is estimated at NOK 9.9 billion (USD 1.23 billion). The field consists of three segments and the initial development relates solely to Nova Main, with the Southeast and East segments representing future upside potential.

Ecopetrol (->100%) will take over Chevron’s 43% stake in the Chuchupa & Ballena field in the Caribbean Sea.

The Azeri and Russian presidents have agreed on joint exploration of the Goshadash structure in the Caspian Sea, until now the subject of an MoU between Socar and Petronas, but it is understood that Petronas has quit the project.

The Azeri and Russian presidents have agreed on joint exploration of the Goshadash structure in the Caspian Sea, until now the subject of an MoU between Socar and Petronas, but it is understood that Petronas has quit the project.

SW part of AE-0155-Chalabil block, offshore Sureste Basin, WD 22m, P&A dry early Feb '20, AE Campeche JU. PTMD was 3,750m (3,390m TVD), target M. Miocene.

Zaziltun 1EXP nfw, SW part of AE-0155-Chalabil block, offshore, WD 22m, P&A dry, JU. PTMD was 3,750m (3,390m TVD), target M. Miocene.

Woodside is seeking a partner to commit to drilling an exploration well in Frontier Exploration Licence (FEL) 5/13 which contains the Beaufort (previously known as Ventry) prospect. Woodside is currently maturing the prospect with the aim for it to be drill ready in 2020. Former partner Bluestack Energy defined the prospect to consist of Upper Jurassic deepwater sandstone reservoir rocks, analogous to the Magnus and Burns Sandstones of the North Sea. The reservoirs are acoustically hard (relative to shale) and often have a high frequency banded appearance, reflecting lateral continuity of bedding. The reservoirs are trapped by a large stratigraphic/hanging wall trap. Overpressured Upper Jurassic / Lower Cretaceous shales provide ideal conditions for stratigraphic trapping. Underlying Beaufort is the Walton prospect (previously named Ventry Deep) which has a similar geometry and seismic character. Bluestack estimated the Beaufort prospect to hold recoverable prospective resources of 395 MMboe with well costs estimated at USD 56 million. As of April 2020 it was understood that the opportunity is still available with the licence set to expire towards the end of 2020. FEL 5/13 comprises of six blocks – 35/25a, 35/30, 36/21a, 36/26a, 44/5a and 45/1a and covers a total area of 712 sq km. The acreage was initially awarded as Licensing Option 11/03 in the 2011 Atlantic Margin Licensing Round. Woodside farmed into licence in 2013 acquiring a 90% working interest and operatorship from Bluestack. Up to 45% participating interest in FEL 5/13 is available for farm-in with a data-room set up in London. Interest in the licence is held solely by Woodside Energy (Ireland) Pty Ltd (100%) after it acquired Bluestack's 10% interest in the licence in February 2020.

Woodside (->100%) has acquired Bluestack Energy's 10% interest in FEL 5/13 Licence.

Reabold Resources has agreed to acquire Humber Oil & Gas' 16.665% stake in West Newton licence PEDL183, as released on 26 May 2020. Reabold will pay GB£ 1.4 million (US$ 1.7 million) cash consideration and issue 350 million new ordinary shares in the capital of Reabold, valued at 0.1p each. Reabold holds a 59.48% stake in Rathlin Energy UK Ltd which operates PEDL183. Rathlin plans to drill the West Newton B-1 (WNB-1) appraisal well on PEDL183 in Q2 2020, with permission in place to drill and conduct an EWT on a second well, West Newton B-2 (WNB-2). This will further appraise the Permian Kirkham Abbey Formation (Fm) and test the deeper Permian Cadeby Fm at its optimum location. Rathlin drilled West Newton A-2 appraisal (L46/05- 4 aka WNA-2) to 2,061m during Q2 2019 and reportedly encountered a 65m hydrocarbon column (but including minor liquids only) in the Kirkham Abbey Fm primary appraisal objective, with an oil saturated core from the Cadeby Fm. Flow testing during Q3 2019 was suspended after unexpectedly proving a 45m oil column below a 20m gas column in the Kirkham Abbey Fm. Rathlin has now re-designed the flow test to accommodate the oil section and is currently seeking Environmental Agency approval. The West Newton Field has been updated with in place resource estimates of 146.4 MMbo and 211.5 Bcfg (base case), and 283 MMbo & 265.9 Bcfg (upside case), as announced on 11 November 2019. West Newton 1 (L46/05- 3) was drilled in 2013, and encountered gas in the Kirkham Abbey Fm, with further testing conducted in 2014. Rathlin also drilled Crawberry Hill 1 (L46/08- 2) on the licence in 2013 which was P&A as an uncommercial discovery. PEDL183 covers 712 sq km over blocks SE93 and TA3a, 4, 13a, 14, 22, 23, 24, 32 & 33 to the N of the Humber estuary, and was awarded to Connaught Oil & Gas subsidiary Rathlin Energy on 1 July 2008 in the 13th Landward Licensing Round. In December 2018 Union Jack and Humber Oil & Gas both farmed in for 16.665% in exchange for each paying 25% of West Newton appraisal well costs, and Connaught sold 37.08% in Rathlin to Reabold Resources for GB£ 3 million (US$ 3.9 million). In November 2019 Reabold Resources increased its ownership of Rathlin to 59.48%. PEDL183 licensees are Rathlin Energy Ltd (66.67% + Op), Union Jack Oil plc (16.665%) and Humber Oil & Gas Ltd (16.665%).

