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CaribX (UK) Limited announced on 28 January 2020 it has increased its interest in the Main Cape Block, located in the Mosquitia Basin, from 15% to 55% - subject to governmental approval. A new management team is in place and plans are for an exploration well during 2021-2022. The interest holders are the operator AziLat Petroleum Ltd with 45% and CaribX with the remaining 55%. During 2019, 50% of the 33,950 sq km offshore block was relinquished. As of July 2017, AziLat acquired 80% interest in the Main Cape Block (former Patuca and Mosquitia) from Shell. The block was secured by BG Group in 2013, with the Production Sharing Contract (PSC) approved by the Honduras Congress in May. The last offshore well drilled in Honduras was the Castana 1 (TD 3,812m) drilled by Texaco and abandoned dry in 1980 in the Tela Basin (Caribbean Sea). Earlier, Union Oil's 1973 offshore wildcat Main Cape 1, located in the Mosquitia Basin, had oil shows in the interval 2,711 - 2,817m in Eocene Mosquitia Formation carbonates. The well was not appraised.

CaribX (UK) has increased its interest in the Main Cape Block, from 15% to 55% (AziLat Petroleum Ltd ->45%).

M-08, Moattama Basin, WD ca. 150m, ops terminated mid-Apr '20, results n/a. PTD was 1,100m, target gas in Lower-Middle Miocene Upper Burma lmst, Noble Clyde Boudreaux SS. Normally to be followed by the SR prospect, 40km SE of above. Berlanga (op), partner A-1 Mining.

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).

Nova Petroleo is assumed to have plugged and abandoned dry the 1-NOVA-3 (1-NOVA-001-AL) new-field wildcat (NFW) in the SEAL-T-292 block during mid-February 2020 at an unreported final total depth (TD). The NFW was spudded on 30 January 2020. The NFW had a proposed total depth (PTD) of 550 m and was targeting the Late Jurassic Serraria Formation. The well is a rank NFW located in the west central area of the block with the nearest well located 7.5 km southeast, the 1-MT-2-AL plugged and abandoned dry by Petrobras in 1984. Nova Petroleo is operator of the ANP Round 12, SEAL-T-292 block and holds 50% working interest and Petrobras holds 50% non-operated working interest.

1-NOVA-3 (1-NOVA-001-AL) nfw (Nova Petroleo 50% op. Petrobras 50%) in the SEAL-T-292 block, P&A dry.

Industry sources indicated that Shell Petroleum Dev. Co of Nigeria Ltd (SPDC) made a major gas and condensate discovery with its deeper-pool wildcat Epu 05 in OML 28, originally named Epu Deep 1X. Although the exact discovered reserves are still under evaluation, it is understood that the well reportedly encountered more than 1.5 Tcf of non-associated gas and 40 MMbbl of condensate in 17 reservoir intervals representing a 250 m net pay. Epu 5 was considered high-impact well as SPDC targeted deeper and high-pressure gas horizons in the tract. The well was spudded on 25 February 2018 with the HP/HT “Hilong-27” land rig, it reached a TD around 5,000 m by mid-July, and it was completed during August. The exploration drilling in OML 28 was put on hold since early 2016, when deeper pool wildcats Kaiama Deep 1X and Zarama Deep 1X were planned but put on hold. Epu 5 is the fourth deeper-pool wildcat drilled in the past years by SPDC in OML 28, all targeting high-pressure gas plays (Gbaran Deep West 1X in 2014, Gbaran Deep East 1XST1 in 2015, Kolo Creek 41ST1 in early 2016 and Epu 5 in 2018). There is high potential for a fast track development due to the existing neighboring infrastructure. The onshore license is located in the central Niger Delta and includes a number of oil fields (Kolo Creek, Zarama, Epu and Gbaran) and some gas and condensate fields (Abasare and Koroama). Participants in OML 28 are Shell, operator with 30% interests, Nigerian National Petroleum Co. with 55%, Total E&P Nigeria Ltd with 10% and Nigeria Agip with 5%.

Nigeria (Girardot Sub-basin (Upper Magdalena B.)) Delta

Basin-centered gas accumulation play in block F18-C (deep), W. Thrace Basin / NW Turkey, TD 4,796m, 1,066m gross of Teslimkoy + Kesan fm’s interpreted as gas-bearing down to TD, porosity higher than in Inanli-1 + Yamalik-1, stimulation + testing underway, w.o. 1st results. Valeura (op), partners Equinor + Pinnacle.

Devepinar-1 nfw Basin-centered gas accumulation play in block F18-C (deep), W. Thrace Basin / NW Turkey, TD 4,796m, 1,066m gross of Teslimkoy + Kesan fm’s interpreted as gas-bearing down to TD, porosity higher than in Inanli-1 + Yamalik-1, stimulation + testing underway, w.o. 1st results. Valeura (op), partners Equinor + Pinnacle.

Sidetrack of GS-29 AN in GS-29 5 field area, KG deeper waters, drilled early Feb – late Apr ’18, susp. o&g at TD 3,178m in late Mar ’18, Sagar Vijay DS.

India, not found

East Um El Yusr block (Area A), E. Desert, drilled 12 Sep – early Oct ’18, TD 1,479m, compl. oil. Target L. Miocene Yusr + Rudeis fm’s. KE (op), partner Petrogas.

El Khalig West 1 (Kuwait Energy 70% op, Petrogas 30%) in East Um El Yusr (Area A) block completed as an oil producer from Lower Miocene Yusr Member and Rudeis Fm, TD=1479m.

The authorities have approved a 20% transfer from Shell to Repsol in the 1-14 Han Kubrat block, 6,893 sq km in Black Sea shelf + deepwaters, ahead of explo drilling next month. The deal has yet to be gazetted. Shell (op), parnters Repsol + Woodside.

The authorities have approved a 20% transfer from Shell to Repsol in the 1-14 Han Kubrat block, 6,893 sq km in Black Sea shelf + deepwaters, ahead of explo drilling next month. The deal has yet to be gazetted. Shell (op), parnters Repsol + Woodside.

