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Caelus is looking for a partner to share in the drilling of a planned appraisal to the 2016 Tulimaniq oil discovery. The 1.8-2.4 Bbbl recoverable find is thought capable of delivering 200,000 b/d of light crude from the Cret. Torok fm, although it was not tested.  The Tulimaniq acreage comprises 26 tracts totalling 474 sq km. Details from GEPS.

Caelus is looking for a partner to share in the drilling of a planned appraisal to the 2016 Tulimaniq oil discovery. The 1.8-2.4 Bbbl recoverable find is thought capable of delivering 200,000 b/d of light crude from the Cret. Torok fm, although it was not tested. The Tulimaniq acreage comprises 26 tracts totalling 474 sq km.

As of 11 September 2018, Pancontinental Oil & Gas NL (Pancontinental) is understood to be on the lookout for a Block 2713 (PEL 87) partner. The company mentioned that it intends to seek a major joint venture partner to fund an accelerated forward programme which will include a 3D seismic survey over its Late Aptian aged “Super Fan”. Pancontinental recently completed the first stage of assessing the potential prospective oil resources within the block (see article: Pancontinental Oil & Gas NL interpret a "Super Fan" within Block 2713 (PEL 87)). To date, the company has identified several leads with a combined best estimate in excess of 1.3 billion barrels of oil: Lead Unrisked Gross (100 percent) Prospective Oil (mmbbl) Play Type Best Estimate Probability of Geologic Success Lead A Mound facies 152 11% Lead C1 Structural (4-way rollover) 73 19% Lead D Structural/Stratigraphic 345 10% Lead G First Turbidite lobe/Sheet sand 349 7% Lead H Structural/Mound (4-way rollover) 40 7% Entire Super Fan Aptian Depositional Wedge 1329 5%   On 4 December 2017, Pancontinental announced that it had via its wholly owned subsidiary Pancontinental Orange Pty Ltd been awarded Block 2713. The 10,947 sq km block straddles the Luderitz and Orange Sub-basins in water ranging between 400 m and 3,200 m deep. Interests in the licence are as follows: Pancontinental operates the licence with a 75% interest, Custos Investments (Pty) Ltd holds a 15% carried interest and the National Petroleum Corporation of Namibia holds a 10% carried interest.

Pancontinental Oil & Gas NL (Pancontinental) is understood to be on the lookout for a Block 2713 (PEL 87) partner. The company mentioned that it intends to seek a major joint venture partner to fund an accelerated forward programme which will include a 3D seismic survey over its Late Aptian aged “Super Fan”.

Effective 3 October 2019, Slovakian Horizon Energy s.r.o., a joint venture comprising equal partners Aspect Holdings LLC and domestic Nafta a.s., was granted the Pavlovce nad Uhom contract in southeastern Slovakia. The contract has a ten-year term, until 3 October 2029. The 995 sq km Pavlovce nad Uhom permit is located in the Kosicky and Presovsky political provinces, some 50 km east of the city of Kosice. In a geological sense, the tract was situated within the East Slovak Sub-basin (Pannonian Basin). Industry sources indicate that the application was lodged likely during July 2019 and was signed off on 9 September. The Pavlovce nad Uhom is covering similar area to previously-existing contract Vychodoslovenska nizina (650 sq km), held by Nafta until June 2019.

The 995-sq km Pavlovce nad Uhom contract area was granted to Horizon (Aspect Holdings, Nafta a.s. %)

Mubarek block, Amu-Darya Basin, tested 35 MMcfg/d from 2,955m in an uncased borehole, further testing planned, Uralmash 3D rig. Reserves pegged at 355 Bcf, likely in Callovian-Oxfordian carbs.

Uzbekistan (Amu-Darya B.) ? op. by EPSILON D (100.0%) in Mubarek block

Coirón Amargo Sur Este block, Neuquén Basin, TD 4,804m, tested 628.4 bo/d from the Vaca Muerta shale, compl. Apr ’18.PAE (op), partners Madalena Energy + GyP Neuquen.

Coirón Amargo Sur Este block, Neuquén Basin, TD 4,804m, tested 628.4 bo/d from the Vaca Muerta shale, compl. Apr ’18.PAE (op), partners Madalena Energy + GyP Neuquen

It is understood that in August 2018 Global Petroleum Ltd was still looking for partners for its d80F.R-.GP, d81F.R-.GP, d82F.R-.GP and d83F.R-.GP exploration permits under application in the southern Adriatic Sea. Pending the awards of the permits, the company plans to acquire 1,045 km of 2D and possibly 300 sq km of 3D seismic over a combined surface of 2,986 sq km. Global Petroleum was awarded approvals of the environmental impact assessment (EIA) for 280 km of 2D and 100 sq km of 3D over the d82F.R-.GP and d83F.R-.GP applications in October 2016 and is still awaiting clearance for the two remaining ones. Objective in the area is oil in the Cretaceous carbonates of the Maiolica and Scaglia formations and the Lower Jurassic fractured mudstones/wackstones of the Corniola Formation. Global Petroleum Ltd holds a 100% operating interest in the four applications for exploration permits. For further information please contact the following: Steve Davies Exploration Manager Global Petroleum Limited 5 Charterhouse Square London EC 1M 6PX United Kingdom Tel: +4479 4281237

Global Petroleum Ltd was still looking for partners for its d80F.R-.GP, d81F.R-.GP, d82F.R-.GP and d83F.R-.GP exploration permits under application in the southern Adriatic Sea.

The Ministry of Petroleum and Energy (MPE) opened the APA 2020 licensing round on 19 June 2020. The area available has been increased by a further 36 blocks which are located in the western part of the Norwegian Sea. Bids must be received by 12:00 noon on 22 September 2020 and awards will be made in Q1 2021. The additional blocks (which passed through the public consultation process between 30 March 2020 and 11 May 2020) are: 6200/2, 3, 6 6300/9, 10, 11, 12 6301/3, 5, 6, 7, 8, 9, 10, 11, 12 6502/2, 3, 5, 6 6603/1, 2, 3 6604/1 6703/7, 8, 9, 10, 11, 12 6704/7, 8, 9,10,11 6705/7 The yearly APA rounds are focussed on the more mature areas of the NCS where exploration is potentially time critical. Discoveries are generally expected to contain smaller volumes but are likely to be within tie-back reach of existing facilities, enabling shorter development lead times and requiring lower expenditure.

The Ministry of Petroleum and Energy (MPE) opened the APA 2020 licensing round on 19 June 2020. The area available has been increased by a further 36 blocks which are located in the western part of the Norwegian Sea. Bids must be received by 12:00 noon on 22 September 2020 and awards will be made in Q1 2021. The additional blocks (which passed through the public consultation process between 30 March 2020 and 11 May 2020) are: 6200/2, 3, 6 6300/9, 10, 11, 12 6301/3, 5, 6, 7, 8, 9, 10, 11, 12 6502/2, 3, 5, 6 6603/1, 2, 3 6604/1 6703/7, 8, 9, 10, 11, 12 6704/7, 8, 9,10,11 6705/7

Add. DEA 23 Mar ’19: AE-0056-2M-Mezcalapa-06 block, onshore Sureste Basin, susp. o&g on 20 Mar ’19. Of note the well had been suspended for a while already, results (at the time) and reasons unknown. PTD was 3,955m, target U. Miocene.

Cibix 1EXP op. by Pemex (100%) in AE-0056-2M-Mezcalapa-06 block, suspended as an o&g discovery, target U.Miocene

Repsol has agreed with Total to buyout the latter’s 7.7% in the 120,000 boe/d Visund field in PL 120, thereby increasing its net Norwegian output to ab. 30,000 boe/d. Partnership will become Statoil (op), Petoro, ConocoPhillps, Repsol.

Repsol to acquire minority stake 7,7% in the Visund oil and gas field from Total (->0%, Statoil 53.2% op, Petoro 30%, ConocoPhillips 9,1%).

Alaminos Canyon block 380, lease G32954, Perdido Thrust Belt, WD 1,980m, cleared to plug on 6 Jun ’19, results yet n/a, Deepwater Thalassa DS. Target subsalt Frio + Wilcox sands. Shell (op), partners Chevron, Equinor + Repsol.

AC 380 1S1B0 (Blacktip sidetrack) expl in Alaminos Canyon block 380, lease G32954, Perdido Thrust Belt, WD 1,980m, cleared to plug on 6 Jun ’19, results yet n/a, Target subsalt Frio + Wilcox sands. Shell (op), partners Chevron, Equinor + Repsol.

NewAge and partner Tower are reportedly on the lookout for partners in their equally-shared Algoa-Gamtoos block, 11,833 sq km offshore in the NE Outeniqua Basin, a combined 50% available in exchange for funding 3D seismic + sharing some past costs. Additional interest could be secured by contributing towards an explo well.

NewAge and partner Tower are reportedly on the lookout for partners in their equally-shared Algoa-Gamtoos block, 11,833 sq km offshore in the NE Outeniqua Basin, a combined 50% available in exchange for funding 3D seismic + sharing some past costs. Additional interest could be secured by contributing towards an explo well.

Independent Oil and Gas plc (IOG) spudded appraisal well 48/24b-6 on the Harvey discovery in licence P2085 on 6 August 2019. The appraisal well was to clarify the up-dip potential of the Harvey structure and had a 63% geological chance of success. It is being drilled with the Maersk “Resilient” (J/U) rig and operations were expected to last for 60 days. On 11 September 2019 IOG announced that the well has reached a TD of 7,537 ft (2,297 m) in the Permian Leman sandstone reservoir. The top of the Leman sands was encountered at 7,086 ft (2,160 m). Initial analysis indicate that a 49 ft (15 m) gas column has been encountered. Wireline data and core samples will now be fully analysed to better understand gas volumes and potential deliverability. Harvey could be developed via the Thames pipeline export route if deemed commercial. The rig left location on 19 September 2019. Harvey is thought to hold minimum unrisked prospective gas resources of low case 85 Bcf, mid case 129 Bcf and high case of 199 Bcf. Currently IOG estimates that most likely 90 Bcf lies on its licensed acreage and in the case of a positive well result the company would request the OGA determine the Harvey licence area to include the full structure. IOG would try to fast-track the development of Harvey through exporting the gas via the newly recommissioned Thames pipeline. Interest in licence P2085 is held solely by IOG North Sea Limited. However, in an announcement from 26 July 2019 it was stated that CalEnergy Resources Limited has an option to acquire a 50% interest in the Harvey acreage within three months of the completion of the appraisal well.

048/24b-06 (Harvey) (IOG N.Sea 100%) in P2085 block, 25m gas column at the top of the reservoir, assessment planned to determine potential Harvey devt. TMD=2297m (Leman sst),

South African Sasol reports a possible sale of shares or assets in order to raise cash as a result of the oil price collapse. Sasol is likely not alone here, but it adds that oil prices and Covid-19 impact have ‘considerably modified its perspectives’ in only a few weeks. According to Moody’s Sasol’s debt amount to ab. USD 8,6 bn. On a wider scale, Africa's economic growth could fall from 3.2% to 1.8% at the end of 2020, evidently depending on conditions.

South Africa, not found

Aker BP spudded exploration well 24/9-13 on 16 June 2019 targeting the Rumpetroll prospect which is a sandstone injectite complex similar to the nearby Frosk oil discovery which was made in February 2018. The well is located in PL 869 and was drilled using the “Deepsea Nordkapp” S/S. Aker BP reached TD at 2,305 m in the Paleocene Heimdal Formation. A 3 m gas column was proven in the Eocene Hordlaland Group, with 2 m of sandstone. These sands are remobilised from the Heimdal and Hermod Formations. The underlying Eocene Balder Formation contained 17 m net of sandstone with shows. On 17 July 2019 appraisal sidetrack 24/9-13 A was kicked-off and was drilled to TD at 3,466 m (2,240 m TVDSS) in the Heimdal Formation. This well encountered a 40 m gas column with 7 m of sandstone in the Hordaland Group. The two wells together confirmed an overall 77 m gas column and recoverable reserves are estimated at 4-11 MMboe, significantly less than the pre-drill estimate of 45-148 MMboe. 24/9-13 A was plugged and abandoned on 29 July 2019.   Frosk, which lies to the north of Boyla, was discovered by 24/9-12 S. A 10 m oil column was proven in a 40 m thick Eocene Hordaland Group sandstone injectite with an OWC established. Higher up in the Hordaland Group there were three thin oil-bearing partially cemented sands totalling 5 m. The secondary Paleocene Hermod Formation objective was water-wet (there was 50 m of sandstone present). Sidetrack 24/9-12 A deviated 850 m to the southwest and confirmed a 30 m oil column in Hordaland injectites with no OWC. Four thin gas-bearing sands totalling 5 m were found higher up in the Hordaland Group. Aker BP has estimated recoverable reserves at 30-60 MMboe. Interest in PL 869 is divided between Aker BP ASA (60% + operator), Lundin Norway AS (20%) and Var Energi AS (20%).

024/09-13 (Rumpetroll) (Aker BP 60% op, Lundin 20%, Var Energi 20%) in PL 869, near the Boyla field, P&A, small gas discovery (4-10 MMboe recov). Encountered 3m gas column in the Hordaland group, + 17m of good-quality Balder reservoir with oil traces. 24/09-13 A encountered a 40m gas column in injectite zones, of which 7m good reservoir quality sst in the Hordaland. OWC not encountered.