Reabold Resources has agreed to acquire Humber Oil & Gas' 16.665% stake in West Newton licence PEDL183,

SE part of Loma La Lata-Sierra Barrosa block, Neuquén Basin, fracked and tested the Vaca Muerta as of Mar '20, suspended early July, results n/a.

Argentina (Neuquen B.) Barreal Grande 1H op. by YPF (100%) in Loma la Lata-Sierra Barrosa block, fracked and tested the Vaca Muerta as of Mar '20, suspended early July, results n/a.

Ratio has agreed to sell a 10% stake in the Royee (399) offshore block to private Unibin Capital Ltd after reaching a similar deal in March with Delek (24.99%). Partners to become Edison (op) 20%, Ratio 35.01%, Delek 24.99%, Israel Opportunity O&G 10%, Unibin Capital 10%. Ratio is still looking to farm down further the 399-sq km Mediterranean block.

Ratio Oil (->70%, EDF 20%, Opportunity-Energy Res. Partnership 10%) selling 10% stake to Unibin in the 399 Royee exploration licence.

Baron Oil Plc announced on 14 November 2019 that the company has entered into a non-binding Heads of Agreement (HOA) to acquire the entire share capital of SundaGas Pte Ltd. The proposed transaction is classified as a reverse takeover, pursuant to AIM (Alternative Investment Market of London Stock Exchange) rules. Completion of the transaction is subject to approval from Baron's shareholders, satisfactory completion of due diligence, granting of Rule 9 waiver (Rule 9 of the takeover code), publication of AIM Admission Document (detailing, inter alia, the terms of proposed transaction) as well as execution of a legally binding Sale and Purchase Agreement (SPA). The acquisition will be partially settled through fund raising via share issuance by Baron Oil to SundaGas for a pro-rata of two new ordinary shares in Baron for each ordinary share currently in issue. The ordinary shares to be held before the fund raising for SundaGas and Baron Oil will be respectively 3,852,819,512 (66.67%) and 1,926,409,576 (33.33%). Apart from the fundraising, Baron intends to carry out share consolidation and change its name to SundaGas Plc as part of proposal. SundaGas will provide an unsecured loan facility of up to GBP 200,000 (USD 257,695) to Baron Oil for cost related to the proposed transaction, with a nominal interest rate of 1% per annum, to be paid within 90 days if the proposed transaction is void. Assets covered under the transaction deal include Telen PSC, located in the deepwater Kutei Basin, and the Chuditch block in offshore Timor Leste. A performance bond of USD 4.45 million was previously paid for the Telen PSC, and will remain in place upon completion of the proposed transaction. The Chuditch block was awarded to SundaGas (via subsidiary SundaGas Banda Unipessoal, 75% PI with operatorship) and Timor Gap Chuditch Unipessoal (25% PI) on 8 November 2019. The block was awarded through the TL-SO-19-16 Production Sharing Contract through direct negotiation. SundaGas holds 100% operating interest in the Telen block. The company acquired the asset from Total in 2018. The initial six-year exploration period for the PSC expired in October 2018 and the block has subsequently entered the final four-year exploration period until October 2022. Exploration commitments, including one exploration well and 200 km 2D seismic acquisition, are due by October 2020. SundaGas offered a farm-in opportunity for the block in April 2019. The block contains the Hiu Marah prospect, a large structural closure with estimated prospective resources (2U) of 161 MMboe, including 126 MMbo and 208 Bcfg, within Middle Miocene turbidite sandstones of the Sepinggan Formation. The prospect is considered a low-risk target (Geological Chance of Success is estimated at 23%) based on the presence of DHIs identified from available 3D seismic data (including flat spots and AVO anomalies), as well as analogy with nearby discoveries. SundaGas and Baron Oil entered a joint venture agreement in 2016 to explore new business opportunities in SE Asia. Discussions between the companies were still underway as of September 2019.

Baron Oil has entered into a non-binding HoA with SundaGas with a view to acquire the latter's share issued capital under a reverse takeover. SundaGas is involved in Indonesia (Telen block) + Timor-Leste (new Chuditch block,

Pura Vida is seeking to farmout its 17,937-sq km Ambilobe block off NW Madagascar. Next expiry is Jul ’19, but this can be extended 2 yrs.

Pura Vida is seeking to farmout its 17,937-sq km Ambilobe block off NW Madagascar. Next expiry is Jul ’19, but this can be extended 2 yrs.