Ecopetrol has agreed with Chevron to acquire half of the latter's 42.86% in Mississippi Canyon block 726 containing the recent Esox discovery (DEA 30 Oct '19). Partnership to become Hess (op) 57.14%, Chevron 21.43%, Ecopetrol 21.43%.

Ecopetrol has inked an agreement with supermajor Chevron (->21,43%, Hess 57,14% op.) to acquire a 21,43% stake in the Esox-1 well (yielded oil discovery last week ) in G24101 lease (MC Block 726).

The ratification by the Greek parliament of the contract signed by Energean Oil & Gas for to the Aitoloakarnania block located onshore Western Greece was published in the official gazette on 15 March 2017, which formalizes the award of the tract. The exploration terms will be for seven years divided into three exploration phases (3+2+2). Commitments include the acquisition of 400 km of new 2D seismic as well as various G&G studies during the first phase for a minimum expenditure of EUR 7.23 million. One exploratory well is required for both the second and third phases (minimum expenditure EUR 10 million each). It is recalled that in March 2017 the company reached into an agreement with Repsol for the farm-out of a 60% stake and operatorship in the Ioannina and Aitoloakarnania blocks. Energean was selected as preferred bidder for the Aitoloakarnania block on 4 February 2016. The block was part of the “Call for Tenders for the exploration and exploitation of hydrocarbons Onshore Western Greece”, which was launched in 2014. The contract was signed on 25 May 2017 and ratified by Greek parliament on 28 February 2018. In the past, some 400 km of 2D seismic were recorded and eight wells were drilled in the area covered by the 4,360-sq km block. Pending approval, interest share in the Aitoloakarnania exploration permit will be shared between Repsol Exploracion Ioannina SA (60% -operator) and Energean Oil & Gas SA (40%).

Greece, Ioannina

Ouro Preto is assumed to have plugged and abandoned dry the 1-OPEO-JATOBA-PI (1-OPEO-001-PI) new-field wildcat (NFW) in the PN-T-137 contract block during mid-September 2018.  No show reports have been filed for the well through early-October 2018.  The final total depth (TD) has not been reported. The NFW was spudded on 2 August 2018. The well had a proposed total depth (PTD) of 2,190m.  The Devonian Cabecas Formation and the Mississippian Poti Formation were the primary targets.  The NFW is located in the west central area of the block and is a rank NFW.  The nearest well is located off the northern block boundary 28 km to the north-east and is the 1-FL-1-PI plugged with gas shows by Petrobras in 1963 at a total depth (TD) of 2,405 m.   Ouro Preto has 100% working interest in the contract.

Brazil, PN-T-137

Federal energy company, Ieasa (former Enarsa), in mid November 2018 was still planning to divest its 50% stake on the 56 sq km Aguada del Chanar block in the Neuquen Basin. Even though Neuquen provincial company Gas y Petroleo del Neuquen operates the block with 50% interest, the exploration and development project on the block has been funded by Enarsa since 2007. The main idea for Ieasa is to reach investors for unconventional Vaca Muerta exploration. The original Aguada del Chanar was split in three blocks in 2013. The western area was awarded to GyP Neuquen and named Aguada Federal. Afterward GyP signed a JV agreement with German company, Wintershall which has been conducting a Vaca Muerta shale drilling pilot plan with success. The eastern block Aguada Canepa was awarded to Pan American Energy (90%) and GyP (10%). In 2013 oil and some minor gas was tested from the Vaca Muerta Formation in the Bosque del Chanar 3 appraisal well in the northern corner of the block. Enarsa invested a total of US$ 140 million for the development of the remaining Aguada del Chanar license but according to its current president, Hugo Balboa, results were not satisfactory. Ieasa is negotiating with GyP Neuquen for the return of 50% of these funds as the contract requires. The license could be included in a bidding process in the near future. It was announced recently that Enarsa is required to dismantle its oil and gas branch of the company. Enarsa was created by the previous Kirchner government in 2004 and is involved in gas and fuel imports, domestic hydrocarbon transportation and other projects as well as various corruption scandals.

Argentina, Aguada del Chanar

Ref. DEA 25 May ’18, commitment well in Area 1 (Amoca-Miztón-Tecoalli A & B) PSC, offshore Sureste Basin, WD 26m, P&A non-comm. o&g on 1 Jun ’18, West Castor JU. PTD was 4,500m, target Cinco Presidentes fm.

Mexico (Salina Sub-basin (Sureste B.)) Cinco Presidentes

A list of explo licences available for investors without auction was published 10 Sep ’18. Eight blocks totalling 19,301 sq km in E&W Siberia and Volga-Urals are open until 19 Oct ’18. Any block attracting more than one valid offer will be withdrawn from the list and could be auctioned:

A list of explo licences available for investors without auction was published 10 Sep ’18. Eight blocks totalling 19,301 sq km in E&W Siberia and Volga-Urals are open until 19 Oct ’18. Any block attracting more than one valid offer will be withdrawn from the list and could be auctioned:

The NPD confirmed on 10 January 2020 that Idemitsu has farmed-in to PL 882, taking 10% interests from both Concedo (on 20 December 2019) and Petrolia (on 31 December 2019). PL 882 covers a 188 sq km area over parts of blocks 33/6 and 34/4 to the northwest of Snorre. A well will be drilled by operator Neptune on the Dugong prospect in mid-2020. Dugong exploration well 34/4-15 S will be drilled using the “Deepsea Yantai” S/S. The well’s objectives are the Upper Jurassic Intra-Draupne Formation and the Middle Jurassic Brent Group. TD is planned at 3,740 m (3,647 m TVD). If a potential sidetrack is drilled (TD 3,790 m / 3,565 m TVD) operations could last for up to 97 days. The PDO for Equinor’s Snorre Expansion Project (Snorre 2040) was approved in July 2018. The project aims to increase the field’s recovery rate from 46% to 51% by producing a further 195 MMbo and extending field life beyond 2040. At a total estimated cost of NOK 19.3 billion (USD 2.31 billion) the development includes six subsea templates each with four wells. Of the 24 new wells half will be producers and the other half will be used for alternating water and gas injection. The templates will be tied back to Snorre A where upgrades will take place (to receive production and provide injection gas and water). First oil is expected in Q1 2021. PL 882 is operated by Neptune Energy Norge AS with 40%. Concedo ASA, Idemitsu Petroleum Norge AS and Petrolia NOCO AS are partners, holding 20% each.