Belize’s Ministry of Economic Development, Petroleum, Investments, Trade & Commerce and Blue Creek Exploration signed a Production Sharing Agreement (PSA) on 9 August 2017 for 296 sq km -  a total of seven blocks: 228, 246, 247, 264, 265, 281 and 282. The contract has an exploration period of eight-years, with an initial exploration phase of two-years and three successive renewal periods of two-years each. If commercial discovery is made, there will be a development and production period of 25-years. Blue Creek has committed to a USD 4.345 million total investment, contract has a 10% royalty for crude oil and 7.5% for natural gas. No details have been released as to when the exploration program will start.

United Oil & Gas has announced the completion of the farm-in and the transfer of the 20 per cent interest in the Walton-Morant Licence, offshore Jamaica from Tullow Jamaica to UOG.

Bonasse licence in SW Peninsula (Cedros) acreage, TD 1,412m, HC's in 6 reservoir intvs (total 720m) in the target U, M + L Cruse horizons, tested oil from 3 intvs in the L + M Cruse (40 API in the Lower Cruse, 17-20 API in the Middle Cruse, high water cut, addit. zones testing planned). Columbus has signed* terms for a full carry of a Lower Cruse appr/devt well (Saffron-2) in 3Q '20. Individual devt plans are being considered for the M + L Cruse discoveries. * with a third party drilling contractor

Saffron 1 nfw. (Beach Oilfield 100%) in Bonasse licence in SW Peninsula (Cedros) acreage, HC's in 6 reservoir intvs (total 720m) in the target U, M + L Cruse horizons, tested oil from 3 intvs in the L + M Cruse (40 API in the Lower Cruse, 17-20 API in the Middle Cruse, high water cut, addit. zones testing planned). TD=1412m

Perenco was recently awarded the Olowi permit, which contains the Olowi Marin field, committing not only for exploitation of oil but also for the devt of the field’s gas potential towards the implementation of an LNG project. The field produced for 10 years under operator CNR, but the Knock Allan FPSO was demobilised in early ’19 and the company elected to not renew the permit past 30 Apr ’19.

Perenco (100%) has been awarded by Gabonese authorities the Olowi permit.

A new company could take over hydrocarbon production on Block 8 in the Maranon Basin if the authorities approve a pending transfer of interest in the block, according to information from the Perupetro. Pluspetrol Norte is attempting to transfer its 100% working interest in the block to Altamesa Energy Canada. The block is the site of both long term production and a continuing socio-environmental conflict as some communities in the block oppose oil production there due to poor environmental practices in the past leading to contamination and serious effects on the health of residents in some communities. This is the stated reason Pluspetrol wants to sell the block. These conflicts with the communities have at times been violent and have led to the temporary seizure of production facilities. This led to an average oil production in Block 8 for October of 2,540 bo/d which has increased to 6,257 bo/d as of 19 November.Pluspetrol Norte is a Peruvian partial subsidiary of Pluspetrol which in 2017 submitted a US$ 169 million five-year work program in its environmental impact statement (EIS) for Block 8. The EIS included drilling eight development wells, along with water injection wells, workovers and expansion of facilities. The Pluspetrol work program EIS was designed to increase production and guarantee reserve recovery on the block. The indigenous federations representing the Pastaza, Corrientes, Tigre and Maranon river basins have been involved with Pluspetrol in negotiations over the historical contamination from surface discharge of waste waters and other poor oil field practices that have affected the indigenous population on the block. Although this is no longer an issue in the present, the responsibility for the liability of the contamination and cleanup remains a tough issue with legal arguments to be made against Pluspetrol, former operator Occidental and the Peruvian government which used to allow the contamination due to a weak regulatory framework in the past.

A new company could take over hydrocarbon production on Block 8 in the Maranon Basin if the authorities approve a pending transfer of interest in the block, according to information from the Perupetro. Pluspetrol Norte is attempting to transfer its 100% working interest in the block to Altamesa Energy Canada.

CNOOC is offering equity in the AGC Profond block, 6,688 sq km in the deepwater MSGBC Basin, share negotiable, ahead of drilling next year. The block is home to 6 prospects, amongst which Wolverine (Barremian) + Civet (Albian). A data room opens 7 Jan ’19, contact Robert Hughes, [email protected].

CNOOC is offering equity in the AGC Profond block, 6,688 sq km in the deepwater MSGBC Basin, share negotiable, ahead of drilling next year. The block is home to 6 prospects, amongst which Wolverine (Barremian) + Civet (Albian).

Add. DEA 1 Feb ’18 (adds tests) : Mirpur Khas 2568-7 EL, Lower Indus onshore, TD 3,331m, o+g discovery in late Dec ’17, tested 23.4 MMcfg/d + 72 bc/d, presumably from the target Lower Goru. UE (op), partners Bow Energy, Zaver Petr. + Govt Holdings.

Pakistan (Indus B.) Hakro 1

JX Nippon exited P199 block 3/8a Ninian Field Area (50.7 sq km), assigning its 45% (12.94% field interest) to operator CNR, as reported by OGA on 2 July 2018. JX Nippon's exit is likely related to the planned decommissioning the Ninian North platform, which forms one of three fixed platforms on the Ninian Field. CNR submitted draft decommissioning plans to the Department for Business, Energy and Industrial Strategy (BEIS) in June 2017, and the plans cover a 15-year period with the topsides removal due to commence in 2019. The Ninian Field produces from the Middle Jurassic Brent Group and was discovered by 3/03- 1 (1974) with production commencing in 1978. CNR International (UK) Ltd now holds 100% operator stake in all the Ninian Field licences including P199 - 3/8a Ninian Field Area.

JX Nippon exited P199 block 3/8a Ninian Field Area (50,7km²), assigning its 45% (12,94% field interest) to operator CNR

The govt has reportedly nominated ONGC to operate the Panna-Mukta fields after the expiry of the Shell-Reliance PSC for the Panna-Mukta-Tapti fields, Bombay Basin. Production from the fields has declined significantly, and Tapti ceased to produce in March 2016.

The govt has reportedly nominated ONGC to operate the Panna-Mukta fields after the expiry of the Shell-Reliance PSC for the Panna-Mukta-Tapti fields, Bombay Basin. Production from the fields has declined significantly, and Tapti ceased to produce in March 2016.

As of 17 May 2018, Independent operator Paul L. Craig closed on a farm-out agreement in mid-November 2018 for the South Nanushuk prospect are in the National Petroleum Reserve-Alaska (NPR-A) and include AA-093747, AA-093748 and AA-093749. The total acreage included in the blocks is 35,425 acres (143.36 sq km). The acreage sets on trend south of the Horseshoe and Willow Nanushuk Formation oil discoveries drilled by Repsol and ConocoPhillips respectively. These discoveries were made in topsets of the west to east prograding clinoforms across the central North Slope. In August 2018, Independent operator Paul L. Craig and partners offered three blocks for sale or farm-out north of Umiat and west of Gubik fields. The three blocks called the The operator believes the Nanushuk clinoforms arc through the South Naunushuk prospect beginning south of Umiat Field and extend north though the Pikka Unit. The three tracts, include AA-093747, AA-093748 and AA-093749, were awarded from the NPR-A Sale 2013 for a bonus bid of USD 272,049 or USD 7.68 per acre. Partners in the tracts include Paul L. Craig 41.6667%, Peter G. Zamarello 50% and Paul Gardener 8.3333%. Contact information for Paul L. Craig 907-830-1151 or [email protected]

Paul L. Craig closed on a farm-out agreement in mid-November 2018 for the South Nanushuk prospect are in the National Petroleum Reserve-Alaska (NPR-A) and include AA-093747, AA-093748 and AA-093749. The total acreage included in the blocks is 35,425 acres (143.36 sq km).

Mubadala announced an agreement to farm out 20% interest in the Andaman I and South Andaman gross split contracts, in offshore North Sumatra, to Premier Oil, on 17 July 2019. The deal is subject to customary conditions and approvals. Upon final approval, Mubadala will remain operator of both blocks with 80% interest. The deal will reinforce the cooperation between Mubadala and Premier in exploring the deep water area of the North Sumatra Basin. The companies are also partnering in the adjacent Andaman II PSC, in which Premier holds a 40% operating interest and Mubadala controls 30%. The remaining 30% in the Andaman II block is held by KrisEnergy. In May 2019, PGS completed a large multi-client 3D seismic survey across the South Andaman, Andaman I and Andaman II blocks. The new data, covering approximately 9,000 sq km, will improve the understanding of the proven Miocene carbonate and Oligo-Miocene clastic plays and of the deeper, unproven syn-rift plays in the area. The survey, which commenced in December 2018, was acquired using the “PGS Apollo” S/V. No exploration drilling has taken place within the Andaman I block, while two unsuccessful wells have been drilled in the South Andaman acreage by previous operators (Lasmo in 2000 and Eni in 2008). Mubadala signed gross split contracts for the Andaman I and South Andaman blocks in April 2018 and February 2019 respectively, with initial interest of 100% in both blocks. Background Information Andaman I block The Andaman I block was offered as part of the Conventional Oil and Gas Bidding First Round 2017 under the Direct Offer mechanism. Mubadala was awarded the block on 31 January 2018, and contract signature under Gross Split fiscal terms took place in April 2018. The base government/contractor split under Gross Split terms is 57%/43% for oil and 52%/48% for gas, subject to modifiers depending on the specific situation of the block. Signature bonus for the block was USD 750,000. The block, with an area of approximately 7,400 sq km, is located primarily in the deep water area of the South Sumatra Basin, with the western edge bounded by the Mergui Ridge. No well has been drill to date within the acreage. Exploration targets in the area could be clastic reservoirs of the Upper Oligocene Parapat Formation, Lower Miocene Bampo Formation and Middle Miocene Baong Formation, mostly in structural trap settings. The minimum exploration commitments for the first three-year exploration period include G&G studies and a 500 sq km 3D seismic survey, for a total value of USD 2.15 million. The seismic commitment was likely fulfilled by the multi-client 3D survey acquired in early 2019. South Andaman block The South Andaman block was offered in the Conventional Oil and Gas Bidding Third Round 2018 under the Direct Offer mechanism. Mubadala was announced as the winner of the block on 27 December 2018 and signed the Gross Split contract on 18 February 2019. Signature bonus amounted to USD 2 million. The block has an area of approximately 3,550 sq km and is located in the offshore part of the North Sumatra Basin, under the Aceh Province jurisdiction. Water depth in the block ranges between approximately 100 and 1,500 m. The block was initially reported by Migas as an active Joint Study Area (JSA) in January 2017. Potential exploration targets in the block include fluvial to alluvial clastic reservoirs deposited during the syn-rift stage (Parapat, Bampo formations) and post-rift stage (Baong and Keutapang formations), ranging from Oligocene to Upper Miocene. The minimum exploration commitments for South Andaman include G&G studies and 500 sq km of 3D seismic acquisition, for a total expenditure of USD 2.15 million. The seismic commitment was likely fulfilled by the multi-client 3D survey acquired in early 2019.

Premier confirmed it had signed an agreement with operator Mubadala to earn a 20% interest in South Andaman and Andaman I blocks PSC split PSC.

On 5 April 2018 it was reported that Cepsa will take over the 30% interest of Petronas in the Bir El Msana oil field, Rhourde El Rouni (BMS) permit, Block 401c, Berkine Basin. In 2017, Petronas reported its intention to withdraw from Algeria where its only asset was Bir El Msana. The deal is subject to approval from the authorities. After the deal, interests in the Bir El Msana field will be as follows: Cepsa, operator with 75% and Sonatrach with 25%. In August 2015 it was announced that the Bir El Msana field came on stream. Its production rate is 12,000 b/d of oil. A nine-well development program on the Bir El Msana (BMS) field started in 2012. First oil was expected in April 2014 but there have been delays. Other E&P activities of Cepsa in Algeria are as follows. Apart from Bir El Msana, Cepsa also operates the Rhourde El Krouf and Ourhoud fields in the Berkine Basin. The combined production of these three fields is around 130,000 b/d of oil. In the same basin, the company is also developing the Kechen En Nasseur oil discovery in the Rhourde Er Rouni II block. In the Timimoun Basin, Cepsa partners Total for the Timimoun gas development project which came on stream in March 2018. Timimoun has a plateau production rate of 177 MMcf/d of gas.

On 5 April 2018 it was reported that Cepsa will take over the 30% interest of Petronas in the Bir El Msana oil field, Rhourde El Rouni (BMS) permit, Block 401c, Berkine Basin.

In March 2020, Discover – partner of Tullow in the Block 35, 36 and 37 – reported it has started a farm-out process during the month. The licence is located in water ranging in depths between 2,500 to 3,000 m within the Outer Rovuma Fan, roughly 100 km to the east of the large Mozambican gas discoveries. Tullow may drill a well in the licence in 2021. It is believed that the well will test two large stratigraphic prospects that are partially overlapping. The mid-Eocene prospect has a Pmean prospective resource of 5.8 Bbbl (for the oil case) or 3.7 Bboe (for the gas case). The Cenomanian prospect has a Pmean prospective resource of 3.5 Bbbl (oil) or 2.5 Bboe (gas). In October 2019, Tullow completed a 3,000 sq km 3D seismic data over the licence. Interest in the licence is held by Tullow Comoros Ltd (35% + operator), Discover Exploration Comoros BV (25%) and Bahari Resources Ltd (40%, wholly owned subsidiary of Discover Exploration Ltd). Background Information The companies were awarded the licence in March 2014. In May 2014 the companies started the acquisition of a 2,330 km 2D infill seismic survey being part of the GX Technology (ION Geoventures) East Africa SPAN programme. The survey was completed in early August 2014. The seismic survey fulfilled the commitments for the initial period that ends in March 2018. The data were reported of excellent quality, and initial interpretation suggested an extension of the Mozambican reservoir play beneath the Comoro acreage. Vast areal extend of Paleocene fan has been interpreted over Blocks 35, 36 and 37, with possible source rock in the oil window. The previous 2D seismic survey in the area was shot in 1H 2011, also part of the East Africa SPAN programme. Commitment for the second exploration phase (2018 to 2021) is to acquire either 2D or 3D seismic data. Commitment for the last and third exploration phase is to drill one exploration well. The Comoros’ acreage is a frontier area. The main potential for O&G business appears to be the eastern extension of the Rovuma Delta where deepwater fan stratigraphic plays are expected to be found. Faulting along the ridge separating the Comoros from East Africa Continent is also known to have created large anticlinal structures

Discover – partner of Tullow in the Block 35, 36 and 37 – reported it has started a farm-out process during the month. The licence is located in water ranging in depths between 2,500 to 3,000 m within the Outer Rovuma Fan, roughly 100 km to the east of the large Mozambican gas discoveries.