Metgasco Pty Ltd, Vintage Energy Pty Ltd and Bridgeport Energy Ltd reported on 24 February 2020, that they have executed the farm-in agreement, to enter PRL 211, located in the Cooper-Eromanga Basin. Under the terms of the farm-in, which was entered into in November 2019, the companies will be acquiring interest from current operator of PRL 211, Senex Energy Ltd. A number of conditions are required to be satisfied, including executing a formal farm-in agreement. Other conditions include Ministerial approvals and a demonstration of sufficient funds being available to drill a well. The remaining conditions are expected to be completed by 31 March 2020. Under the terms of the farm-in agreement, it's proposed that Vintage will acquire operatorship of the licence with 42.5% interest, with the remaining interest split between Bridgeport (21.25%), Metgasco (21.25%) and current holder Senex (15%). Senex will be free carried for the first well, as part of the farm-in terms. The joint venture partnership of Metgasco, Vintage Energy, Bridgeport Energy and Senex Energy already has ownership of adjacent exploration licence ATP 2021-P, which is on the Queensland side of the basin (subject to relevant authority approvals and registration of the interests). PRL 211, located in South Australia, is currently 100% owned by Senex's subsidiary Stuart Petroleum Pty Ltd. Entry into the retention lease provides the joint venture with complete access to the Odin Prospect which straddles both ATP 2021-P and PRL 211. With the Odin structure being the main target, the terms extend to specifically drilling the prospect, for which, Vintage will be liable for 50% of the costs to acquire its 42.5% equity. The remaining costs will be split evenly between Bridgeport and Metgasco. The well is planned to be drilled in Q4 2020. It is expected that the initial well costs will be around AUD 4 million. Subsequent well testing costs will reflect the equity share in the licence once the farm-in deal is completed. The Vali Prospect, located solely in ATP 2021-P, was drilled in December 2019/January 2020 and was, prior to drilling, reported to provide significant de-risking of the Odin Prospect. The Vali 1 exploration well encountered 35 m net gas pay in the primary Patchawarra Formation, plus additional gas recovery and oil shows the deeper Triassic and Jurassic secondary targets. Vintage reported that the results are on the high side of pre-drill estimates. Oil shows in the Jurassic Westbourne and Birkhead formations were also reported by Vintage. As of 16 January 2020, Vintage plans to case and suspend the well for potential stimulation, which could increase permeability in the Patchawarra sandstones, flow testing and future production. PRL 211 was awarded over exploration licence PEL 637 (replacement of PEL 516, 2010), which was awarded in 2014 to Stuart Petroleum. Origin entered in 2015 forming the subsequent partnership for PRL 211, which was awarded on 25 October 2017. PRL 211 now covers nearly 100 sq km. The joint venture partnership ended on 26 June 2018 with Stuart acquiring Origin's 40% interest. The Odin Prospect comprises an anticlinal structure on the eastern boundary of the permit with an independent closure at a depth of around 2,300 m. The Strathmount 1 exploration well, which was drilled in 1987, lies within the extent of the prospect. The well encountered 21 m of reservoir sands and 13.7 m of interpreted gas pay. Gas flow testing indicated returned gas to surface, but rates were too small to measure. On the 2016 Snowball 3D seismic data, Metgasco reports that the well appears to have intersected the sands outside of the Toolachee and lower Patchawarra level. Odin has been assigned gross P50 recoverable resources of 12.6 Bcf, a 3.9 Bcf upgrade from estimates released in 2018.

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

Mitsubishi Corp, through wholly owned subsidiary Bennett Resources Pty Ltd (previously Diamond Resources Pty Ltd) is offering a farm-in opportunity in exploration permit EP 371, located in the Canning Basin. Mitsubishi reports that it is offering significant equity and potential operatorship. Mitsubishi holds its 100% interest in the licence after completing an asset swap agreement, with Buru Energy Ltd, in January 2018.Under the terms of the deal Diamond Resources acquired Buru’s 50% interest and operatorship in the EP 371 permit. Diamond Resources gained full access to the associated gas resources, facilitating a timely appraisal and commercialisation of the resources. In return, Buru acquired Diamond Resources’ 50% interest in the conventional fields located in L 20, L21 and EP 391, EP 431, EP 436 and EP 428. The deal was completed to allow the companies to focus on areas in which they hold most expertise and have the ability to maximize the exploration potential and production from the assets. EP 371 contains the oil discovery Crimson Lake, made in 1988, and also shale gas fields Valhalla, Valhalla North and Asgard, which were made between 2011 and 2012.Mitsubishi plans to develop and commercialise the resources. Possible options for development include producing gas for the domestic market, utilizing existing infrastructure, or tying into the LNG facilities available. It is thought further operations on the wells in the permit will be undertaken, with flow tests and production tests on the gas resources. EP 371, which covers an area of 3,675 sq km, was awarded on 18 March 1993. Mitsubishi Corp holds 100% interest through subsidiaries Diamond Resources (Canning) Pty Ltd (50% + Operator) and Diamond Resources (Fitzroy) Pty Ltd (50%). Companies interested in pursuing this opportunity should contact: Taisei Furukawa         email: [email protected] Jeff Feltham                email: [email protected]

Mitsubishi Corp, through wholly owned subsidiary Bennett Resources Pty Ltd (previously Diamond Resources Pty Ltd) is offering a farm-in opportunity in exploration permit EP 371, located in the Canning Basin.