Petrolia NOCO (->20%, Neptune 40% op.) and Concedo (->20%) each transferred 10% equity in PL 882 to Idemitsu Petroleum.

On 16 March 2018, local media reported that BP is looking to sell its assets in the Gulf of Suez. The assets, which are producing about 70,000 bo/d and 400 MMscf/d of gas, are operated by Gulf of Suez Oil Company (Gupco), a joint venture between the Egyptian General Petroleum Corporation (EGPC) and BP. BP assets in Gulf of Suez include: South Ghara (Torsina), South Belayim (Ekma), Merged “Gupco”, South Gharib (Rodoco), East Morgan, LL 87 1&2, North October (Nopco), East Morgan, West Morgan and East Shukeir (Esma).

BP is looking to sell its assets in the Gulf of Suez. The assets, which are producing about 70,000 bo/d and 400 MMscf/d of gas, are operated by Gulf of Suez Oil Company (Gupco), a joint venture between the Egyptian General Petroleum Corporation (EGPC) and BP. BP assets in Gulf of Suez include: South Ghara (Torsina), South Belayim (Ekma), Merged “Gupco”, South Gharib (Rodoco), East Morgan, LL 87 1&2, North October (Nopco), East Morgan, West Morgan and East Shukeir (Esma).

On 3 April 2018 Lundin spudded an appraisal well at Rolvsnes in PL 338 C. 16/1-28 S is located in the northern part of the field, approximately 1 km north of discovery well 16/1-12. The company used the “COSL Innovator” S/S to drill the well to a TD of 4,880 m (1,918 m TVD) in granitic basement rock. The well encountered 2,500 m of granitic basement rock in the horizontal section with poor reservoir quality. A well test was performed for 10 days flowing approximately 7,000 bo/d through a 52/64” choke. During the five day main flow period production was held at a rate of approximately 4,200 bo/d. The test results indicate that the reservoir has good productivity supported by aquifer pressure. The oil is undersaturated with a GOR of 620 scf/bbl. Following the results, the resource range at Rolvsnes has been revised upwards to between 14 and 78 MMboe from the previous estimate of between 3 and 16 MMboe. Rolvsnes is considered a potential tie-back candidate to Edvard Grieg. On 23 September the well was suspended. The 2009 discovery well proved a 40 m oil column in fractured Basement and results from three mini DSTs showed that the reservoir has good flow characteristics, although it is complex. Lundin reported that this discovery was unlikely to be connected to the main Edvard Grieg field to the north as the OWC is about 15 m higher. In 2015 appraisal well 16/1-25 S was drilled approximately 2.4 km south of the discovery well. It proved a gross oil column of 30 m in porous granitic Basement with pressure data and oil type confirming communication with 16/1-12, and a similar OWC at 1,927 m subsea. A DST flowed oil at a rate of 265 b/d through a 36/64” choke. According to Rolvsnes partner Lime Petroleum’s parent company Rex International, Lundin is considering a phased appraisal and development programme for the field. It could drill up to four producers plus a water injector, each well being dependant on the results of the previous well. Rolvsnes (also known as Edvard Grieg South) contains estimated 2P recoverable reserves of 31 MMbo plus 32 Bcfg (from a CPR by Gaffney, Cline and Associates for Rex International published in February 2018). Rex International also has an interest in PL 815 to the southeast where it maps the Goddo prospect as a possible geological continuation of Rolvsnes. Interest in PL 338 C is held by Lundin Norway AS (50% + operator), Lime Petroleum AS (30%) and OMV (Norge) AS (20%).

016/01-28S (Rolvsnes) (Lundin 50% op, Lime 30%, OMV 20%) pos. appr. in PL 338 C, DST gauged up to a constrained 7 000 bo/d [52/64” choke] from a fractured + weathered basement (2 500m horiz section penetrated, poor reservoir quality), 5-day main flow period held at 4 200 b/d, GOR 110 cum/cum, gross resource range increased to 14-78 Mmboe from 3-16 MMboe.

As of June 2019 Trace Atlantic Oil Ltd is 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. 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).

As of June 2019 Trace Atlantic Oil Ltd is 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.

Commitment well (2nd) in North Madura II PSC, offshore East Java, TD 2,160m, DST’ing since late Dec ‘17, target Ngimbang clastics + Kujung carbs. Tasha JU.

Taubah-1(East Java B.) Taubah 1 op. by PETRONAS (100.0%) in North Madura II block, DST’ing, target Ngimbang clastics + Kujung carbs.

The authorities announce the opening of an 18-onshore block offer, application deadline 15 Apr '20 with the DGPC. Bid docs can be obtained from www.ppisonline.com. The available blocks have been identified as follows (locations are as usual defined in the block name, e.g. '3069-9' = N 30, E 69, 9th block in area): - 3068-6 (Killa Saifullah) - 2762-2 (Desert) - 3067-7 (Sharan) - 3269-2 (Miran) - 3372-25 (Abbottabad) - 3471-1 (Nowshera) - 3372-26 (Hazro) - 3273-5 (Jhelum) - 3372-27 (North Dhumal) - 3272-16 (Lilla) - 3068-10 (block 28-N) - 3170-11 (D.I. Khan West) - 3069-9 (Suleiman) - 3072-9 (Okara) - 3171-2 (Nurpur) - 2972-7 (Vehari) - 2972-8 (Sutlej) - 2770-4 (Islamgarh).