On 7 June 2018, the consortium of Petrobras with 30% working interest, Chevron with 30%, and Shell with 40%, was granted a preliminary award of the Tres Marias block from the 4th PSC Pre-Salt Bid Round.  There were no other bids for the Santos Basin block. The consortium will pay a fixed signing bonus of USD 27.78 million, at 1 USD to 3.60 BRL, and has estimated minimum investment guarantees of USD 68.33 million.  The winning Petrobras consortium bid 49.95% state take versus the second place Petrobras consortium bid of 18% state take.  The second place consortium included Total with 30% and BP with 30%. The Tres Marias block covers an area of 821.49 sq km and the minimum state take was set at 8.32% for the PSC contract.

the consortium of Petrobras with 30% working interest, Chevron with 30%, and Shell with 40%, was granted a preliminary award of the Tres Marias block from the 4th PSC Pre-Salt Bid Round.

After months of suspension on claims by the Chinese govt that its field was located in Chinese territory, Repsol has reportedly agreed to transfer its 51.75% stake in the Ca Rong Do (Red Emperor) o&g project in block 07/03 to PetroVietnam. It will also release its 40% in blocks 135-136/03, also pressured by the Chinese since the latter intervened here 3 years ago. Both moves should be completed by end 2020. Repsol had plans for 2 explo wells in 07/03, Nam Con Son Basin, prospects designated Cobia and Ca Rong Do NE. So far Repsol (op), partners PVEP, Mubadala + PetroVietnam.

After months of suspension on claims by the Chinese govt that its field was located in Chinese territory, Repsol has reportedly agreed to transfer its 51.75% stake in the Ca Rong Do (Red Emperor) o&g project in block 07/03 to PetroVietnam. It will also release its 40% in blocks 135-136/03, also pressured by the Chinese since the latter intervened here 3 years ago. Both moves should be completed by end 2020.

Further to DEA 28 Nov ’17, Exxon is yet to sign for 3 offshore blocks, but officials comment a deal is close. Word on the street is that these would be (from south to north) C-14, C-17 and C-22 in ultra-deepwaters west of existing held acreage. Confirmation is sought. These will be Exxon’s 1st holdings in the country in many years.

Mauritania, not found

Horiz shale wells in the Chenghao oilfield, Yishan Slope of the Ordos Basin, both fracked and tested resp. 886 bo/d + 791 bo/d from the Chang 7 Unit (Yanchang 7 Unit), Yanchange fm.

Chengye 1 & 2 expl Horiz shale wells in the Chenghao oilfield, Yishan Slope, both fracked and tested resp. 886 bo/d + 791 bo/d from the Chang 7 Unit (Yanchang 7 Unit), Yanchange fm.

Sudan Petroleum Corp (Sudapet) is looking to farm out and or finance Block 2A and Block 4 in Muglad Basin, once the termination of current EPSA with the GNPOC group is completed. Sudapet was also considering the option of reuniting both blocks with Block 2B, operated by 2B OPCO (Sudapet, 50% and Petrolines, 50%). As of the end of July, GNPOC’s Block 2A and Block 4 were producing approximately 18,300 bo/d. GNPOC operates both blocks in partnership with Petronas Carigali (30%), CNPC (40%), Sudapet (5%) and ONGC Nile Ganga BV (25%).

Sudan, not found

According to industry sources in Q1 2020, CHx Belize LP (CHx) was awarded a 3,131 sq km block, in the North Peten Basin, west Belize on the border with Guatemala. The Production Sharing Agreement (PSA) is due to expire in October 2027, with a relinquishment opportunity in October 2021. As of February 2020, work was under way reprocessing and interpreting existing seismic data, reviewing and evaluating existing well data and other geological and geophysical data. The acreage surrounds the Belize Natural Energy-operated Spanish Lookout and Never Delay fields, and borders the recently awarded Princess Petroleum Block and FCRL Block (see related articles). The Spanish Lookout and Never Delay fields were discovered in 2005 and 2008 respectively. At it's peak in 2009, Spanish Lookout produced 5,000 bo/d, down to 1,000 bo/d in 2019.

Hx Belize LP (CHx) was awarded a 3,131 sq km block, west Belize on the border with Guatemala.

At an informative event held by IAPG (Instituto Argentino del Petroleo y del Gas) in Houston, Texas, USA, on 26 June 2019, representatives from the Santa Cruz Province’s Institute of Energy announced the province’s plan to hold a bid round for four blocks in onshore Austral Basin covering over 2,350 sq km of area in the second half of 2019. Main objectives in the blocks were said to be unconventional oil and gas opportunities from the producing tight sands of Lower Magallanes Formation, as well as the prospective shale of Palermo Aike Formation with reported potential of 1 Bbo and 85 Tscfg. Each block requires a different amount of minimum investment for the first exploration period, with the mandatory drilling of one exploratory well is expected in the second period. More information about the round is expected to be released in the next few months. Block Name Block Sqkm Minimum Commitments (1st exploration period) Camusu Aike 245.8 USD 8.87 million El Campamento 1,108.72 USD 26.03 million El Martillo 609.36 USD 18.965 million La Azucena 386.67 USD 13.945 million   No discoveries have been made in any of the bid block areas. Camusu Aike block has never been drilled, meanwhile the El Martillo block has not been drilled since 2005, and same for the La Azucena and El Campamento areas since the late 1990’s. However, all said blocks are situated next to the unconventional exploitation concessions of El Cerrito and Campo Indio Este operated by Cia General de Combustibles (CGC) where El Puma 3 tight gas discovery was made from the Lower Magallanes Formation in August 2018. More information regarding the bid round can be obtained by contacting the Institute of Energy of Santa Cruz Province at [email protected] or by phone: +54 (02966) 436653 / 437467 / 437455. Background Information The Province of Santa Cruz issued a call for tenders for the Tapi Aike, Paso Fuhr, El Turbio, and El Turbio Este in its last Licitacion Publica Nacional e Internacional round in June 2017 after all areas were relinquished to the province in 2015 due to lack of investments. In September 2017, Tapi Aike was awarded to CGC, while El Turbio was awarded to state company YPF, and El Turbio Este was awarded to to Chilean state company ENAP. Meanwhile Paso Fuhr was awarded to a joint venture of YPF and CGC in March 2019 following a separate application that was submitted in late-2018.

At an informative event held by IAPG (Instituto Argentino del Petroleo y del Gas) in Houston, Texas, USA, on 26 June 2019, representatives from the Santa Cruz Province’s Institute of Energy announced the province’s plan to hold a bid round for four blocks in onshore Austral Basin covering over 2,350 sq km of area in the second half of 2019.

Petrobras is offering its 100% interest in the Lagoa Parda, Lagoa Parda Norte + Lagoa Piabanha prod. leases in the onshore Espirito Santo Basin.  EoI’s by 19 Oct ’18, qualification docs by 29 Oct ‘18 to [email protected].  The offering is part of the original Topaz divestment project of 2017.

Petrobras is offering its 100% interest in the Lagoa Parda, Lagoa Parda Norte + Lagoa Piabanha prod. leases in the onshore Espirito Santo Basin. EoI’s by 19 Oct ’18, qualification docs by 29 Oct ‘18 to [email protected]. The offering is part of the original Topaz divestment project of 2017.

In April 2019 it was confirmed that Warwick Onshore Exploration has left onshore licence EXL 269 which contains Cuadrilla’s Preston New Road wellsite. The company’s 5% interest has been split between Cuadrilla subsidiary Cuadrilla Elswick (No.2) Ltd (3.3125%) and Spirit Energy’s subsidiary Elswick Energy Ltd (1.6875%). The acreage not only contains the shale gas exploration site at Preston New Road but also the Elswick discovery which is a small Permian gas field producing onsite electricity. Cuadrilla announced in November 2018 that it has seen natural gas flow to surface along with the recycled water from the Shale at its Preston New Road site in EXL 269. Volumes of gas are small and due to operation constraints from micro-seismicity mean that not as much sand has been injected into the shale during the fraccing process as was planned. The company commenced hydraulic fracturing work on 15 October 2018. Fraccing operations were expected to take approximately three months to complete where the company was to frac two wells. On 29 October 2018 Cuadrilla confirmed that three micro-seismic events above 0.5 ML have been recorded at the site with one event measuring 1.1 ML. Following the events an 18 hour pause to fraccing operations was undertaken. On 14 December 2018 Cuadrilla announced that further micro-seismic events had been recorded with the largest reaching 0.9 ML. Cuadrilla again paused operations for 18 hours and the well integrity was checked and verified. On 6 February 2019, Cuadrilla confirmed that flow testing indicated there is the presence of high quality gas in an excellent shale gas reservoir. A complex fracture system was introduced into the shale and when sand was injected into the fractures they have remained in place whilst the gas flowed. The gas has a high methane content so requires minimal processing. Work is not fully completed on testing but during the early stages gas flowed at a stabilised rate of 100,000 scf/d and peaked at 200,000 scf/d. The company has submitted an application to the OGA to allow the wells to be tested fully. If approval is given Cuadrilla expects to commence work later in 2019. The well has been shut-in to allow monitoring and pressure build up. Following completion of the deal interest in the licence is held by Cuadrilla subsidiary Cuadrilla Elswick Limited (46.1875% + operator), AJ Lucas subsidiary Elswick Power Limited (23.75%), Spirit Energy subsidiary (22.75%) and another Cuadrilla subsidiary Cuadrilla Elswick (no.2) Limited (7.3125%)

United Kingdom (West Lancashire Sub-basin (East Irish Sea B.)) Elswick

Further to DEA 6 May ’19, the B2 block PSA is reportedly to be signed by South African Strategic Fuel Fund (SFF, op), the Ministry of Petroleum and Nilepet (S. South Sudan NOC).  B2 lies in the Muglad Basin, Jonglei state, and is one of the 3 spinoffs of the 120,000-sq km parent block B.

A PSA is reportedly inked for block B2 in Jonglei State, between South Africa’s state-owned Strategic Fuel Fund (SFF) and South Sudan state oil company Nile Petroleum (NilePet). The acreage in focus was previously designated block B2, is one of the 3 spinoffs of the parent block B (120 000km²), which was once claimed by Total under a concession granted by the Khartoum administration but never ratified after South Sudan gained independence in 2011.

Berlanga is understood to have completed operations at wildcat WS B (M-08 E1) in block M-08, Moattama Basin, around mid-April 2020, with results unreported. The well had a PTD of approximately 1,100 m. As of early April 2020, operations were ongoing at a drilled depth of approximately 450 m. The well was spudded in late March 2020 using the "Noble Clyde Boudreaux" S/S, which was mobilized to the drilling location in mid-March. The rig had been contracted to drill one firm and one optional well in the shallow water area of the block. It is understood that the optional well will not be drilled. The WS prospect is a faulted four-way dip closure within Lower-Middle Miocene Upper Burma Limestone. Unrisked recoverable reserves in the prospect are estimated by Berlanga at 2.1 Tcf (Pmean). WS is located at a water depth of approximately 120 m. Geological Chance of Success (GCOS) has been estimated at 39%. According to the operator, key risk factors for this prospect are hydrocarbon charge and retention. The significance in the M-08 drilling programme lies in testing the southward extension of the Miocene carbonate play which has been proven successful by Total's Yadana field in block M-05, located over 100 km north. Shallow gas (possibly from Plio-Pleistocene sands) was considered by Berlanga as a potential drilling hazard for this campaign. The second target identified in the block is the SR prospect, located 40 km southeast of WS in about 200 m of water. SR is a faulted Miocene carbonate buildup within Upper Burma Limestone. Unrisked recoverable reserves for SR are estimated by the operator at 305 Bcf (Pmean), with a GCOS of 46%. The SR prospect could be in communication with a nearby structure ("GR") providing further upside. Berlanga had indicated an estimated cost of USD 30 million for the full two-well programme. In case of commercial success, the nearest potential tie-in options are represented by the Yadana field and PTTEP's Zawtika field located 150 km east in block M-09. Berlanga likely conducted a sea floor site survey for the proposed well locations between November and December 2019. The contract for the survey was awarded to PTSC Geos and Subsea Services Company (PTSC G&S) in September 2018. Information as of October 2019 indicated that the operator was going through a tender process to identify a rig suitable to operate at water depths between approximately 100 and 300 m. It is understood that the initial drilling scoping report was submitted to the government in January 2017. The report was resubmitted in August 2017, to incorporate revisions by the Myanmar Environmental Conservation Department. In addition to WS and SR, an additional 15 prospects have been identified in the shallow-water part of the block, with upside potential of up to 7 Tcf. The prospects have been likely matured from the interpretation of a 3D seismic survey conducted by the company in 2016. Approximately 3,100 sq km of 3D seismic data were acquired using the “PGS Apollo” survey vessel in the first half of the year. The new data, which covered the eastern part of the block, were processed with pre-stack time migration in October 2016. Water depth in block M-08 ranges from less than 100 m in the northeastern part, to more than 600 m at the southwestern edge. Only one well has been drilled in the block to date, M-08A 1 by Total in 2000 (dry). A PSC for block M-08 was officially signed on 5 December 2014 and right holders are Berlanga Holding BV (95%, operator) and A-1 Mining Company (5%). The initial study period for the block expired in October 2018 and was subsequently extended by 1.5 years, to March 2020. Background Information Block M-08 is well located with respect to potential Middle and Lower Miocene (Upper Burman Unit) carbonate buildups on trend with the producing 5.8 Tcf Yadana field to the north and Pliocene to Miocene delta front clastics from the Zawtika Development Project to the east. The block contains a single dry well drilled by the previous operator Total in February 2000. Block M-08 was first explored by Total EP Myanmar after being awarded in January 1997 with eight years exploration period, which expires on January 2005. In January 2000, Total EP Myanmar drilled its first well in the country, M-8 A1, targeting the Oligocene to Lower Miocene carbonates. The well was plugged and abandoned after the carbonate reservoir was found water bearing sighting hydrocarbon charge as the main risk in petroleum prospecting. Interest holders in the block were Total Myanmar Exploration and Production (operator with 36.75%), Unocal Myanmar Offshore Co Ltd (33.25%) and PTTEP (30%). PTTEP acquired its 30% interest through a farm-in in July 1997. Russian firm Zarubezhneft JSC and joint venture partners Russia's Itera Group and India's Sun Group then picked-up the block and signed a PSC with MOGE for block M-8 in April 2006, after the relinquishment by Total. But then in June 2007, operator Zarubazhneft withdrew from the block, allowing Ngwe Oil and gas, a joint venture company set up by Russia's Itera Group and India's Sun Group, to hold 100% operating stake in the block. Between March and April 2008, Ngwe Oil and Gas acquired 3,500km of 2D seismic over the block as part of its work commitment. Ngwe Oil & Gas relinquished the block in September 2011 with no exploration wells were drilled. Berlanga was awarded block M-08 following the First Offshore International Bidding Round 2013. The production sharing contract was signed in December 2014 between MOGE Managing Director-U Myo Myint Oo, Berlanga Myanmar Pte Ltd – Mr. Johannes Hans Braakman and A-1 Mining Company-U Yan Win. MOGE received signature bonus of USD 15 million and USD 500,000 for data fee. The PSC carried a one-year feasibility study period and six-year exploration period (two phases). Berlanga is planning to spend USD 153 million during the PSC period.