Shell has exited PL958 and assigned its 50% operated stake to OKEA, effective from 31 January 2019. PL958 covers 809 sq km over Norwegian Sea blocks 6408/4 & 6408/7. The acreage contains one dry NFW 6408/4-1 (1988, Conoco, 2,725m) which encountered water bearing reservoir in the Jurassic Fangst Group and Triassic Tilje Formation. The licence was awarded to Shell, VNG and Petoro on 22 June 2018 in the 24th Round with an option to acquire 3D seismic or drop the licence after one year, followed by a drill or drop decision in June 2022. Neptune Energy Group entered PL958 when it purchased VNG Norge AS for an undisclosed consideration on 4 December 2018. OKEA had earlier acquired Shell's 44.56% operated interest in Draugen Field, located 15km W of PL958, plus 12% partner share of Gjoa Field in the North Sea, for NOK 4.52 billion (US$ 526 million) on 30 November 2018. Revised PL958 partners are OKEA AS (50% + Op), Neptune Energy Norge AS (30%) and Petoro AS (20%)

Norway, PL 958

Shell has confirmed that it is offering for sale two of its Norwegian assets – Draugen and Gjoa. Shell operates the Draugen field with a 44.56% interest and it is a partner in Gjoa (holding 12%). No further details relating to the sale have been released but more information is expected as the divestment progresses. Draugen was discovered in September 1984 with well 6407/9-1 which flowed 8,490 bo/d and 1,764 Mcf/d from the Upper Jurassic Rogn Formation. The field lies in the Froya High of the Trondelag Platform. Draugen has been developed with a concrete monotower gravity base structure supporting an integrated topside. Gas is piped to Karsto via a tie-in with the Åsgard Transport trunkline. Oil is loaded into shuttle tankers on the field’s two flowlines which link the platform with a floating loading buoy. The field came onstream on 19 October 1993 and had produced 919 MMboe of its 970 MMboe reserves by the end of December 2017. 2017 production totalled 8.9 MMboe, up from 8.5 MMboe in 2016 due to the installation of a subsea pump and two new producers. Gjoa has been developed using four subsea templates plus a satellite well tied back to a floating production unit. Oil is exported via the Troll II line to Mongstad and gas flows to the UK via FLAGS. The field came onstream on 7 November 2010. Initial recoverable reserves are estimated at 420 MMboe and by the end of 2017 126 MMboe of this was remaining. 2017 production totalled 40.6 MMboe. Interest in Draugen (PL 093 and PL 176) is held by A/S Norske Shell (44.56% + operator), Petoro AS (47.88%) and VNG Norge AS (7.56%). Gjoa is covered by PL 153 where interest is held by Neptune Energy Norge AS (30% + operator), Petoro AS (30%), Wintershall Norge AS (20%), A/S Norske Shell (12%) and DEA Norge AS (8%).  

Shell has confirmed that it is offering for sale two of its Norwegian assets – Draugen and Gjoa. Shell operates the Draugen field with a 44.56% interest and it is a partner in Gjoa (holding 12%).

PL 1046, 51 sq km in the Cooper-Eromanga, was gtranted to Santos on 8 May ’19 for a 30-year term. It covers the Hector + Hector South gas finds. Santos (op), partner Delhi Petr.

Santos (70% + Op. Beach 30%) was awarded production licence PL 1019, 1020, 1046.

WA-527-P, 6,590 sq km in the Bedout (Roebuck) Basin in WD 65-128m, awarded in Mar ’17 for 6 years, now opened for farm-in offers. Commitments include 510 sq km of 3D seismic in year 3 and a well in year 4. More from GEPS.

WA-527-P, 6,590 sq km in the Bedout (Roebuck) Basin in WD 65-128m, awarded in Mar ’17 for 6 years, now opened for farm-in offers. Commitments include 510 sq km of 3D seismic in year 3 and a well in year 4.