The authorities announce the opening of an 18-onshore block offer, application deadline 15 Apr '20 with the DGPC. Bid docs can be obtained from www.ppisonline.com. The available blocks have been identified as follows (locations are as usual defined in the block name, e.g. '3069-9' = N 30, E 69, 9th block in area): - 3068-6 (Killa Saifullah) - 2762-2 (Desert) - 3067-7 (Sharan) - 3269-2 (Miran) - 3372-25 (Abbottabad) - 3471-1 (Nowshera) - 3372-26 (Hazro) - 3273-5 (Jhelum) - 3372-27 (North Dhumal) - 3272-16 (Lilla) - 3068-10 (block 28-N) - 3170-11 (D.I. Khan West) - 3069-9 (Suleiman) - 3072-9 (Okara) - 3171-2 (Nurpur) - 2972-7 (Vehari) - 2972-8 (Sutlej) - 2770-4 (Islamgarh).

On 16 October 2019, the Federal Agency for Subsoil Use announced an auction for four blocks in Udmurtia Republic (Volga-Ural Province). The auction will be held on 11 December 2019. Applications should be submitted by 14 November. Each participant must make a refundable deposit equal to the starting price for the block. The deposit will be non-refundable if the winner fails to pay its winning bid. Additional information regarding the auction may be requested from: Udmurtnedra Izhevsk Ukhtomskogo Str., 24 Details of the offer are as follows: The Khmelevskoy block covers 15 sq km and encompasses a part of the Khmelevskoye field with 3P reserves estimated at 12.9 MMbbl of oil. Oil reserves are distributed within five reservoirs of the Visean-Moscovian sedimentary section. The starting price amounts to RUB 543.3 million (USD 8.36 million). The winner of the auction will obtain a 20-year E&P license. The Pyzepskiy Yuzhnyy block covers 61.7 sq km and encompasses the Pyzherskoye Yuzhnoye field with 3P reserves estimated at 4.7 MMbbl of oil. Oil resources (category D1) of the block are estimated at 2 MMbbl. The starting price amounts to RUB 107.4 million (USD 1.65 million). The winner of the auction will obtain a 25-year E&P license. The Kacheshurskiy block covers 115 sq km and encompasses the Kacheshurskaya and Menilskaya Severnaya prospects with combined oil resources estimated at 3.6 MMbbl. Oil resources (category D1) of the block are estimated at 5 MMbbl. The starting price amounts to RUB 8.7 million (USD 0.13 million). The winner of the auction will obtain a 25-year E&P license. The Kamskiy Zapadnyy block covers 57.4 sq km. Oil resources (category D1) of the block are estimated at 4 MMbbl. The starting price amounts to RUB 0.9 million (USD 0.01 million). The winner of the auction will obtain a 25-year E&P license.

On 16 October 2019, the Federal Agency for Subsoil Use announced an auction for four blocks in Udmurtia Republic (Volga-Ural Province). The auction will be held on 11 December 2019.

Mississippi Canyon block 882 (lease G35989), deviated into MC 881, E. of Eni's Morpeth-Klamath field in WD 681m, ops terminated and Sevan Louisiana SS released.

United States (Deep Water Gulf of Mexico B.) Mississippi Canyon 881 001S0B0 op. by OXY (75%), OPUBCO (16%), HI PRO (9%) in MC 881 block, TD = 3105.6 m, WD = 598.6 m deviated into MC 881, E. of Eni's Morpeth-Klamath field in WD=681m, ops terminated, no further details are available.

The Ministry of Petroleum of Chad is offering 24 open blocks on an open-door policy. As of August 2017, the open blocks were:  Basin Name Block Name Block Sqkm Al Kufra Basin Djado Block II 13,771 Al Kufra Basin Erdis I 32,979 Al Kufra Basin Erdis II 15,614 Al Kufra Basin Largeau Block I 11,706 Chad Basin Largeau Block II 11,739 Chad Basin Largeau Block III bis 11,302 Chad Basin Largeau Block IV bis 18,901 Chad Basin Largeau Block VI 11,706 Chad Basin Largeau Block VII 11,815 Chad Basin LC-2008 11,977 Chad Basin Manga Block 16,907 Chad Basin Moussoro Block 11,927 Chad Basin Chad Basin Lac Chad Block Lac Chad Block I 11,900 3,782 Chad Basin Siltou Block I 13,300 Chad Basin Siltou Block II 17,800 Chad Basin, Bongor Trough MD-2008 11,760 Djado Basin Djado Block I 20,493 Doba Trough WD 1-2008 1,988 Doba Trough~Bongor Trough Chari-Ouest Block III 4,651 Doseo Trough BDS-2008 41,875 Erdis Basin Erdis 36,830 Erdis Basin Erdis-2008 37,150 Erdis Basin Erdis Block V 14,150 Source: IHS Markit   © 2017 IHS Markit   The Al Kufra Basin is better known as Erdis Basin in Chad. The south extension in Niger and Chad of the Murzuq Basin is called Djado Basin (or Jadu Basin) and has seen no hydrocarbon exploration in the past. The Faya-Largeau area is poorly explored, with only few low-quality seismic lines acquired in the 1980s. The Lake Chad area was one of the first regions to be explored in Chad, but unlike the Doba Trough, it has not been intensively explored. Three discoveries have been made: Kanem-1 in 1974, Sedigi in 1975 and Kumia-1 in 1976. The latest version of the Hydrocarbon Laws in Chad was translated into English in August 2008. On 27 August 2007, Prime Minister M. Nouradine Delwa Kassiré Comakye announced that the Republic of Chad had promulgated legal texts and implemented mechanisms relating to the specific management of its oil incomes in order to adhere to the EITI. The Government solemnly declared that the principles of this initiative from that moment on would be applied to Chad and the incomes drawn from the extractive industries would be declared and used in a total transparency.