M8-E1 (Whale South) (Berlanga Myanmar 95% op, A-1 Mining Co Ltd 5%) in M-8 block P&A, dry (unsuccessful TBC), TD of 960m within the Miocene carbonate section (Lower Miocene Upper Burman limestone objectives).

In early-November 2017, local reports indicated that Patagonia Oil Corp has acquired Roch’s 10% working interest in the Llancanelo block. The purchase effectively increased the company’s stake in the concession to 39%, following its acquisition (via affiliate company PentaNova Energy) of Alianza Petrolera Argentina from Hong Kong-based Petro AP in August 2017. Alianza previously held 29% interest in the block. State company YPF is the operator with 61% controlling interest.   The Llancanelo block covers 26.56 sq km of onshore land in the Mendoza Province side on the Northeast Platform of the Neuquen Basin. Recently in April 2017, Patagonia signed an agreement to acquire 11% participating interest on the block from YPF for USD 40 million, which is still pending on approval from the government of Mendoza Province. It was reported that the companies plan to develop a heavy oil pilot project in the block for a total investment amount of USD54 million over the next 36 months, with YPF remaining as the operator.

Alianza Petrolera Argentina has agreed to acquire a 10% stake in the Llancanelo block from Roch (->0%, YPF 50% op, Patagonia Oil 11%, PentaNova 29%).

Chevron Australia (WA-383-P) Pty Ltd was awarded retention lease WA-89-R, located in the Investigator Sub-basin, North Carnarvon Basin, on 26 July 2018.  The lease has been granted over the Blake gas discovery for a period of five years and it will expire, or be eligible for renewal, on 25 July 2023. Work commitments have been assigned for the duration of the permit’s validity and include seismic interpretation of the reprocessed Honeycombs 3D seismic data, which was acquired in 2012 by PGS, and static reservoir modelling. The Blake gas discovery was made 2014. Given the remote location of the field (approximately 230 km from Exmouth), the estimated resources are perhaps not large enough to support a standalone development. In the fifth and final term of the lease, Chevron plans to review of commercial development schemes such as pipeline ullage, floating LNG and tie-back options. Within a 50 km radius of the Blake discovery lays around 12 Tcf of undeveloped resources, including the Scarborough and Nimblefoot fields. Within a 75 km radius, this extends to the entire Equus project fields, and totals around 15 Tcf of undeveloped resources with only three operators: Chevron, Woodside and Western Gas. WA-89-R covers an area of 563 sq km and has been awarded from exploration permit WA-383-P. The exploration permit has been reduced in area from 1,607 to 1,044 sq km and no longer covers any discoveries but could remain prospective, laying between Scarborough and the Western Gas operated Equus project fields. In October 2017, WA-83-R was also awarded over the Pinhoe gas discovery. WA-89-R was awarded on 26 July 2018. Participants in the licence are: Chevron Australia (WA-383-P) Pty Ltd (50% + Operator) and Shell Australia Pty Ltd (50%).

Chevron Australia (WA-383-P) Pty Ltd was awarded retention lease WA-89-R, located in the Investigator Sub-basin, North Carnarvon Basin,

Ref. DEA 4 Sep ’18, the DGH has postponed the planned contract signatures of OAL I round contracts beyond the initially reported 6 September, new date n/a. 55 blocks are to be assigned. Please refer to GEPS for the full list of winners.

DGH has postponed the planned contract signatures of OAL I round contracts beyond the initially reported 6 September, new date n/a. 55 blocks are to be assigned.

Block 7 (Butabul), Wusta Governorate, recent drilling reportedly encountered deeper gas + cond. in the Barik reservoir of the Sahmah field, ‘multi-TCF’ potential. Main regional target otherwise Haushi Group (L. Gharif sst). Block 7 is home to the Sahmah, Ramlat + Rija fields.

Sahmah 25 dpw in Block 7 (Butabul), recent drilling reportedly encountered deeper gas + cond. in the Cambro-Ordovician Barik sst. reservoir of the Sahmah field, ‘multi-TCF’ potential.

On 19 September 2018, Pertamina Hulu Mahakam (PHM), operator of the Mahakam Offshore PSC, reportedly signed a Heads of Agreement (HoA) for the transfer of 10% Participating Interest (PI) to a company owned by the provincial government of East Kalimantan, PT Migas Mandiri Pratama Kutai Mahakam. Following the HoA, the companies have committed to continue discussions regarding the PI transfer until the final agreement, which is expected to be signed within six months. The 10% PI transfer to local government-owned enterprises is in compliance with Ministerial Regulation No. 37/ 2016, aimed at providing direct benefits from oil and gas activity to the local administrations. The regulation applies to blocks in development and production stage. PHM, a fully owned subsidiary of Pertamina, is operator of the block with 100% interest. The company was assigned the Mahakam Offshore PSC since January 2018, after the expiry of the previous contract operated by Total. The block reportedly had reached an average production of around 960 MMcfg/d as of August 2018, below the annual target of 1,008 MMcf/d. Liquids production was reported at 43 Mb/d, compared to the target of 46 Mb/d. Pertamina has deployed two swamp barges and one jackup rig in the first half of the year. The company is seeking at least one additional rig to accelerate development drilling in the block. Background Information The original 16,870 sq km Mahakam PSC was awarded to Japex on 31 March 1967. No bonuses were due at the time of the award but the PSC carried a Work Obligation of USD 7.5 million in six years. Total farmed in to the PSC in 1970 and assumed operatorship. Partial relinquishments in 1970 and 1973 reduced the block to 8,685 sq km by the time of its Extension, which was granted on 11 January 1991 and effective 31 March 1997. The Extension excluded the unitised Attaka field. By this time Inpex had replaced Japex in the partnership. The Extension was awarded upon a Signature Bonus of USD 15 million and a Work Obligation of USD 63 million covering the period 1 January 1990 to 30 March 1997. Subsequent partial relinquishments have resulted in a final retained area of less than 6,000 sq km. Indonesian government decided to award the block to Pertamina after the expiry of the first PSC extension in 2017. In preparation to the takeover, Pertamina, together with SKK Migas representing Indonesian Government, signed a new contract extension for the Mahakam Offshore PSC on 29 December 2015. The official signing was witnessed by Indonesian Minister of Energy and Mineral Resources. The new contract became effective on 1 January 2018, until 31 December 2037. The signature bonus to be paid by Pertamina was set at USD 41 million, the highest signature bonus ever in Indonesia. Production bonuses will be USD 5 million (for cumulative production of 500 MMboe), USD 4 million (for cumulative production of 750 MMboe) and USD 4 million (for cumulative production of 1,000 MMboe).

Pertamina Hulu Mahakam (PHM), operator of the Mahakam Offshore PSC, reportedly signed a Heads of Agreement (HoA) for the transfer of 10% Participating Interest (PI) to a company owned by the provincial government of East Kalimantan, PT Migas Mandiri Pratama Kutai Mahakam.

SE Bozhong block, Bozhong Depression in Bohai Gulf Basin, WD 20m, target Tertiary clastics, ops terminated late Mar '230, no results, Hai Yang Shi You 932 JU.

Bozhong 29-2-1 (BZ 29-2-1) nfw SE Bozhong block, Bozhong Depression in Bohai Gulf Basin, WD 20m, target Tertiary clastics, ops terminated late Mar '230, no results,

PTTEP Australasia Pty Ltd is looking to divest interest in its Cash/Maple assets, located in the Bonaparte Basin, Ashmore-Cartier.  PTTEP is operator and sole holder of interest in the assets and is looking for a partner to join it in the appraisal and development phases.  PTTEP reports that it is looking for a partner in the project to manage the risk in developing it solo. Cash/Maple is located in AC/RL7 and was discovered in 1990.  PTTEP completed the pre-Front End Engineering and Design (pre-FEED) phase for the proposed development of the Cash-Maple asset during 2018. In 2019 it was reported that the company is now evaluating the optimal development plan for the discoveries. Throughout 2017 and 2018 PTTEP undertook pre-FEED activities for the proposed development of Cash-Maple.  Work was ongoing originally hoped to be completed by the end of 2017.  PTTEP reports that the concept select phase is continuing, with both conventional LNG and floating LNG options being considered.  A concept for development will be determined prior to the project entering FEED. An appraisal programme was undertaken in 2014, with analysis of results ongoing alongside a review of the development options for the discovery.  In 2015 a geological and geophysical review was ongoing, continuing the assessment for development options.  In mid-2014 PTTEP reported that it was reviewing its global portfolio and rearranging assets in order for Cash/Maple to go ahead. Concept selection activities have been ongoing since early 2014.  Originally FEED was scheduled to commence in 2014, followed by a Final Investment Decision (FID). In April 2014 PTTEP reported that FID was hoped to be reached in 2016, with first gas then expected in 2022.  PTTEP has utilised the results from its appraisal drilling at both Cash and Maple, in September 2011 and July 2012 respectively, to assist in the commercialisation option decisions.  The AC/RL7 retention lease covers an area of 420 sq km and was awarded on 27 November 2006.  PTTEP Australasia (Ashmore Cartier) Pty Ltd holds 100% interest and operatorship.

Australia (Northern Gippsland Terrace (Gippsland B.)) Sole

Pan Orient is planning to drill two appraisal wells within the L53 DD field in L53 DD Production Area (PA), onshore Chao Phraya Basin, in August 2019. L53 DD5 and L53 DD6 wells will be drilled from the same well pad as the previous four wells within the L53 DD field. The wells could be targeting to access the extension of BB/CC sand, the main producer in the field. The estimated cost for both wells would be around USD 900,000 for dry hole cases. The last appraisal well, L53 DD3 was drilled in March 2019. In mid-May 2019, the well was tested at an average of 1,854 b/d of oil from the commingled DD/EE, BB/CC and BB sands.  Since December 2018, three appraisal wells have been drilled within the L53 DD PA, immediately after the discovery in L53 DD1. The appraisal wells have contributed to an additional 150% for 2P and 65% for 1P, which has accelerated the approval of Production License in late April 2019. The production in the L53 DD PA has increased 600% since the discovery of L53 DD in December 2018. As of April 2019, the concession holds remaining crude oil reserves of 2.7 MMbbl from the Lower Miocene sandstone reservoir. The L53/48 concession is fully owned and operated by Pan Orient (Siam) Ltd, which is in turn controlled by Pan Orient Energy Corp (50.01%) and Sea Oil Public Company (49.99%). The exploration Area A and B will expire in January 2021, after which the production areas (A, B, D, G and DD) will be retained. Background Information The L53/48 block lies onshore in the Kamphaeng Saen Sub-basin of the Chao Phraya Basin, around 50km WNW of Bangkok. The area is covered by at least 580 sq km of 3D seismic data which were acquired since 2007. Seven minor oil discoveries were encountered within the L53/48 concession from 2009 to 2018. To date, a total of four fields are producing (L53-A, L53-G, L53-D East and L53-DD), one is developing (L53-B) and another two fields are appraising (L53-D and L53-D C-EXT). The oils were structurally trapped in the Lower to Middle Miocene Sandstone Series which was sealed by Middle Miocene Series mudstone. The original 3,997 sq km L53/48 block was awarded to Pan Orient Energy on 8 January 2007 as the operator and sole interest holder, under the 19th Licensing Round. The concession agreement allows Pan Orient to explore for hydrocarbons over a period of six years with a minimum three years first phase commitment of approximately US$ 2.1 million, which includes 3D seismic acquisition and two exploratory wells. In late 2016 and 2017, the operator attempted to find several upside potentials within the Miocene sandstone reservoirs by drilling L53-ANE-A1 and L53 AC C1 in the Reserve Area A. The wells failed to encounter hydrocarbons within the target intervals, which were determined to have excellent quality of sandstones. In November 2018, the L53 DD field was discovered by L53 DD1 wildcat. Oils were trapped in the Lower to Middle Miocene Sandstone Series structural play sealed by Middle Miocene Series mudstone. The daily oil production for L53 DD1 is around 530 barrels, based on the reported cumulative production from 21 November 2018 to 10 February 2019. This discovery was immediately appraised by L53 DD2 well. Both wells have been shut-in after the completion of production test in February 2019, until an approval is granted for L53 DD field Production License by the Department of Energy Fuel (DMF). The approval is anticipated to be granted in April/May 2019.