After essentially extending the deadline for it 1st Licensing Round through 2021, sources close to state-run Union Cuba-Petroleo (Cupet) is planning to offer improved fiscal terms as part of a bid to woo potential bidders. However, the exact nature of these proposed improvements has not been detailed. A brochure released at the 3rd Cuba Energy, Oil and Gas Conference held on 26-29 November 2019 in Havana did not show any differences in fiscal terms to that previously revealed. Cupet hosted a roadshow in London on 3 June 2019 as part of the launch of the country's 1st Licensing Round. Cuba is offering 24 blocks offshore in the country's Exclusive Economic Zone (EEZ) as part of Havana's bid to boost oil production. Licence round participation registration is scheduled for 10 January 2020, while inquiries and clarifications are slated for 31 January 2020. Cupet says company qualification has a 29 May 2020 deadline, while the bidding process kicks off on the same day. Bid evaluation will take place on 29 June 2020, while licence awards are scheduled for 1 July 2020. However, at the final roadshow in Havana it is understood the government decided to extend the timeline. The blocks are being offered under Production Sharing Agreements (PSA) under provision of the Foreign Investment Law 118 and its implementation norms and resolutions. The general terms of the round are: ->The term of the contract is 35 years.->The exploration period is 10 years. ->During the exploration period no taxes or annual rentals are payable.->No signature bonus payable.->No production bonus payable.->No royalties payable.->No state participation.->If commercial development occurs, the contractor will pay income tax at a rate of 15%-22.5%, commencing in the ninth year of the project (ie a nine-year tax holiday prevails) on net profit.->Profit split is based on R-Factor. This is the main bid evaluation parameter.->The contractor does not pay taxes to provinces or municipalities or on repatriation of profits or production.->The cost recovery ceiling is set at up to 70% and will consider the volume and price of hydrocarbons.->The contractor must contribute to the training of local staff. Fixed local staff training cost is US$ 200,000 per year during the exploration period, non-cost recoverable. ->Cupet retains the first buy-in option at the market price.->The contractor must give priority to the local workforce, except for key technical and management positions.<P />

After essentially extending the deadline for it 1st Licensing Round through 2021, sources close to state-run Union Cuba-Petroleo (Cupet) is planning to offer improved fiscal terms as part of a bid to woo potential bidders. However, the exact nature of these proposed improvements has not been detailed. A brochure released at the 3rd Cuba Energy, Oil and Gas Conference held on 26-29 November 2019 in Havana did not show any differences in fiscal terms to that previously revealed.

Glencore has sold half of its 100% interest in the offshore Bolongo block to Perenco, who took over operatorship in the process under a new 50:50 partnership. Bolongo in the Rio del Rey has recently been halved to 232 sq km in favour of a new Bolongo block to be licensed in 2018:

Perenco has acquired 50% interest + op. in the Bolongo block from Glencore (->50%).

In January 2018, Polskie Gornictwo Naftowe i Gazownictwo (PGNiG) completed successful appraisal Przemysl 290 in the 100/94 Przemysl G contract in southeastern Poland (Carpathians). Przemysl 290, solely operated by PGNiG, reached the final depth of 2,030 m in the Miocene sandstone-mudstone series, encountered commercial quantities of gas - rates up to 7.6 MMcf/d - and was handed over for production. Przemysl 290 was drilled during November-December 2017. The well is situated on the Przemysl gas field, in its central sector, within the Outer Carpathian Foredeep. The well was targeting the Upper Badenian to Lower Sarmatian Autochthonous Miocene sandstone-mudstone series with an estimated planned total depth of approximately 2,000 m.

PGNiG completed successful appraisal Przemysl 290 in the 100/94 Przemysl G contract in southeastern Poland (Carpathians). Przemysl 290, solely operated by PGNiG, reached the final depth of 2,030 m in the Miocene sandstone-mudstone series, encountered commercial quantities of gas - rates up to 7.6 MMcf/d - and was handed over for production.