Chad, Sedigi (Dev)

OMV spudded exploration well 6506/11-10 on the HPHT Hades and Iris prospects in PL 644 B using the “Deepsea Bergen” S/S on 28 November 2017. The well was drilled to TD at 4,536 m in the Lower Jurassic Ror Formation and has confirmed gas condensate discoveries in both prospects. The Hades reservoir is the Lower Cretaceous Lange Formation at 3,932 m. A 35 m gas condensate column was proven with 15 m of net sandstone. No GWC was found. Estimated recoverable reserves range from 19 to 113 MMboe. The Iris reservoir was confirmed at 4,223 m. The Middle Jurassic Garn Formation contains a 95 m gas condensate column with 85 m of net sandstone. The GWC lies at 4,295 m subsea and recoverable reserves are estimated at 19-132 MMboe. Pressure data has shown that the two hydrocarbon columns are not in communication. It is likely that the finds will be appraised in due course. On 18 April 2018 the well is still being abandoned. PL 644 B consists of a 28 sq km area over the northern part of block 6506/11, immediately north of Morvin, and was awarded in APA 2015. The adjacent PL 644 covers parts of the surrounding blocks 6506/8, 6506/10 and 6506/11. Morvin was discovered in 2001 by 6506/11-7 and the PDO was approved on 25 April 2008. The field came onstream in August 2010 using two subsea templates tied-back to Asgard B. The field's reservoir is also HPHT. PL 644 B is operated by OMV (Norge) AS (30%). OMV is partnered by Statoil Petroleum AS (30%), Faroe Petroleum Norge AS (20%) and Spirit Energy Norge AS (20%).

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

On 9 October 2017 Union Jack Oil plc announced that it has acquired the entire onshore portfolio of Cairn subsidiary Nautical Petroleum Limited. Under the terms of the agreement Union Jack acquired 10% interest in PEDL 005(R) which contains the producing Keddington oil field in which it already had a 10% interest. It has acquired 10% interest in PEDL 339 containing the Louth prospect which has estimated Stock Tank Oil Initially in Place (STOIIP) of 5.5 MMbbl. It has taken a 16.67% interest in PEDL 203 which contains the Kirklington 3Z well which will be ready to produce if a decision for production is made and following some remediation work. And lastly it has acquired a 16.67% interest in PEDL 118 containing the decommissioned Dukes Wood field is located and where there is believed to be further unproduced resources. The acquisition has been valued at GBP 25,000 and Union Jack has assumed further financial costs for the acquired assets. Union Jack will receive production proceeds from Keddington from 1 September 2017. It is understood the deal completed in December 2017. The Keddington field is located along the east-west structural high on the southern margin of the Humber Basin known as the East Barkwith Ridge. The Saltfleetby field is also located along the ridge along with the Biscathorpe prospect. Recent 3D mapping over the Keddington field has indicated some remaining oil potential within structural closure. Keddington was discovered in 1998 by Morrison Middlefield Resources Ltd subsidiary Candecca Resources Ltd. Following completion of the deal interest in the Keddington field in PEDL 005(R) is held by Egdon Resources U.K. Limited (45% + operator), Terrain Energy Limited (35%) and Union Jack Oil plc (20%). Interest in PEDL 339 is held by Egdon Resources U.K. Limited (65% + operator), Union Jack Oil plc (20%) and Terrain Energy Limited (15%). Interest in PEDL 203 and PEDL 118 is held by Egdon Resources U.K. Limited (55.5% + operator), Terrain Energy Limited (27.78%) and Union Jack Oil plc (16.67%).

UJO announces the acquisition of Nautical Petroleum’s interests onshore UK, namely 4 Egdon-operated blocks in the E. Midlands. Involved are 10% in PEDL 005 (Keddington field), 10% in PEDL 339 (Louth prospect), 16,67% in PEDL 203 (Kirklington shut-in field), and 16,67% in PEDL 118 (Dukes Wood shut-in field).