Thailand (Chao Phraya B.) L53-G

Early Feb ’18, Oranje-Nassau transferred its 24% in A15a block/field to Dyas. The 67-sq km block lies in the N. part of the country’s offshore. Petrogas (op), partners Dana Petr., Dyas + EBN.

Dyas has taken 24% interest in licence A15a from Oranje-Nassau Energie (-> 0%, Petrogas E&P 27% + Op, Dana Petr. 9%, EBN 40%).

On 14 March 2020 the NPD confirmed that DNO and Equinor have completed a deal involving PL 293 B and PL 827 S (effective from 28 February 2020). DNO has increased its interests by 9% in PL 293 B (part of block 35/10 to the southwest of Gnomoria)) and by 19% in PL 827 S (part of block 35/10 to the north of Gnomoria, applicable above Top Cretaceous). A well is due to be drilled on the Gabriel prospect in PL 827 S in April 2020. Gabriel exploration well 35/10-5 is targeting oil in the Paleocene Intra-Balder / Sele Sandstone. TD is planned at 1,968 m and operations are expected to last for around 36 days. PL 293 B contains the 35/10-1 exploration well drilled in 1991 / 1992 by Statoil. The well was drilled to target the Middle Jurassic Brent Group and the Lower Jurassic Cook Formation. Both objectives were found to be water-bearing but there was a 2 m thick sandstone in the Paleocene Lista Formation (between 1,891 and 1,893 m) which contained oil. The Gnomoria well (35/10-4 A - Equinor, 2018) confirmed a section of poor reservoir quality sandstone in the Jurassic Heather Formation totalling 122 m. Oil was proven but no OWC was encountered and estimated recoverable resources are 1.25 – 7.5 MMbo. Following completion of the deal, interest in PL 293 B is held by Equinor Energy AS (51% + operator), DNO Norge AS (29%) and Idemitsu Petroleum Norge AS (20%) and interest in PL 827 S is divided between Equinor Energy AS (51% + operator) and DNO Norge AS (49%).

Norway, PL 827 S

Add. DEA 23 Mar ’19: AE-0056-2M-Mezcalapa-06 block, onshore Sureste Basin, susp. o&g on 20 Mar ’19. Of note the well had been suspended for a while already, results (at the time) and reasons unknown. PTD was 3,955m, target U. Miocene.

Cibix 1EXP op. by Pemex (100%) in AE-0056-2M-Mezcalapa-06 block, suspended as an o&g discovery, target U.Miocene

SW part of AE-0094-Cinturon Plegado Perdido-12 block, GoM Basin, WD 1,317m, P+A results n/a at TD 6,510m in late Dec ’17, Centenario GR SS. Target Wilcox.

Mexico (Plegado-Perdido) Ambus 1EXP op. by Pemex (100%) in AE-0091- Cinturon Subsalino-09 block, P&A with the results n/a.

On 30 July 2019 local news reported - quoting the minister of energy Georgios Lakkotrypis - that the Council of Ministers of Cyprus had approved on 29 July 2019 the licensing of the Block 7 offshore southwestern Cyprus to the consortium of TOTAL E&P Cyprus BV and Eni Cyprus Ltd. The Cypriot government had received the application from the consortium on 26 November 2018. It had opened an exceptional bidding procedure for the block on 3 October due to “very specific geological reasons” related to the Calypso 1 gas discovery made by the consortium of Eni and Total in the adjacent Block 6 in February 2018. Block 7 covers 4,555 sq km to the southwest of the island at water depths between 786 m and 2,703 m. Contract terms in Cyprus provide for an initial three-year exploration period with two two-year renewals. At least a 25% relinquishment of the original license area is mandatory upon each renewal. In case of a discovery, the operator has the right to be awarded an exploitation concession. An exploitation concession is granted for a period of up to 25 years with an option for one renewal of ten years. It is assumed TOTAL E&P Cyprus BV will be the operator with 50% interests in the permit and Eni Cyprus Ltd a partner with the remaining 50%.

Cyprus (Eratosthenes Carbonate Platform) Calypso 1

PL 025, SE of Gudrun in WD ca. 105m, TD 4,014m, was junked and re-spudded at 990m as 15/3-11 on 14 June ‘18, now being abandoned, no further information, Deepsea Bergen SS. Equinor (op), partner Neptune, OMV + Repsol.

015/03-10 & -11 (Sigrun) (Equinor 36%, Neptune Egy 25%, OMV 24%, Repsol 15%) in PL 025, P&A results n/a.

Valeura confirms it has taken over full ownership of the Banarli and 63% in the West Thrace licences (partner Pinnacle) following the recent withdrawal of Equinor (ref. DEA 4 Feb '20). The company re-affirms its commitment to appraise its deep unconventional gas play and intends to LT test the Devepinar discovery once more. It is seeking an additional partner to share in the deep unconventional play.

aleura confirms it has taken over full ownership of the Banarli and 63% in the West Thrace licences (partner Pinnacle) following the recent withdrawal of Equinor (ref. DEA 4 Feb '20). The company re-affirms its commitment to appraise its deep unconventional gas play and intends to LT test the Devepinar discovery once more. It is seeking an additional partner to share in the deep unconventional play.

On 29 January 2018, Karoon with 100% working interest was granted an official award by the ANP for the S-M-1537 block in the offshore Santos Basin from the ANP Round 14.   

Karoon with 100% working interest was granted an official award by the ANP for the S-M-1537 block in the offshore Santos Basin from the ANP Round 14.

Ardent is open to farmin offers for P2300, P2329, P2427 + P2486 in the SNS. 12 leads have been mapped here, total est. 2 Tcfg in Hauptdolomite carbs below 2,100-2,300m. Currently (P2329, P2427 + P2486) Ardent (op, 25%), partners Horizon Egy + Simwell Res. P2300: Ardent (op, 50%), Horizon Egy + Simwell Res. Contact: [email protected].

Ardent is open to farmin offers for P2300, P2329, P2427 + P2486 in the SNS. 12 leads have been mapped here, total est. 2 Tcfg in Hauptdolomite carbs below 2,100-2,300m. Currently (P2329, P2427 + P2486) Ardent (op, 25%), partners Horizon Egy + Simwell Res. P2300: Ardent (op, 50%), Horizon Egy + Simwell Res.

On 17 December 2018, Agiba Petroleum Company (Agiba) abandoned the Banafsag Deep 1 exploration well in the southern part of the Meleiha development lease, onshore Shoushan sub-basin, Western Desert as a dry hole. The well was spudded on 19 November 2018 with the Sino Tharwa’s “ST-5” and was drilled to a TD of 3,673 m in the Jurassic Khatatba Formation. It has the Cenomanian Bahriya Formation as primary target and the Aptian Alam El Bueib as the secondary target. Agiba, a JV between EGPC and IEOC (Eni), operates the Meleiha lease. Partners are IEOC (Eni) with a 76% interest and Lukoil holds the remaining 24%.

Banafsag Deep 1 wildcat (Agiba = EGPC-IEOC-Lukoil 100%) in S. part of Meleiha devt lease, Shoushan sub-basin, P&A dry, Targets Bahriya + Alam El Bueib Fm.

Emperor is seeking to farmout wholly-owned retention lease R3/R1,  80 sq km in the Carnarvon Basin. Equity and terms are negotiable. The lease contains the 2003 Cyrano oil discovery.

Emperor is seeking to farmout wholly-owned retention lease R3/R1, 80 sq km in the Carnarvon Basin. Equity and terms are negotiable. The lease contains the 2003 Cyrano oil discovery.

The authorities have authorised the sale, by Total (op), Wintershall + Eni of their rights to the 886-sq km Octans Pegaso offshore block, to Enap Sipetrol which now becomes sole owner. Octans Pegaso lies in the Austral Basin off the coast of Santa Cruz:

Argentina, Octans-Pegaso

An auction is planned 31 Aug '20 for 20-yr rights to the 175-sq km Budyshchansko-Chutivska block in the Poltava Oblast (E. Ukraine), application deadline on 30 August. Budyshchansko-Chutivska contains 3 small o&g discoveries. Commitments 2D + 3D seismic + 1 well. Starting price USD 3.1 MM. Contact email: [email protected].

An auction is planned 31 Aug '20 for 20-yr rights to the 175-sq km Budyshchansko-Chutivska block in the Poltava Oblast (E. Ukraine), application deadline on 30 August. Budyshchansko-Chutivska contains 3 small o&g discoveries.

Siccar Point has sold its 26% interest in the Shell-operated Jackdaw HPHT field to Dyas effective 22 Dec ‘17. Jackdaw lies in P98 (30/2a [Pre + Post-Tertiary areas]), P111 (30/3a Lower) and P672 (30/2d). Partnership now Shell (op), Dyas 26%.

Siccar Point has sold its 26% interest in the Shell-operated Jackdaw HPHT field (P98 & P111 & P672) to Dyas.

Hitherto-unreported, last August Afro secured sole rights to 272 ER, a 757-sq km block in the Mpumalanga Province, Karoo Basin, 6 years after the application was lodged. Commitments during 3 years include exploration core holes, logs + analysis of core sample gas content (CBM), then testing if warranted.

Afro Energy has awarded a Coal Bed Methane exploration right in 272ER block.

Citic has agreed to sell a 10% interest in the Seram (Non-Bula) PSC Extension, 1,288 sq km onshore Seram Island, to a yet-unnamed 3rd party for USD 3.8 MM cash. The deal is subject to usual approvals. Partnership to be Citic (op), Kufpec, Gulf Petroleum Investment, Lion Energy + new partner.

Citic has agreed to sell a 10% interest in the Seram (Non-Bula) PSC Extension, to a yet-unnamed 3rd party for US$3,8 MM. Kufpec, Gulf Petroleum Investment, Lion Energy + new partner.

On 1 October 2018 ConocoPhillips announced that it had reached an agreement to sell its share in the Greater Sunrise assets to the East Timor Government.  Under the terms of the sale agreement, the East Timor Government will make a payment of USD 350 million, and in return will take on ConocoPhillips’s 30% share in the project. The deal is subject to relevant authority approvals and partner pre-emption options, as well as the government acquiring funding approval.  If these are received the parties expect to complete the deal in Q1 2019. Upon completion of the deal, ConocoPhillips will assign its 30% interest in permits JPDA 03-19, JPDA 03-20, NT/RL2 and NT/RL4 to the East Timor Government.  The JPDA contracts are, at this stage, within the previous-Joint Petroleum Development Area (JPDA) waters.  These will be renegotiated as East Timor PSCs, after the new maritime boundary was outlined in March 2018. These are expected in late 2018/early 2019. The permits contain the Sunrise and Troubadour discoveries, that make up the Greater Sunrise assets.  The discoveries were made in 1975 and 1974 respectively and contain over 5 Tcf gas and 225 MMb condensate. ConocoPhillips reported that it differed in opinion with the East Timor Government over how the Greater Sunrise fields should be developed. It has been long debated, with the Greater Sunrise joint venture (JV) preferring a Floating LNG (FLNG) scenario, over the East Timor Government’s suggestion to pipe the hydrocarbons back to an onshore plant in East Timor.  The JV have indicated this would be more costly, but also difficult as a development due to the bathymetry between the discoveries and East Timor. The deal will have significance, as the East Timor Government has outlined that its preference remains, and with interest in the project it will have a greater input into the development decisions. Upon announcement of the transaction, the East Timor Government reported that it would proceed with further discussions with the JV to evaluate the future development.  Woodside, operator of the assets, has indicated that the project falls under its “Horizon III” planned developments, which are scheduled for post-2027.   The Great Sunrise fields have been under discussion for development for some time, with Woodside initially planning to make a decision in 2009.  However a number of issues, including differing opinions in the development scenario, disputes around the maritime boundary and drop in oil price have pushed the development back a number of times.  Woodside has had several discussions with the East Timor government over the development, looking to come to an agreement. However the maritime boundary dispute put this on hold with Woodside reporting that it would wait for a resolution.   A new maritime boundary was agreed and the initial documents signed in March 2018.  The boundary is expected to be finalized and put in place in late 2018/early 2019.  The new maritime arrangement has included a “Special Regime” for Sunrise, which will see East Timor get at least 70% of the government revenues from the development, with the split to be 70:30 (in favour of East Timor) if the development sees a pipeline to East Timor, and split 80:20 if a pipeline to Australia is utilised.  It is not known if this will alter if the government has a stake in the project. Participants in the Greater Sunrise assets are: Woodside Petroleum Ltd (27.67% + Operator), Shell Australia Ltd (32.33%), OG ZOKA Ltd, a wholly owned subsidiary of Osaka Gas Co Ltd (10%) and ConocoPhillips, selling its share to the East Timor Government, (30%).