Kina Petroleum Corp is offering equity in its wholly owned and operated exploration licenses: PPL 435 and PPL 436, located in the Fly Platform, Papuan Basin. Both licences were scheduled to expire in November 2018, but Kina has submitted a new application covering both areas - APPL 642. This is also expected to be available to interested parties for farm in. PPL 435 and PPL 436 cover a combined area of 19,380 sq km and were awarded in 2012, for six years. Rather than extend the licences, with associated area reductions, Kina submitted APPL 642 to maintain its position in the basin. APPL 642 covers an area of around 16,900 sq km over main prospects which are considered to lie along a liquids fairway extending from Elevala-Ketu, in PRL 21. The application also extends eastward into an expired licence area held by Kengaku, hosting the Saratoga prospects, located to the south of the Panakawa oil seep. The timeline for an exploration licence to be awarded or refused by the Minister for Petroleum and Energy is variable. Based awards within the area, this could be around 18 months. Under previously scheduled work commitments, one well was planned (to a minimum of 1,000 m, at a forecasted cost of AUD 20 million). However, the commitment to drill was replaced by the acquisition of seismic which was scheduled for late-2016/17. The option to remove the well commitments and complete an additional phase of seismic would allow the existing prospects to be further delineated with additional seismic control before moving to a drill phase. Any newly approved work programme in relation to application APPL 642 is likely to contain a seismic commitment which potential partners would be asked to assist in. Recent seismic reprocessing/interpretation and any planned, new 2D seismic data acquisition, will likely focus on delineating the Aiambak and Lake Murray East leads in PPL 435 and the Sturt, Alligator, Dalbert, and Oriomo prospects in PPL 436. The combined prospects and leads are estimated to contain prospective resources over 13 Tcf gas and 181 MMb liquids (best estimate). Aeromagnetic and gravity survey data has been acquired (completed in June 2014) which has been merged and interpreted by Kina alongside reprocessed vintage 2D seismic data. The gravity data defines the Aiambak and Alligator/Sturt Prospects which are located on the hanging wall of the southern Fly Platform edge. Aiambak is located updip of the Lake Murray 1 well which was drilled in 1973, encountering gas in the Toro Sandstone. Kina considers the prospect to be in connection with the well after gas testing. Alligator and Sturt prospects are located updip of oil seeps observed at the Panakawa 1 well. Through source-migration studies, Kina believes that the prospects have potential to receive charge from oil mature sources rocks from the Wabuda and Morehead Troughs. Cott Oil and Gas Ltd completed a farm-in to PPL 435 and 456 in mid-February 2013. However, Cott subsequently withdrew in July 2015 to focus on other areas of its portfolio. Kina is now seeking farm-in partners for both PPL 435 and PPL 436 (and APPL 642 upon award). The PPL 435 and PPL 436 licences cover a combined area of 19,380 sq km and were awarded on 25 July and 30 November 2012 respectively, for a period of six years. Kina Petroleum Corp holds 100% interest and operatorship of both permits. APPL 642 covers an area of around 16,900 sq km and was registered with the Department of Petroleum & Energy on 2 May 2019. Companies interested in pursuing this opportunity should contact: Richard Schroder – Kina Petroleum MD Tel: +61 2 8247 2500 Email: [email protected]

(Papuan B.) PPL 435 & PPL 436, operated by KINA PT (100%), Kina Petroleum Corp is offering equity.

On 6 February 2019, Pertamina Hulu Energi (PHE) and regional government-owned company PT Migas Hulu Jabar ONWJ (MUJ) signed an addendum to a previous agreement for the transfer of 10% participating interest (PI) in the Offshore Northwest Java (ONWJ) PSC from PHE to MUJ. The addendum addressed calculations of tax obligations for both partners in relation with the gross split contract for the block. In addition, the regional government via MUJ committed to support upstream activities in the area by simplifying and accelerating the issuance of the necessary permits. The addendum is expected to ensure sustainable long-term cooperation between Pertamina and the local administration in West Java. The addendum is a follow-up of the initial agreement signed on 19 December 2017, whereby PHE transferred the 10% PI to MUJ, in accordance with Regulation of Ministry of Energy and Mineral Resources No. 37/2016. Pertamina Hulu Energi is operator of the block, following a twenty-year extension signed on 18 January 2017. The ONWJ contract was the first to adopt the new Gross Split scheme which was implemented by the government on 16 January 2017. Oil and gas production from the block is being used entirely to support national strategic needs such as fuel, power plants and raw materials for fertilizer production. The latest development in the ONWJ PSC was the SP field, which was brought onstream in October 2018. The field has a production capacity of 30 MMscfd, catering for local consumption. SP was the first field development project carried out under Gross Split fiscal terms. MUJ is a business unit controlled by the Jakarta and West Java provincial governments, and by several regencies in the West Java area. Background Information PT Pertamina and SKK Migas, witnessed by Indonesian Minister of Energy and Mineral Resources, signed an extension for the Offshore Northwest Java (ONWJ) PSC on 18 January 2017. The contract will be valid for 20 years, from 19 January 2017 to 18 January 2037. The final government/contractor split for the new contract was set at 42.5%/57.5% for oil and 37.5%/62.5% for gas. Financial commitments for the first three years of the contract will be USD 82.3 million. Signature bonus to be paid by Pertamina is USD 5 million. Total investment for the 20-year duration of the contract is estimated at around USD 8.5 billion. The ONWJ PSC was originally awarded in 1967. The interest split in the block until 18 January 2017 was Pertamina Hulu Energi with 58.2795%, EMP ONWJ Limited with 36.7205% and Kufpec with 5%.

On 6 February 2019, Pertamina Hulu Energi (PHE) and regional government-owned company PT Migas Hulu Jabar ONWJ (MUJ) signed an addendum to a previous agreement for the transfer of 10% participating interest (PI) in the Offshore Northwest Java (ONWJ) PSC from PHE to MUJ. The addendum addressed calculations of tax obligations for both partners in relation with the gross split contract for the block.

Hub 2566-4 EL, Kirthar Fold Belt in Sindh + Balochistan, P&A dry mid-Jun ’18 at TD 2,700m, SLR-223 rig.

Ayub X-1 in Hub 2566-4 EL, P&A, dry.