Oil and Gas Development Company Ltd (OGDCL) reported in November 2016 that it has been looking to form joint ventures by farming-out interests in 39 operated blocks in the country including 38 exploration blocks and one development lease. The interested companies can acquire working interest on non-operated or operated basis. These are all onshore blocks among these, 19 are located in Balochistan province, 10 blocks in Punjab province, five are located in Khyber Pakhtunkhwa and five blocks in Sindh province. In addition to farming-in to OGDCL’s licences, E&P companies can acquire new licences as joint venture partner with OGDCL. As of end of March 2018, the blocks were still open for farm-in opportunities. Interested companies can contact directly to OGDCL’s Mr Masood Nabi (Executive Director – JV/BD) at [email protected] telephone: + 92 51 9200 23521 or Dr. M Saeed Khan Jadoon (Executive Director – Exploration) at [email protected] telephone +92 51 9200 23582. OGDCL is a major national oil company in Pakistan operating 61 exploration licenses covering an area of 118,309 sq km, which is largest exploration acreage by any company in the country. OGDCL also hold equity in 100 development and production leases, including 68 operated leases. It has the largest portfolio of hydrocarbon balance recoverable reserves in the country with 2P estimates of 195 MMbo and 3,950 Bcf of gas. Below is the list of exploration blocks offered for form-out which includes 37 onshore and one on/offshore block. OGDCL is also looking for a partner in Sara West D&PL. It has invited proposals for the development of Sara West field to process produced gas, making it pipeline quality or saleable which could be used for power generation. Contract Name Area       (sq km) Onshore / Offshore Basin Names Main Political Province Alipur 2970-6 EL 2,425 Onshore Indus Punjab Armala 2469-9 EL 2,489 Onshore Indus Sindh Baratai 3371-17 EL 39 Onshore Potwar Khyber Pakhtunkhwa Bela North 2566-5 EL 2,046 Onshore Porali Trough Balochistan Bostan 3066-5 EL 2,338 Onshore Bela-Muslimbagh Balochistan Fateh Jang 3372-14 EL 1,071 Onshore Potwar Punjab Fatehpur 3071-4 EL 2,431 Onshore Indus Punjab Gurgalot 3371-5 EL 341 Onshore Potwar Khyber Pakhtunkhwa Gwadar 2561-1 EL 2,407 Onshore Makran Coastal Trough Balochistan Hetu 3170-7 EL 2,432 Onshore Indus Basin~Punjab Shelf Punjab Jandran West 2969-9 756 Onshore Sulaiman Foldbelt Balochistan Khanpur 2870-7 EL 2,495 Onshore Indus Punjab Kharan-3 2865-3 2,487 Onshore Balochistan Balochistan Khiu 3171-3 EL 2,396 Onshore Indus Basin~Punjab Shelf Punjab Khuzdar North 2866-3 EL 2,451 Onshore Kirthar Fold Belt Balochistan Kulachi 3170-8 EL 2,472 Onshore Indus Punjab Ladhana 2970-7 EL 2,409 Onshore Indus Punjab Lakhi Rud 3068-4 EL 2,485 Onshore Sulaiman Foldbelt Balochistan Layyah 3070-17 EL 2,459 Onshore Indus Punjab Mari East 2769-16 EL 1,398 Onshore Indus Sindh Orakzai 3369-1 EL 1,708 Onshore Campbellpore~Pishin-Katawaz Khyber Pakhtunkhwa Palantak 2764-3 EL 2,457 Onshore Makran-Balochistan Flysch Belt Balochistan Parkini Block-A 2564-2 EL 1,892 Onshore Makran Coastal Trough Balochistan Parkini Block-B 2564-3 EL 1,908 Onshore Makran Coastal Trough Balochistan Pasni West 2562-1 EL 2,293 On/Offshore Makran Coastal Trough Arabian Sea Rakhshan 2764-2 EL 2,459 Onshore Balochistan Balochistan Ranipur 2768-11 EL 2,380 Onshore Indus Sindh Rasmalan 2564-4 EL 1,464 Onshore Makran Coastal Trough Balochistan Rasmalan West 2564-5 EL 1,640 Onshore Makran Coastal Trough Balochistan Samandar 2565-1 EL 2,496 Onshore Makran Coastal Trough Balochistan Saruna 2567-4 EL 2,432 Onshore Kirthar Foldbelt Balochistan Shaan 3069-4 EL 2,471 Onshore Sulaiman Foldbelt  Balochistan Shahana 2763-2 EL 2,448  Onshore Makran-Balochistan Flysch Belt Balochistan Tegani 2769-14 EL 270 Onshore Indus Sindh Tirah 3370-14 EL 1,946 Onshore Bela-Muslimbagh-Zhob Ophiolite Belt Khyber Pakhtunkhwa Warnali 3273-4 EL 719 Onshore Potwar Basin~Punjab Shelf Punjab Zhob 3169-2 EL 2,473 Onshore Sulaiman Fold Belt Khyber Pakhtunkhwa Zorgarh 2868-7 EL 2,402 Onshore Indus Basin~Sulaiman Fold Belt Punjab    OGDCL is also interested in forming joint ventures with E&P companies having experience in unconventional hydrocarbons resources, especially in the exploitation of shale gas and tight gas. Likewise, the company is also looking for partners with experience in Enhanced Oil Recovery (EOR) in mature fields and development of low-BTU fields. It was earlier reported in May 2015 that OGDCL was looking to farm-out interests in 29 operated blocks in the country on swap basis under which the interested companies, in addition to acquiring equity in OGDCL operated blocks, will offer interests to OGDCL in their exploration blocks outside Pakistan. It is understood that such opportunities were mainly available for national oil companies.

Oil and Gas Development Company Ltd (OGDCL) reported in November 2016 that it has been looking to form joint ventures by farming-out interests in 39 operated blocks in the country including 38 exploration blocks and one development lease.

NE part of CNH-R02-L04-AP-CS-G01/2018 contract, Area 20, AP-CS-G01 block, Campeche Deep Sea Basin, WD 2,760m, tested and non-commercial, assumed P&A'd, Deepwater Thalassa DS off to Max-1 early May '20 (DEA 5 May '0). PTMD was 6,731m (6,345m TVD), targets Oligocene + Oxfordian. Shell (op), partner Chevron.

Mexico (Campeche Deep Sea B.) Chibu 1EXP op. by SHELL (60%), CVX (40%) in Area 20 block, WD = 2760 m

AE-0150-Uchukil, Area A block, offshore Sureste Basin, TD 2,140m assumed reached, ops concluded late Jun '20, Campeche JU. Target oil in L. Pliocene.

Mexico (Sureste B.), Paki-1 EXP, op. by PEMEX (100%) in AE-0150-Uchukil, Area A block, offshore Sureste Basin, TD 2,140m assumed reached, ops concluded late Jun '20, Campeche JU. Target oil in L. Pliocene.

The Omani Ministry of Oil and Gas (MOG) is seeking qualified international companies to unlock the challenging hydrocarbon potential of Block 43B (Dhahirah) and Block 71 (Habhab). At the OPAL Oil & Gas Conference in Muscat, Dr Saleh Al Anboori, Director-General of Planning and Studies at the Ministry of Oil and Gas (MOG), stated that the two blocks are open for investment based on one-to-one negotiations. <P />Block 43B (11,967 sq km) is located along the coastal area of northern Oman, north of the Hajar Mountains. It was offered in the country's 2017 bid round, but seems to have not received any bids. The acreage is largely unexplored, with only two wells having been drilled. So far there are no discoveries, however gas shows were encountered in the Barak 1 NFW, which was drilled by Amoco in 1985. The last well, Hawasina 1, was drilled by MOL in 2013. It was P&A as a dry well after reaching a TD of 4,382m. Conventional gas is the main play type across the block with Eocene and Paleocene Formations providing the most significant potential targets. Several prospects have been mapped within the Eocene Seeb Formation, along the coastal portion of the block. Block 71 (282 sq km) is located in central Oman, around 90km west of Duqm. The block has only recently been created, after Petroleum Development Oman (PDO) relinquished the area from its Block 6 concession. It contains the Habhab oil field, which was originally discovered in 1982 and reservoirs approximately 1Bbo (STOIIP P50) of heavy oil/bitumen (10-14deg API) in thinly-laminated Cambrian sandstones of the Miqrat formation. Enhanced oil recovery will be required to produce the Habhab oil. It is understood that in recent years PDO has progressed steam and chemical injection pilots to try and unlock the potential of the field, with encouraging results. In 2017, PDO was looking for partners, to help with the development and implementation of hydrocarbon production practices aimed at achieving the maximum economic recovery of Habhab oil.