Timor Sea JPDA, JPDA 03-20

Siccar Point has sold its 26% interest in the Shell-operated Jackdaw HPHT field to Dyas effective 22 Dec ‘17. Jackdaw lies in P98 (30/2a [Pre + Post-Tertiary areas]), P111 (30/3a Lower) and P672 (30/2d). Partnership now Shell (op), Dyas 26%.

Siccar Point has sold its 26% interest in the Shell-operated Jackdaw HPHT field (P98 & P111 & P672) to Dyas.

Add. DEA 18 Nov '19: W-C part of AE-0007-2M-Amoca-Yaxche-05 block, offshore Sureste Basin, WD 94m, P&A o&g shows at TD 6,989m early Nov '19, West Titania JU. Target Cretaceous + Jurassic.

Mexico, not found

During Q2 2018 CC Energy Development SAL (Oman) successfully drilled and completed the Ulfa 3 appraisal well on Block 3 (Afar) in eastern Oman. The well is the second appraisal well to the Ulfa 1 NFW, which discovered oil in carbonates of the Precambrian Khufai formation. It follows the successful Ulfa 2 well and forms part of a three well appraisal campaign in 2018. Ulfa 3 was drilled around 2.6km SW of Ulfa 1 to appraise the western flank of the structure in order to define the reservoirs extent and oil-water contact. The well confirmed the reservoir extension to the west and also its good qualities. Intermittent testing has given good results and Ulfa 3 has been completed as a producer.<P />The deviated Ulfa 1 well was spudded in December 2016 and reached a final TD of 4,040m in Q1 2017. It tested a previously undrilled structure, located along the Farha South field (Huqf Uplift) trend, targeting sandstones of the Cambro-Ordovician Barik formation as well as carbonates of the Precambrian Lower Buah and Khufai formations. Ulfa 1 is the first carbonate discovery on Block 3, with the nearby Farha South Field producing from Barik sandstones. As such the company believes that the large carbonate section it produces from in the Shahd and Saiwan fields in Block 4, may extend northwards to the fringes of the Farha South Field.<P />In November 2016, JV partner Tethys Oil announced that in accordance with the terms of the Exploration and Production Sharing Agreement (EPSA) for Blocks 3 and 4, the JV partners have agreed new boundaries for Block 3 with the Ministry of Oil and Gas (MOG). The new boundaries exclude a 5,480 sq km area in the north-eastern part of Block 3, which has been returned to the MOG. Following the agreed adjustment, Block 3 now covers an area of 5,918 sq km and the exploration and production term is valid until 2040. CC Energy Development SAL (Oman) operates Block 3 with a 50% interest and is partnered by Tethys Oil Block 3 & 4 Ltd (30%) and Mitsui E&P Middle East BV (20%).

Ulfa 3 appraisal well on Block 3 (Afar) in eastern Oman.The well is the second appraisal well to the Ulfa 1 NFW, which discovered oil in carbonates of the Precambrian Khufai formation. It follows the successful Ulfa 2 well and forms part of a three well appraisal campaign in 2018. Ulfa 3 was drilled around 2.6km SW of Ulfa 1 to appraise the western flank of the structure in order to define the reservoirs extent and oil-water contact. The well confirmed the reservoir extension to the west and also its good qualities. Intermittent testing has given good results and Ulfa 3 has been completed as a producer.

As of June 2020, Trace Atlantic Oil Ltd is believed to be farming out a stake in Block 5B, deep waters of the Senegal (M.S.G.B.C.) Basin. The company is offering between 50 and 70% of its current holding of 65% in the acreage. A 3D seismic survey acquired in 2014 has allowed to define several prospects for future drilling. The Formosa prospect is the most promising according to Trace Atlantic. It is a structure at Albian sands level on the Cretaceous shelf edge play fairway and has similarities with the SNE and FAN discoveries in Senegal. The prospect lies in 1,160 m of water and has a mean recoverable resource estimate between 200 and 1,000 MMb of oil. The 5,696 sq km permit is operated by Trace Atlantic Oil Ltd, with a 65% interest. Partner is Sphere Petroleum with 35%. Interested parties should contact Stellar Energy Advisors at +44 (0) 20 7493 1977 (phone) or [email protected] (email).

Guinea-Bissau (Senegal (M.S.G.B.C.) B.) Block 5B op. by TRACE ATL (65%), CAP ENERGY (30%), SPHERE PT (5%), PETROGUIN (0%), As of June 2020, Trace Atlantic Oil Ltd is believed to be farming out a stake in Block 5B, deep waters of the Senegal (M.S.G.B.C.) Basin. The company is offering between 50 and 70% of its current holding of 65% in the acreage

Zarghun South D&PL, Kirthar Fold Belt, TD 2,022m, tested gas (no details) late Mar '20, co. rig 1. Mari (op), partners Spud Egy, Kufpec, Premier + GHPL.

Zarghun S.-4 appr Zarghun South D&PL, Kirthar Fold Belt, TD 2,022m, tested gas (no details) late Mar '20, co. rig 1. Mari (op), partners Spud Egy, Kufpec, Premier + GHPL.

AE-0019-2M-Okom-02 block, offshore Sureste Basin, P&A dry 26 Jul ’18.  PTD was 3,050m, target Miocene.

Maskaa 1AEXP (Pemex 100%) in AE-0019-2M-Okom-02 block, P&A dry, target Miocene, PTD was 3 050m.

Industry sources reported on 25 September 2018 that Total has agreed to purchase from Chevron all the share capital of Chevron Denmark Inc. The latter holds a 12% interest in the Danish Underground Consortium (DUC) as well as a 12% interest in the 8/06 Area B licence and a 7.5% interest in the Tyra West pipeline. The transaction remains subject to approval of partners and the relevant authorities. Once the deal approved, Total’s participation in DUC will increase from 31.2% to 43.2%, the other partners of the consortium are Shell (36.8%) and the Danish North Sea Fund (20%, owned by the Danish State). Jude 1 was drilled in 2015 in the 8/06 Area B block and is understood to have been an appraisal well for the Bo South discovery made in 2008. The original licence 8/06 was split into area A and area B in March 2013. Area A, which covered the Elly and Luke discoveries, was relinquished in November 2013. As a result of a technical and commercial evaluation of the discoveries Maersk concluded that it could create more value in other projects which have less associated risk (Elly and Luke were HPHT fields with high CO2 content).

Industry sources reported on 25 September 2018 that Total has agreed to purchase from Chevron all the share capital of Chevron Denmark Inc. The latter holds a 12% interest in the Danish Underground Consortium (DUC) as well as a 12% interest in the 8/06 Area B licence and a 7.5% interest in the Tyra West pipeline.

Parta appraisal programme, Iecea Mare prod. lease within E X-10 Parta block, S. Pannonian Basin in W. Romania, under preparation for prod. testing, est. contingent resources 20 Bcfg in the PA IV, PA III + PA V sands. Attempts to deepen below the over-pressured zone at 2,407m were thwarted by HP, fluid losses + wellbore degradation. A deeper basement potential will thus be evaluated at a later stage.

Romania (Banat Sub-basin (Pannonian B.)) Iecea Mare

In October 2019 Suelopetrol had finished drilling the OMI 2 exploration well on the Llanos Basin LLA-61 Block with results not reported. The well was spudded in August 2019 targeting Carbonera sandstones and logging operations were conducted in September 2019. It follows the OMI 1 NFW that discovered oil and was producing some 350 bo/d as of September 2019. Suelopetrol operates the acreage with 100% interest. Background information Suelopetrol acquired 165 km of 3D seismic data over the LLA-61 Block during 2012. After receiving the necessary environmental permits, access road construction commenced for the Llanos Basin drilling campaign.

Colombia (Catatumbo B.) ? op. by WELL LOG (100.0%, WELL LOG 100.0%) in Carbonera block

On 5 June 2019 the NPD confirmed that Equinor has taken 60% of Suncor’s interest in PL 375 and has assumed operatorship of the licence (effective from 29 May 2019). PL 375 covers part of block 34/4 and contains the Beta and Beta Brent discoveries where development studies are ongoing. Suncor confirmed that submission of the PDO has been postponed by two years and is now due in February 2022. Previously, a tie-back to Snorre had been considered but had been deemed uneconomic. In 2000 Saga made the Middle Jurassic Brent Group Delta oil discovery with 34/4-10 R. This has now been re-named Beta Brent. Ten years later Petro-Canada (now Suncor) drilled 34/4-11 to the northeast and encountered oil in the Brent and Statfjord formations in the Beta structure. The find was appraised in early 2011 by 34/4-13 S and oil was tested from the Statfjord Formation at 10,064 b/d through a 28/64” choke. In 2012 Suncor drilled appraisal well 33/6-3 S 9 km southwest of 34/4-11 targeting Beta Statfjord South but although the Lower Jurassic Statfjord Formation objective was encountered it was dry. Its Beta Statfjord North appraisal well 34/4-14 S, drilled in 2015, was also a dry hole. The NPD (December 2018) quotes recoverable volumes of 24 MMbo plus 11 Bcfg in Beta but does not provide a figure for Beta Brent (it considers that production is unlikely). Interest in PL 375 is held by Equinor Energy AS (60% + operator), Suncor Energy Norge AS (20% + operator) and Var Energi AS (20%).

Suncor has assigned 60% + Op from its 80% stake to Equinor (->60% + Op, VÃ¥r Energi 20%, Suncor 20%) in PL 375.

Hurricane may need to P&A its Lincoln Crestal well by 22 Jun '20, the OGA having not (yet) cleared the well's tie-back to the Aoka Mizu FPSO already serving Lancaster. Lincoln Crestal in P1368, Greater Warwick area West of Shetlands, TVD 1,780m, had DST’d up to 9,800 b/d (stable) of 43 API oil on ESP (4,682 b/d unassisted) in Sep '19. Hurricane (op), partner Spirit Egy.

Hurricane may need to P&A its Lincoln Crestal well by 22 Jun '20, the OGA having not (yet) cleared the well's tie-back to the Aoka Mizu FPSO already serving Lancaster.

On 19 August 2019, the UK-based company Savannah Petroleum plc (Savannah) informed that Nigerian authorities approved the transfer of Seven Energy International Ltd (Seven)’s assets, as described two years earlier when Savannah signed a lock-up agreement regarding a USD 140 MM acquisition deal. Savannah is acquiring Seven’s working interests in two marginal fields located southeastern Niger Delta. Savannah will own 40% in Frontier Oil-operated Uquo oil and gas field, as well as 31.875% in Universal Energy Resources (UER) -operated Stubb Creek oil field (Seven had 62.5% in UER so far). Savannah will also acquire a stake in the 260 km Accugas gasline and associated infrastructure. The deal’s finalization is subject to the payment of all taxes due in relation to the transaction within 90 days of the receipt of the official approval letter. Andrew Knott, CEO of Savannah Petroleum plc, commented "The receipt of Consent in relation to the Seven Energy Transaction is a significant milestone for Savannah. I would like to take the opportunity to thank the Federal Government of Nigeria for their support in relation to the Transaction. I look forward to working with all stakeholders as we advance the Seven Assets." Background information On 15 November 2017, the UK-based company Savannah Petroleum plc (Savannah) informed that it has signed a lock-up agreement regarding a USD 140 MM acquisition of Nigerian assets from Seven Energy International Ltd (Seven). Upon finalization of the deal, Savannah will acquire Seven’s working interests in two marginal fields located southeastern Niger Delta. Savannah will own 40% in Frontier Oil-operated Uquo oil and gas field, as well as 31.875% in Universal Energy Resources (UER) -operated Stubb Creek oil field (Seven had 62.5% in UER so far). Savannah will also acquire a stake in the 260 km Accugas gasline and associated infrastructure. The deal is worth USD 87.5 MM cash and USD 52.5 MM shares, implying a possible new share issue. A lock-up agreement is understood to be binding contract prohibiting both parties from selling any shares of stock for a specified period of time. Lock-up periods typically last 180 days but can last for as little as 120 days or as long as 365 days. As of late 2017, Savannah was an E&P company active only in Niger, where it expects to spud the first of three exploration wells as soon as the company shares are back to the trading market (end of lock-up agreement). The well was initially planned to be spudded in August 2017 in the Block R3 (East area).

On 18 August 2019, Savannah Petroleum (Savannah) announced that the Nigerian President Muhammudu Buhari had approved Seven Energy’s asset transfer (Seven’s interests in Seven Uquo Gas Limited, Universal Energy Resources Limited and Accugas Limited).

Shuntuoguole N. block, onshore Tarim Basin, ops terminated at TD 8,450m on 24 Aug ’18, results n/a. Target gas in the Ordovician Penglaiba fm.

Shunbei (Ta) Peng-1 in Shuntuoguole N. block, ops terminated at TD=8 450m, results n/a. Target gas in the Ordovician Penglaiba fm.

P2125, NE part of Clair field West of Shetlands, ops terminated and Paul B Lloyd Jr SS off location 11 Dec ‘17. BP (op), partners Enterprise Oil, ConcoPhillips, Chevron + Britoil.

206/09b-05 (Achmelvich) op by BP (%, Enterprise Oil %, ConcoPhillips %, Chevron %, Britoil %) in P2125, NE part of Clair field, ops terminated, results n/a.

VÃ¥r Energi, jointly owned by Eni + HitecVision, has signed to acquire ExxonMobil's upstream assets in Norway for USD 4.5 bn, only days after the rumour emerged (DEA 6 Sep '19). This involves over 20 producing fields operated mostly by Equinor + Shell, of which Grane, Snorre, Ormen Lange, Statfjord and Fram, accountting for 150,000 boe/d in 2019. The acquisition will be effective 1 Jan '19 subject to usual conditions + approvals. VÃ¥r thus will become the 2nd largest E&P player on the NCS after Equinor and is the latter's largest upstream partner.