Hitherto not reported and according to industry sources, Eni Gabon SA (Eni) has found gas in the outpost Nyonie Deep 1ST1. Although not tested, the well has confirmed the Nyonie Deep gas discovery made in block D4 in northern Gabon in 2014. The well was spudded on 14 June 2019 and suspended on 3 September 2019 when the “Topaz Driller” J/U left the area. Earlier in early June 2019, André Marsanich, the former general manager of Eni’s Gabon, announced in a meeting with former Oil Minister Pascal Houangni Ambouroue, the imminent start of an appraisal well on Nyonie Deep field The gas and condensate accumulation is located in the northern part of Gabon in both blocks D3 and D4 within the North Gabon Sub-basin (Gabon Coastal Basin). Eni booked a slot with the “Topaz Driller” J/U owned by Vantage Drilling International just after its use by Total in Torpille Marine field. In early 2019, Eni has conducted studies related to the future appraisal location at the Nyonie Deep field. Eni is the operator and sole participant in both blocks D3 and D4. Background Information In late October 2015, Eni completed its operations in the outpost Nyonie Deep 2 located within block D4. The well encountered gas and was spudded on 14 April 2015. On 31 July 2014, Eni announced that it had discovered gas and condensate with the Nyonie Deep 1 exploration well, located within block D4. The well was spudded on 10 April 2014, at a water depth of 28 m with the “West Mischief” J/U. It targeted the Pre-Salt Nyonie Deep prospect and was drilled to a TD of 4,314 m. Eni estimated the discovery to hold a potential in-place resource of 500 MMboe. The well intercepted a 320 m hydrocarbon bearing section in a Pre-Salt Aptian aged clastic sequence. The structure covers more than 40 sq km and extends into block D3. The well had a planned TD of 4,250 m with objectives in the Gamba and Coniquet formations.

Gabon (South Gabon Sub-basin (Gabon Coastal B.)) Gamba

Hitherto-unreported, last September EGPC was conferred sole rights to oversee devt ops in the Ras Fanar lease, offshore Gulf of Suez Basin, following RWE’s withdrawal. Until then, the 32-sq km lease had been run by Suco (EGPC-RWE 50:50 JV).

EGPC was conferred sole rights to oversee devt ops in the Ras Fanar lease, offshore Gulf of Suez Basin, following RWE’s withdrawal.

North of Bozhong Depression in Bohai offshore, WD 25m, ops terminated results n/a late Jan ’18, Hai Yang Shi You 921 JU. Target Miocene clastics.

China (Bohai Gulf B.) Caofeidian 18-3 (Bo) 1 op. by CNOOC TJ (100.0%) in Boxi block,WD 25m, ops terminated results n/a

SW part of AE-0059-M-Mezcalapa-09 block, onshore Sureste Basin, P&A dry mid-Oct '19. PTMD was 5,828m (4,820m TVD), target Cretaceous.

Mexico, not found

KG-DWN-98/3 (KG-D6), deepwater Krishna-Godavari Basin, TD 4,800m, believed P&A in late Jul ‘19, Dhirubhai Deepwater KG1 DS.

KG-D6 MW 1 nfw (Reliance 60% op, BP 30%, Niko 10%) in KG-DWN-98/3 (KG-D6) DW offshore block, P&A dry.

The NPD reported on 4 January 2018 that DNO has acquired a 20% interest in PL 889 from operator VNG. The licence covers 142 sq km over parts of blocks 6507/8 and 6507/9 to the east of Heidrun and was awarded in APA 2016. The deal is effective from 28 December 2017. DNO returned to the NCS in June 2017 after a six year absence. It acquired Origo Exploration Holding AS, gaining seven Norwegian licences plus four in the UK, Origo’s management and staff and the office in Stavanger. This latest licence is its eighth. Interest in PL 889 is now held by VNG Norge AS (40% + operator), Concedo ASA (40%) and DNO Norge AS (20%).

DNO has acquired a 20% interest in PL 889 from VNG (40% + op.), Concedo (40%).

On 19 December 2018 the NPD confirmed that Wintershall has transferred its 20% interest in PL 777, PL 777 B, PL 777 C and PL 777 D to OMV (effective 14 December 2018). The Hornet exploration well is due to be drilled in PL 777 in 2019. PL 777 B, C and D cover the Glitne field which was abandoned in 2013 after coming onstream in August 2001. The Hornet exploration well was originally due to be drilled in Q4 2018 but Aker BP confirmed in May 2018, in its Q1 2018 results, that it has delayed the well and it will now be drilled in 2019. The company believes that the prospect contains recoverable reserves ranging from 17-166 MMboe and that, if successful, it could be developed as a tie-back to Ivar Aasen. Following completion of the deal interest in PL 777, PL 777 B, PL 777 C and PL 777 D is now divided between Aker BP ASA (40% + operator), Petoro AS (20%), Var Energi AS (20%) and OMV (Norge) AS (20%).

Wintershall has transferred its 20% interest in PL 777, PL 777 B, PL 777 C and PL 777 D to OMV. Following completion of the deal interest is now divided between Aker BP ASA (40% + operator), Petoro AS (20%), Var Energi AS (20%) and OMV (Norge) AS (20%).