Not Found

Guddu 2869-6 EL, Middle Indus onshore in Sindh, TD 790m (Eocene), late Feb ’18 gas discovery, tested 2.47 MMcf/d on 1/2” choke, co. SK-750 rig. OGDCL (op), partners Spud Energy, IPR TransOil + Govt Holdings.

Pakistan (Indus B.) Umair X-1 op. by OGDCL (70.0%, SPUD EN 13.5%, IPR 11.5%, GHPL 5.0%) in Guddu 2869-6 EL block

Mapache block, Llanos Basin, TD 2,618m on 19 May ‘19, tested 430 b/d of 15 API oil from the Ubaque fm during June.

Castana 1 (Frontera 100%) in Mapache Block, completed in the Ubaque Fm objective, tested at 430 bo/d of 15° API gravity oil.

Equinor announced on 18 October 2018 that it has agreed to sell its non-operated interests in PL 044 to PGNiG. The licence contains the Tommeliten Gamma and Tommeliten Alpha discoveries. Equinor holds a 30% interest in PL 044 and a 42.38% interest in the Tommeliten Unit (PL 044 TA). The agreed purchase price is USD 220 million. Equinor stated that the sale is due to its focus on the Norwegian Continental Shelf and to prioritise projects that create higher value for the company. PGNiG, the Polish National Oil Company announced that the acquisition has significant importance as it looks to diversify its gas imports, currently it’s heavily dependent on Russia. Through the acquisition it will allow PGNiG to export gas from Tommeliten Alpha to Poland via Denmark through the planned Baltic Pipe pipeline. The deal is subject to regulatory approval with an effective date of 1 January 2018. Tommeliten Alpha was discovered by Det norske in February 1977 by New-field wildcat 1/9-1. The first 2D seismic survey in block 1/9 was carried out in 1974 which consisted of a 1x1 km grid oriented northwest-southeast. The survey revealed the presence of four structures at the top of the "Chalk" Group: Alpha, Beta, Delta and Gamma. Seismic anomalies caused by gas were seen in the crestal areas and in the Tertiary section above Alpha, Delta and Gamma. Salt diapirs were interpreted below these three structures. Well 1/9-1 was drilled near the crest of the dome and encountered 100 m (330 ft) of porous and hydrocarbon-bearing chalk. In 2015, operator ConocoPhillips shelved it’s USD 2.24 billion development of Tommeliten Alpha due to low oil prices. Tommeliten Alpha would be developed using a similar subsea production system to Tommeliten Gamma and tied back to either the Ekofisk field facilities or the Valhall platform. However, additional reserves were required to justify a development. A final field investment decision was expected in early 2016 with aim to bring the field onstream in Q4 2019. Tommeliten Gamma, located 10 km to the north and was developed using a six-well subsea tieback to the Edda platform. From Edda the hydrocarbons were piped to the Ekofisk centre. Gas was then sent to Emden in Germany and liquids transported to Teesside in England. The field was abandoned in 1998 after almost 10 years of production. In July 2000, it was reported that the six gas production wells had been plug and the christmas trees removed. Following completion of the deal interest in PL 044 will be divided between ConocoPhillips Skandinavia AS (41.88% + operator), PGNiG Upstream Norway AS (30%), Total E&P Norge AS (15%) and Eni Norge AS (13.12%). Interest in the Tommeliten Unit, PL 044 TA will be split by ConocoPhillips Skandinavia AS (28.26% + operator), PGNiG Upstream Norway AS (42.38%), Total E&P Norge AS (20.23%) and Eni Norge AS (9.13%).

Norway (Girardot Sub-basin (Upper Magdalena B.)) Delta

Spirit is to take over operatorship of the Babbage field + Cobra discovery in P456 / block 48/2a, an agreement to this intent being reached with existing partners. The deal is pending completion of the transfer of Premier’s 47% in Babbage and 50% in Cobra to Verus Petroleum (DEA 30 Apr ’18). Dana is the other partner in Babbage. An explo well is planned 2Q ’19 in the Python prospect near Babbage.

Spirit is to take over operatorship of the Babbage field + Cobra discovery in P456 / block 48/2a, an agreement to this intent being reached with existing partners. The deal is pending completion of the transfer of Premier’s 47% in Babbage and 50% in Cobra to Verus Petroleum (DEA 30 Apr ’18). Dana is the other partner in Babbage. An explo well is planned 2Q ’19 in the Python prospect near Babbage.

Octant is looking to dilute its 100% in block L17/L17, 4,794 sq km mainly offshore in the Lamu Basin off S. Kenya, a data room open believed in London. Octant is otherwise engaged in Kenyan block 1 and in Tanzania.

Octant is looking to dilute its 100% in block L17/L17, 4,794 sq km mainly offshore in the Lamu Basin off S. Kenya, a data room open believed in London. Octant is otherwise engaged in Kenyan block 1 and in Tanzania.

PL 832, NW of Ormen Lange field in Norwegian Sea, WD 1,235m, TD 3,642m reached, results later this week, Scarabeo 8 SS. Shell (op), partners Petoro, Spirit Energy + DEA.

Norway (Ras-More Sub-basin (More B.)) Ormen Lange

PEMEX plugged and abandoned dry the Betan 1EXP new-field wildcat (NFW) in the AE-0051-5M-Mezcalapa-01 entitlement during late-January 2019.  The final total depth (TD) was 2,580 m.   The NFW was spudded on 19 November 2018. The well had a proposed total depth (PTD) of 2,666 m and the primary target was the Miocene.         The NFW had estimated prospective resources of 25 MMboe.   The prospect is located in the north central area of the block. SENER awarded the AE-0051-5M-Mezcalapa-01 entitlement to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 974.04 sq km.  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.