VÃ¥r Energi, jointly owned by Eni + HitecVision, has signed to acquire ExxonMobil's upstream assets in Norway for USD 4.5 bn, only days after the rumour emerged (DEA 6 Sep '19). This involves over 20 producing fields operated mostly by Equinor + Shell, of which Grane, Snorre, Ormen Lange, Statfjord and Fram, accountting for 150,000 boe/d in 2019. The acquisition will be effective 1 Jan '19 subject to usual conditions + approvals. VÃ¥r thus will become the 2nd largest E&P player on the NCS after Equinor and is the latter's largest upstream partner.

AC/RL9, offshore Vulcan sub-basin, partner SGH Energy is floating the sale of its 15% stake in the Crux gas field. Development will involve an unmanned platform and 5 production wells, tied back 160km to Prelude FLNG (also operated remotely from there). FEED is currently 50% complete. Shell (op), remaining partner Osaka Gas. Background from GEPS.

AC/RL9, offshore Vulcan sub-basin, partner SGH Energy is floating the sale of its 15% stake in the Crux gas field. Development will involve an unmanned platform and 5 production wells, tied back 160km to Prelude FLNG (also operated remotely from there). FEED is currently 50% complete. Shell (op), remaining partner Osaka Gas

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

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

On 10 April 2018, the ANP published a presentation General Director Oddone made in London with a preliminary map of the “ 2nd ANP Open Door Bid Round” system to commence in 2018, see map below of the sectors and blocks.  The agency plans to publish additional information on the round by 30 April 2018.   On 4 April 2018, the ANP issued a press release indicating its board approved the launch of a “2nd Open Door Bid Round” system in 2018.  The agency has included a total of 1,054 blocks, 969 offshore and 85 onshore, in 20 basins that cover a total area of 441,478.014 sq km.   Offshore there are 969 blocks in 13 basins including Barreirinhas with 31 blocks, Camamu-Almada with nine blocks, Ceara with three blocks, Espirito Santo with 25 blocks, Foz do Amazonas with 237 blocks, Jacuipe with two blocks, Jequitinhonha with three blocks, Para-Maranhao with 52 blocks, Pelotas with 172 blocks, Pernambuco-Paraiba with five blocks, Potiguar with 17 blocks, Santos with 402 blocks, and Sergipe-Alagoas with 11 blocks. Onshore there are 85 blocks in seven basins including Amazonas with 10 blocks, Parana with two blocks, Parecis with 22 blocks, Reconcavo with one block, Sao Francisco with one block, Solimoes with 18 blocks, and Tucano with 31 blocks.   A provisional schedule of events is as follows: By 30 April 2018, the ANP will publish more information regarding the blocks that is assumed to include maps and shapefiles. By late-December 2018, the ANP will publish the rules and regulations for the 2nd Open Door Bid Round system that will include the technical and economic factors and the nominations and bidding procedures.      Summary of Blocks that may be on Offer – 2nd Open Door Bid Round – April 2018 Basin - Offshore Number of Blocks Barreirinhas 31 Camamu-Almada 9 Ceara 3 Espirito Santo 25 Foz do Amazonas 237 Jacuipe 2 Jequitinhonha 3 Para-Maranhao 52 Pelotas 172 Pernambuco-Paraiba 5 Potiguar 17 Santos 402 Sergipe-Alagoas 11 OFFSHORE TOTALS 969 Basin - Onshore Number of Blocks Amazonas 10 Parana 2 Parecis 22 Reconcavo 1 Sao Francisco 1 Solimoes 18 Tucano 31 ONSHORE TOTALS 85 Grand Total 1,054 Source: IHS Markit © 2018 IHS Markit   Preliminary map of Blocks that may be on Offer – 2nd Open Door Bid Round – 10 April 2018

Brazil Agencia Nacional do Petroleo, Gas Nat e Bio (ANP) - to launch 2nd ANP Open Door Bid Round - 1,054 blocks in 20 basins - preliminary map published

Dacian Petroleum has agreed to acquire 40 onshore oil and gas fields from OMV Petrom for an undisclosed consideration. The fields have approximately 1,700 boe/d combined production, or around 1% of of OMV Petrom's daily output. The deal was announced on 8 January 2020 and remains subject to regulatory approvals. This is OMV Petrom's third marginal field divestment in the past three years, following the sale to Carlyle Group-backed Mazarine Energy of 19 fields in August 2017 and a further nine fields in March 2019. Dacian Petroleum was established in November 2018 and is headed by Ion Papa, previously general manager and director at Petrom.

Dacian Petroleum has agreed to acquire 40 onshore oil and gas fields from OMV Petrom for an undisclosed consideration. The fields have approximately 1700 boe/d combined production, or around 1% of of OMV Petrom's daily output.

On 1 February 2020, PEMEX abandoned dry the Baalkah 1EXP New-field wildcat (NFW) in the AE-0155-Chalabil Entitlement Block. The well reached total depth (TD) around 5,800 m. The Baalkah prospect unrisked prospective resources were estimated to be 49 MMboe and the 28% success factor lowers it to 14 MMboe in risked resources. The prospect is located in the south-western area of the block about 1.2 km east of the boundary with the westerly adjoining CNH-R03-L01-AS-CS-06/2018 contract operated by Total with PEMEX as the lone 50% partner. The NFW was spudded on 9 August 2019, and was targeting the Cretaceous and Jurassic at a proposed total depth (PTD) of 6,140 m. The prospect is a sub-salt prospect on a north-west to south-east elongated structure bounded by faults and salt. The operator drilled approximately 400 m salt section in the Oligocene section of the well. The Cantarell II J/U rig drilled the well in a water depth of 27m. The estimated drilling cost was USD 39.6 million at 1USD = 20 MXN and the estimated completion cost was USD 18.65 million. On 4 July 2019, the CNH approved a drilling permit request by PEMEX for the Baalkah 1EXP NFW. SENER awarded the AE-0018-2M-Okom-01 entitlement to Pemex 100% through Ronda 0 on 27 August 2014 but it expired on 27 August 2019 and was replaced by the AE-0155-Chalabil entitlement block on 28 August 2019. The block covers an approximate area of 837.71 sq km. Background Information On 8 February 2019, the CNH approved a modification request to the exploration plan submitted by PEMEX for the AE-0018-2M-Okom-06 entitlement block which includes incremental additional work commitments of drilling two exploration wells and re-processing 370 sq km of 3D seismic. The entitlement already had one well drilled, the Kinbe 1EXP which was junked and abandoned in April 2018.This well was the one firm commitment well approved in its exploration plan when the entitlement was granted a two-year extension on 27 August 2017. The Baalkah 1EXP is the other prospect PEMEX has as a commitment well. The operator also plans the incremental appraisal well the Kinbe 2DEL which will target the Jurassic at a PTD of 6,000 m. This well was previously approved to be drilled by the CNH in November 2018 with the Kinbe evaluation plan. It is expected to spud in late-February 2019. The total budget, encompassing the entire two-year extension period, for drilling three wells and G&G studies is USD 89.45 million at 1USD = 20 MXN.

Mexico (Sureste B.) Baalkah 1EXP op. by PEMEX (100%) in AE-0018-M-Okom-01 block, TD = 5804 m, WD = 27 m, Baalkah 1EXP nfw (Pemex 100%), SW part of AE-0018-2M-Okom-06 block, offshore, WD 27m, TD=5800m late Jan '20. Target Cret. + Jurassic sub-salt. Resutls unreported.

PL 338 near Edvard Grieg, Utsira High, WD 111m, Jorvik TD 2,220m, tested 130 bo/d from a similar reservoir (in communication) to Edvard Grieg, horiz well required for prod. Jorvik sidetracked as 16/1-31 A (Tellus Øst), 60m oil column in basement. Combined 4-37 MMboe ross resources.  Leiv Eiriksson SS.  Progress and well details from GEPS. Lundin (op), partners OMV + Wintershall Dea.

016/01-31S (Jorvik) 31A (Tellus Øst) near Edvard Grieg, appr. (Lundin 65 op, OMV 20%, Wintershall 15%) in PL 338, 31S - tested 130 bo/d from a similar 30m of Triassic conglomerate reservoir with a thin, high quality sst. in communication to Edvard Grieg. Horiz well required for prod. 31A - 60m oil column in porous, weathered basement reservoir.

According to Lebanon's state new agency NNA, Total E&P Liban, the operator of the JV (Total 40%, ENI 40%, Novatek 20%) for Block 4, has completed the drilling of the Byblos well 16/1, offshore Lebanon, to a depth of 4,076 m on April 26 2020. The well is located 30 kms offshore Beirut and was drilled in a water depth of approx. 1,500 meters. The well penetrated the entire Oligo-Miocene target section. The well did evidence traces of gas that confirms the presence of a hydrocarbon system, but it did not encounter any reservoirs of the Tamar formation, which was the target of this exploration well. Based on the data acquired during drilling, studies will be conducted to understand the results and further evaluate the exploration potential of the Total operated JV blocks and for offshore Lebanon. 'We are satisfied to have drilled the first ever exploration well in the Lebanese offshore domain, according to the initial program. We thank the Ministry of Energy and Water and the Lebanese Petroleum Administration for their invaluable support notably to overcome the challenge resulting from the Covid-19 crisis. Despite of the negative result, this well has provided valuable data and learnings that will be integrated into our evaluation of the area,' said Ricardo Darré, Managing Director of Total E&P Liban.Location of Block 4 (Source: Total) See related article: Total and Eni awarded two exploration blocks offshore Lebanon Original article link Source: NNA

Lebanon, Block 4

The Government of South Sudan will launch an oil and gas bid round in 2020. The details of the round will be given in both the Africa Oil & Power and the South Sudan Oil & Power conferences to be held in October this year. According to the Ministry of Petroleum, 10 blocks were on offer and three blocks were under negotiation as of mid-2019: South Sudan Blocks on offer Basin Names Block Name Start Date Block Sqkm Main Political Province Melut Basin~Muglad Basin Block A1 2020 22,258 Ruweng Central African Shield~Muglad Basin Block E1 2020 21,524 Lol Melut Basin Block A2 2020 19,346 Fashoda Melut Basin~Amhara Massif~Tanganyika Shield Block D1 2020 19,266 Kapoeta Amhara Massif~Lotikipi Basin~Tanganyika Shield Block D2 2020 13,061 Akobo Muglad Basin Block A3 2020 11,396 Twic Melut Basin~Amhara Massif Block C2 2020 5,529 Northern Upper Nile Melut Basin~Amhara Massif Block C1 2020 4,733 Northern Upper Nile Muglad Basin Block A5 2020 4,206 Jonglei Muglad Basin Block A6 2020 4,007 Western Lakes IHS Markit 2019   South Sudan Application Blocks   Basin Names Block Name Main Political Province Application Date General Class General Application Type Rights Type Block Sqkm Melut Basin Block B1 Latjoor May 2019 Application Prod Sharing Cont Explorat/Production 43,673 Muglad Basin Block E2 Western Lakes May 2019 Application Prod Sharing Cont Explorat/Production 22,527 Muglad Basin Block A4 Ruweng May 2019 Application Prod Sharing Cont Explorat/Production 2,984  IHS Markit 2019

The Government of South Sudan will launch an oil and gas bid round in 2020. The details of the round will be given in both the Africa Oil & Power and the South Sudan Oil & Power conferences to be held in October this year. According to the Ministry of Petroleum, 10 blocks were on offer and three blocks were under negotiation as of mid-2019:

Cairn has agreed with Solveig Gas Norway to sell the latter its Norwegian arm Capricorn Norge AS for USD 100 MM plus customary working capital adjustments. The split will be effective 1 Jan '20 and concludes Cairn's involvement in Norway - UK North Sea activities are unaffected. The deal is subject to consent by the authorities, partners and 3rd parties.

Cairn has agreed with Solveig Gas to sell the latter its Norwegian subsidiary Capricorn Norge AS for US$100 MM.