Anyue gasfield area, E. Deyang-Anyue fault zone in central Sichuan Basin, TD 6,376m in Jan '20, tested 43 MMcfg/d from the Dengying 2 fm, 127m pay encountered, potential >1 Tcum in place.

Pengtan 1 nfw. Anyue gasfield area, E. Deyang-Anyue fault zone, tested 43 MMcfg/d from the Dengying 2 fm, 127m pay encountered, potential >1 Tcum in place. TD=6 376m. The Pengtan structure, which covers 1200 km² in the central part of the basin, has the potential to hold more than “a trillion cubic metres” of gas in place, the company said.

As announced on 15 July 2019, PNOC-EC and Ratio Petroleum signed a Memorandum of Understanding (MOU) to permit PNOC’s entry to SC 76, located in the northeastern flank of the East Palawan Basin. Both parties are bound to establish cooperation in research and feasibility studies and exchange of technical information, starting with SC 76. The terms of PNOC’s participation in the block are to be agreed upon at a later date. On 17 October 2018, Ratio Petroleum officially signed a service contract for SC 76 with the Philippines’ government for the Philippine Energy Contracting Round V (PECR V – Area 4). This is the only service contract awarded under PECR V. On 30 June 2015, the Department of Energy (DOE) received bid applications for only four areas out of the total 11 areas offered. Local company Colossal Petroleum has put in bids for Area 5 and 7 (East Palawan and Recto Bank) whilst Area 1 (Southeast Luzon) received bid from Yulaga Oil. However, application from Yulaga Oil was disqualified while awards for Colossal petroleum were cancelled due to requirement issue with Commission on Audit (COA). The state-owned Philippines national oil and gas company, PNOC has been continuously looking for partners in petroleum exploration and development to secure a sufficient energy for local consumption. Israel-based Ratio Petroleum Ltd. is a subsidiary of Ratio Oil Exploration. The E&P company also holds interests in Guyana, Suriname, Ireland and Malta. Background Information The 4,160 sq km of SC 76 is covered by a 540 line km of 2D seismic data. The block lies at water depth of around 200 m to 2,000 m. To date, no wells have been drilled within the service contract. Nearby wells are Cuyo 1, Paly 1, Dumaran-1 and Silangan 1. The last two wells have exhibited oil and/or gas shows. The western portion of the block was previously held by Phillips Petroleum Co. and partner Shell Philippines BV from June 1978 to July 1983 as block SC33 East Palawan. SC 76 is also part of Area 8 which was offered during PECR IV in 2011. Play types identified in the block are the reef build-up, anticline, stratigraphic and possible fault block play (from recent studies). The area consists of sedimentary thickness of around 3,000 to 5,000 m. Reservoir target: Cretaceous sandstones, Oligocene to Middle Miocene Carbonates and Middle Miocene to Upper Pliocene sandstones. Source rock – Hydrocarbon was generated by the Oligocene to Miocene shales. Seal – Intraformational seal would be provided by Oligocene to Pliocene mudstones and shales. DOE estimated resources potential of 1.23 Bbbl of oil and 2.06 Tcf of gas.

PNOC-EC and Ratio Petroleum signed a MOU to permit PNOC’s entry to SC 76.

The NPD reported on 8 November 2018 that Equinor has transferred its 6.65% equity in PL 018 C and PL 018 DS to Petrolia with effect from 31 October 2018. The licences cover the same 24 sq km area over the southerly part of block 1/5 and contain the eastern extent of Flyndre. PL 018 C applies above Top Ekofisk and below Base Hidra. PL 018 DS applies from Top Ekofisk to Base Hidra. Flyndre straddles the UK / Norway border (with 7% in Norway) and was discovered in 1974 by Phillips Petroleum with Norwegian well 1/5-2. The field’s reservoir is the Paleocene Balmoral Sandstone at around 3,000 m. Flyndre started production in March 2017 using a single horizontal well as a subsea tie-back to the Clyde platform in the UK. From Clyde the produced oil and gas is exported to the Teeside and St Fergus terminals. When the field came onstream it was expected to produce up to 10,000 bo/d and was planned to remain onstream until at least 2023. However, production has been lower than forecast and pressure is declining faster than anticipated. Interest in PL 018 C is now held by Total E&P Norge AS (88.35% + operator), Petrolia NOCO AS (6.65%) and Petoro AS (5%) and interest in PL 108 DS is divided between Total E&P Norge AS (60.01% + operator), Production Energy Company AS (15%), Aker BP ASA (13.34%), Petrolia NOCO AS (6.65%) and Petoro AS (5%).

Equinor has transferred its 6,65% equity in PL 018 C and PL 018 DS to Petrolia. Interest in PL 018 C is now held by Total (88.35% + op), Petrolia (6.65%) and Petoro AS (5%) and interest in PL 108 DS is divided between Total (60.01% + op), Production Energy Company AS (15%), Aker BP (13.34%), Petrolia (6.65%) and Petoro AS (5%).