JAPEX reported it completed a well operation on 2 August 2019. During drilling, a production test was carried out and it achieved stable gas flow rate, which indicated gas reservoir presence. The data obtained from the well will be analyzed to evaluate further exploration potential in this area. The well reached a TD of 2,530 m below the seabed. JAPEX reported on 16 April 2019 that the company started the exploratory drilling at offshore Hidaka area of Hokkaido on 13 April 2019. The location of the well is approximately 50 kilometers offshore of Hidaka area of Hokkaido with a water depth of 1,070 m, which has been selected based on geophysical survey results obtained through a seismic vessel “SHIGEN” owned by ANRE. it is taken as part of the offshore exploration project commissioned by the Agency for Natural Resources and Energy of the Ministry of Economy, Trade and Industry (ANRE). “Ensco 8504” S/S is used for the drilling operation. This exploratory well, with a PTD of 2,000 m below seabed, is aiming to evaluate the presence of oil and natural gas resources in the area. The well has been decided upon completion of the preparation works including a preliminary seabed survey at the location conducted in October 2018. The operation of exploratory drilling was expected to be completed until late July 2019, and the data obtained through the operations will be later utilized for analysis and evaluation purposes.    Most of Japan’s oil and gas fields are located along the western coastline, about 15 fields are on production in Japan. Major operators are INPEX and Japex. Japan’s major upstream oil and natural gas focus has been involved in locating new domestic reserves in the Niigata, Akita, Yamagata, and Hokkaido regions of Japan, targeting areas near existing oil and natural gas fields. In 2017 Japex announced that it decided to commence oil development of a shallow reservoir named the Takinoue Formation of the Yufutsu Oil and Gas Field in Tomakomai city of Hokkaido aiming commercial production of crude oil. The Takinoue Formation is a discovered but undeveloped reservoir which is shallower than the current oil and gas producing reservoir of the Field. Background Information In 2013, Japex tested oil and gas in Akebono SK-2D-1H, which flowed 1,300 bo/d and 159 Mscfg/d gas at an interval from 1,738 to 1,958m in the Takinoue formation, in the north of Yufutsu field in Hokkaido. Akebono SK-2D-1H, an appraisal well, was drilled in the Yukutsu field. The well was spudded on 22 February 2013 and reached a TD of 2,050m with objective in shallow reservoir in the Takinoue formation. After this shallow reservoir discovery Japex continued evaluation of the oil reserves in the entire shallow reservoir and property analysis of produced oil, and study of appropriate development plan and feasibility of the development. As a result, the company decided to commence development, since it is expected that crude oil reservoir spread out widely in the Takinoue Formation while the quality of oil is heavy. Japex will manage to secure the economic efficiency by reduction of development cost such as modification of existing wells and diversion of idle production facilities of the Yufutsu Oil and Gas Field. Japex commenced development from July 2017, proceeding modification of the existing wells to the production wells and conducting installation work of additional well-head facilities and heavy oil processing facilities in order. Commencement of oil production is anticipated in the second half of 2019 and initial production rate is expected 200 kiloliters per day. Japex also continue the reserves study for the shallow oil reservoir, and pursue the possibility of additional development. Japex has production operations in Hokkaido centered on the Yufutsu oil and gas field, which was discovered in 1989 when Minami Yufutsu SK-1 tested oil and gas. In 1992 Japex drilled Numanohata SK-1D and Akebono SK-1 to assess this discovery and both wells achieved oil and gas flow. With success of those three wells the Yufutsu field is confirmed and the field has been on production since 1996.

Hidaka 1 explo, completed by JAPEX as part of the offshore exploration project commissioned by the Agency for Natural Resources and Energy of the Ministry of Economy, Trade and Industry (ANRE in early July 2019, gas disc. a production test was run on a gas reservoir "where indications of natural gas existence was recognized, and achieved stable gas production. WD=1070 m with PTD= 2000 m below seabed.

GGO has secured rights to licence 2018/40 in Jameson Land, E. Greenland, and an extension was granted to is existing 2015/13 + 2015/14 licences in the same area further south. Drilling is tentatively planned autumn 2020, min. 2 wells/winter season. GGO (op) 93.75%, partner Nuna Oil.

Greenland Gas & Oil (GGO) 93,75% op, Nuna Oil 6,25%) has been awarded a new 2018/40 onshore licence under the government’s open-door licensing process.

On 3 February 2018 Fogelberg appraisal well 6506/9-4 S was spudded by Spirit Energy. The company used the “Island Innovator” S/S to drill the well in PL 433. 6506/9-4 S is located in a down-dip position, approximately 1 km to the west of the discovery well, and was drilled to reduce volume uncertainty and confirm reservoir quality before the licence group commits to a FEED project. The well was drilled to TD at 4,738 m (4,580 m TVDSS) in the Middle / Lower Jurassic Tofte Formation and encountered a 63 m gross hydrocarbon column in the Middle Jurassic Garn Formation. The Middle Jurassic Ile Formation reservoir (70 m of sandstone) had very poor reservoir quality and high water saturation. On 28 April 2018 sidetrack 6506/9-4 A was kicked-off from the 14” casing (its location is where the development wells would be placed). Two cores were cut (around 4,288 m and 4,316 m) and the well reached TD at 4,497 m in the Tofte Formation. A 58 m gross hydrocarbon column was confirmed in the Garn Formation and an 87 m gross hydrocarbon column was present in the Ile Formation. The well was tested and flowed at a maximum constrained rate of 21 MMcfg/d plus 547 bc/d through a 36/64” choke. Preliminary estimated recoverable reserves are 40-90 MMboe – a formal volumetric update will be provided after further interpretation. With this well Fogelberg has been declared commercial and, if development proceeds, it will be as a subsea tie-back to Asgard B (located at the Smorbukk field) with a PDO being submitted in 2019 and a potential onstream date of 2022. On 3 July 2018 the well was being abandoned. The licence term for PL 433 was extended in February 2017 with a deadline to submit a PDO by July 2019. The PDO was originally expected to be submitted in February 2017. Centrica (now Spirit) received MPE approval for the Environmental Impact Assessment (EIA) for Fogelberg in early 2014. The proposed plan (given at that time) included the installation of a four-slot subsea template (with three producers to be drilled initially) tied-back to either Asgard B or Heidrun. Costs were estimated at either NOK 7 billion (USD 1.18 billion) or NOK 11 billion (USD 1.86 billion) depending on which host facility was chosen. The Fogelberg discovery well (6506/9-2 S) was Centrica’s first as an operator on the NCS and was drilled in 2010. Gas and condensate was confirmed in the Garn and Ile formations with no OWC indentified. Reserves at that time were estimated at 23-94 MMboe. The field is HPHT. It lies between Victoria and Smorbukk on the Halten Terrace. Pending completion of a deal in PL 433 interest will be divided between Spirit Energy Norge AS (51.7% + operator), PGNiG Upstream Norway AS (20%), Faroe Petroleum Norge AS (15%) and Dyas Norge AS (13.3%).

6506/09-04S (Fogelberg) appr. pos. by Spirit (51,7% op, PGNiG 20%, Faroe Petr.15% Dyas 13,3%) in PL 433 block, 58m gross hc reservoir in the Garn + 87m in the Ile, testing gauged 21 MMcfg/d stable + 547 bc/d [22/64” choke] for 24 hrs,

W. part of AE-0013-M-Pilar de Akal-Kayab-04 entitlement, offshore Sureste Basin, WD 52m, P&A dry at TD 7,846m (one of country’s deepest) mid-Dec ‘18, West Oberon JU. Target pre-salt below Louann fm.

Mexico, not found

Tethys Oil AB, partners in the onshore Block 04 (Ghunaim) licence in the east of Oman, reported in its first quarter 2018 report that drilling the new field wildcat, Tibyan 1, resulted in a small oil discovery. The well is located approximately 9 km southwest of the Erfan 1 discovery and close to the Shahd field in the Huqf Arch of the Oman Basin. Tethys commented that Tibyan 1 is a small discovery contributing only a modest reserve contribution and as a result, it will be appraised and put on production quickly. It is assumed that the well discovered oil in the Precambrian Khufai (and/or Buah) Formation(s). Erfan 1 (spudded in November 2016), had reached a total depth of 2,548 m in Q1 2017 and flowed oil to surface from the Khufai Formation. In Q2 2017, the discovery was successfully appraised by Erfan 2 which exhibited good oil flows to surface. Both wells were hooked up to the existing blocks’ (03 and 04) production system for long-term testing and appraisal. In March 2013, exploration well B4EW4 1 in Block 04 was completed as a production well and was placed on long-term production test. Early production testing was designed to evaluate the Khufai and Buah reservoirs and Tethys reported a combined flow rate of close to 3,000 b/d of oil on a 36/64” choke. It has been assumed that the field (now Shahd) commenced commercial production early in 2014. Block 04 (Ghunaim) is situated in the east of Oman and the licence covers an area of approximately 23,200 sq km. CC Energy Development S.A.L. (Oman) Ltd operate Block 03 (Afar) and Block 04 with a 50% interest, the remaining interests are held by Tethys Oil (30%) and Mitsui E&P Middle East B.V. (20%).

Oman (Huqf Arch (Oman B.)) Erfan 1

Sources suggest that in June 2018, Sonangol announced to oil companies working in Angola that it would sell part of its interests in almost every offshore block in which it participates. The list of possible farm outs includes blocks that are already in production, blocks where discoveries have been made but are not in production yet and blocks in which discoveries have not yet been made. The following blocks have been listed (See Figure 1): Producing blocks include: Blocks 0, 3/05, 4/05, 14, 15/06, 31 and 32. Blocks where discoveries have been made but are not in production yet include: 16/15, 20, 21, 23 and 24 (Block 24 is understood to have been relinquished by BP, Sonangol’s interest in the block is currently unclear). Block 40 operated by Total, has also been listed. To date no discoveries have been made within the block. According to local sources Sonangol aims to achieve three objectives with the farm down programme: The fist is to reduce its interest to around 20% in each block The second is to generate sufficient cash to allow it to cover arrears cash calls and other operational debt The third is to move the company to a situation in which it has positive cash flow because of its decreased interest and hence reduced level of investment required soon Sonangol may find it difficult to farm down an interest and make a profit in Block 15/06, 31 and 32. The reason being the high exploration and development costs for relatively limited recoverable resources. An example would be Block 32 recoverable resources are in the region of 600 million barrels however, sources suggest the development costs are in the region USD 18.5 billion. In addition, blocks that play host to gas discoveries like Block 24 or have limited recoverable resources like Block 4/05 are also likely to be difficult to farm down. Figure 1: indicates the blocks in which Sonangol has and interest and the listed blocks where it intends to farm out a stake.

Angola Soc Nacional de Petroleos de Angola (Sonangol E.P) announces to oil companies working in Angola that is will sell part of its interests in a number of offshore blocks

Petrosen has issued a call for expressions of interest for the Senegal Offshore Sud and Senegal Offshore Sud Profond blocks (DW MSGBC Basin) in a local newspaper. The Ministry of Petroleum and Energy should be contacted by 31 Oct ‘18 by parties interested, and offers addressed to: Ministère du Pétrole et des Energies, Mr. Thierno Seydou LY, Conseiller Technique n°1 en charge des projets pétroliers et gaziers, 18 Boulevard de la République, Immeuble Bourgi 7e étage, Dakar, Sénégal. Phone  +221 33 889 27 91, email [email protected]. Official map extract below (2 blocks circled). Of note, African Petroleum is under arbitration proceedings at the International Centre for the Settlement of Investment Disputes to resolve a case with the Senegalese authorities over the pending renewal of its rights to Senegal Offshore Sud Profond (SOSP) block.

Senegal Senegal Offshore Sud offers for the Senegal Offshore Sud and Senegal Offshore Sud Profond blocks (DW MSGBC Basin)

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

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

OMV has been declared the winner of a tender for offshore block II, 5,282 sq km on the Black Sea shelf. The April tender was re-scheduled to 22 June on account of CV19, and also featured block III, 3,468 sq km adjacent to the above, for which no outcome has been reported.

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

PEMEX plugged and abandoned dry the Yagual 301EXP deeper-pool wildcat (DPW) in the AE-0051-5M-Mezcalapa-01 entitlement block on 24 November 2018.  The DPW reached a final total depth (TD) of 5,571 m in late November 2018. The DPW was spudded on 19 February 2018. The well had a proposed total depth (PTD) of 6,600 m and the primary targets were the Cretaceous and Jurassic formations.  The well represents a NPW in the Cretaceous and a deeper-pool wildcat (DPW) in the Jurassic.     It will attempt to extend the successful deeper Jurassic plays in the area like Bricol, Chinchorro, Palangre, Pareto, and the most recent discovery Chocol in March 2017.   The Yagual NPW has prospective resources of 46 MMboe.  The prospect is located approximately 2.8 km northwest of the Yagual 1 completed by PEMEX as the discovery well in the Miocene and Cretaceous formations for the Yagual field in 1986.   The Yagual field is located in the A-0372-M-Campo Yagual production entitlement block.  The surface location of the Yagual 301EXP is located in the AE-0052 block but also within the overlying Petrofac Mexico operated CNH-M2-Santuario-El Golpe/2017 PSC contract (CEE).  The CNH-M2-Santuario-El Golpe/2017 PSC contract is depth limited to the Miocene Formation. SENER awarded the AE-0051-5M-Mezcalapa-01 entitlement to Pemex 100% through Ronda 0 on 27 August 2014. The entitlement has been modified five times, the latest was 13 September 2018 whereby the area of the block was increased from 652 to 1,548 sq km.  Previously the well was officially located in the AE-0052-3M-Mezcalapa-02 whose area was reduced and incorporated into the AE-0051 block.

Yagual 301EXP (Pemex 100%) deeper-pool wildcat in the AE-0051-5M-Mezcalapa-01 block, P&A dry. TD=5571m.

Mukhaizna block 53, ops concluded (suspended?) 1Q '20, no results, TMD 4,974m. Oxy (op), partners OOC, IOCL, Liwa Egy, Total + Partex.

Leenah-2 expl Mukhaizna block 53, ops concluded (suspended?) 1Q '20, no results, TMD 4,974m. Oxy (op), partners OOC, IOCL, Liwa Egy, Total + Partex.

PRL 94, NW of Callawonga field in Cooper Eromanga, P&A dry at TD 1,911m on 7 Mar '20. Beach (op), partner Cooper Egy.

Glenelg North 1 (Beach op. 75%, Cooper Energy 25%) in PRL 94, P&A dry.

N. part of block 6 onshore, Fahud Salt sub-basin, ops terminated at TD 1,867m on 23 May, sidetracked the same day and now underway as 3ST, rig 49. Target assumed Infra-Cambrian, Ghudun + Amin formation gas.

Rabiha-3, 3ST appr N. part of block 6 onshore, Fahud Salt sub-basin, ops terminated at TD 1,867m on 23 May, sidetracked the same day and now underway as 3ST, Target assumed Infra-Cambrian, Ghudun + Amin formation gas.

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

Union Jack Oil and Humber O&G have agreed to acquire from Celtique a joint 16,25% in PEDL 201 (Widmerpool Gulf) and 12.5% in PEDL 181 (Humber Basin).