Betan 1EXP (NFW) in the AE-0051-5M-Mezcalapa-01 entitlement, P&A dry

Europa Oil and Gas is actively farming out interest in Frontier Exploration Licence (FEL) 1/17, FEL 2/13 and FEL 3/13 which are estimated to hold gross mean un-risked resources of 4.3 Bboe. In April 2019, Europa announced negotiations were still ongoing regarding the farm-in agreements with a major oil and gas company concerning licences LO 16/20, FEL 1/17 & FEL 3/13. Europa are expecting to be fully carried on a well on each licence and retain material interest in each licence with the final investment decision pending in the major’s head office. To ensure wells are drilled at the earliest opportunity site surveys for wells at Inishkea, Kiely East and Edgeworth are under application subject to regulatory approval and planned to commence in Summer 2019. Europa plan to drill all three prospects from 2020 onwards subject to funding and regulatory approval. Europa stated that potential farminees are still active in its virtual and physical data rooms. Europa has interpreted nine prospects in FEL 1/17, 2/13 and 3/13 through the results of reprocessed PSDM 3D seismic data, originally acquired in 2013. FEL 1/17 contains one syn-rift and two pre-rift prospects, Egerton (167 MMboe), Ervine (192 MMboe) and Edgeworth (225 MMboe) respectively. FEL 2/13 contains two pre-rift prospects Kiely East (280 MMboe) and Keily West (225 MMboe) with one Cretaceous prospect named Kilroy (312 MMboe). Europa announced it has increased its resource estimates in FEL 3/13 from 1.5 to 2.9 Bboe in June 2018. The updated prospect inventory contains Beckett (1719 MMboe), Shaw (747 MMboe) and Wilde (462 MMboe). Beckett and Shaw were previously described as “single cycle events” but are now interpreted as a fan sequence comprising of multiple fan cycles (250 – 325 m gross). Interest in FEL1/17, FEL 2/13 and FEL 3/13 is held by Europa Oil and Gas (Holdings) plc 100%. For further information regarding the Farm-out opportunity please contact: Murray Johnson Email: [email protected]

Europa Oil and Gas is actively farming out interest in Frontier Exploration Licence (FEL) 1/17, FEL 2/13 and FEL 3/13 which are estimated to hold gross mean un-risked resources of 4.3 Bboe.

Alaska North Slope operators placed USD 11,268,709 in high bids on 92 tracts covering 1,051,216 ac (4,254 sq km) at the National Petroleum Reserve in Alaska (NPR-A) sale held by the Bureau of Land Management (BLM) on 11 December 2019. The sale offered 350 tracts covering 3,987,689 ac (16,138 sq km). The revenue from the 2019 sale was nearly USD 10 million more than the 2018 sale when only 16 tracts were bid on. The most active company was North Slope Exploration LLC which picked up 85 tracts for a total of USD 10,762,243 in high bids.  This included the highest bid of the sale, USD 448,899 for tract 2019-D6 covering 14,397 ac (58 sq km). Emerald House was the high bidder on four tracts, and ConococPhillips successfully bid on three tracts. While the latter two companies picked up acreage along the edges of currently-leased tracts, North Slope Exploration's focus was to the west of this area. A map of the lease sale tract results is available at: https://www.blm.gov/sites/blm.gov/files/uploads/OilandGas_Alaska_2019_NPR-A_SaleResultsMap_12112019.pdf

United States, not found

Ecuador's Ministry on Non-Renewable Natural Resources plans to launch six onshore blocks, located in the Napo Basin, during the Intracampos II Bid Round. However, an official schedule has been delayed due to the COVID-19 pandemic, which has delayed the ministry's community outreach – that was planned for May-June 2020.The areas have production and facilities, and information on wells and seismic. One block has unconventional potential, Block 11, the largest block on offer – which is located next to the Bermejo field. Below the areas that will be offered: Block Area -sq km Prospects 11 - Lumbaqui 1,674.94 5 93 - Saywa 1,335.20 3 94 - Tamya 99.57 4 95 - Tetete Sur 30.96 1 96 - VHR Oeste 89.13 3 97 - VHR Este 91.38 2   For more information regarding the ronda, please contact Ing. David Alban, [email protected], 593-3976-000, ext. # 1907 The plan was to launch the licensing round in July 2020, as reported in mid-May 2020. The licensing round was first announced during the XII Ronda Petrolera Intracampos Ecuador presentation in Houston on 25 September 2018.The official announcement was expected in November and then it was moved to December 2019. It appears that the delay is due to change in the ministry. Background Information During a conference in late May 2019, Ecuador’s Adviser to the Minister at Ministry of Energy and Non-Renewable Natural Resources Jose Antonio Cepeda announced that the Intracampos II Bid Round will be in 2019 – most likely end of the year. The government planned to announce the round after the closing of the XII Ronda Petrolera Intracampos Ecuador, as previously reported in late December 2018. Local news reported in late July 2018 that Ecuador’s Secretaria de Hidrocaburos plans to announce in late 2018 - 1Q 2019 the Intracampos II Bid Round, which may include 14 fields, with estimated reserves of 157.4 MMbo. The fields are part of Petroamazonas’ portfolio and will be returned to the government. Expected investment for the areas is USD 1.2 billion. The government plans to offer a new contract for the awarded areas in this round - the Participation Contract, Production Sharing Agreement. The Decree 449 was presented to the Legislative for review on 18 July 2019, in order to change the current Service Contract to Participation Contract and attract more investment. Ecuador’s Secretaria de Hidrocarburos released an estimated schedule for the Intracampos Bid Round, which is expected to be officially announced in late July 2018. The entry fee is USD 100,000 per company, which will have three months for an evaluation and presentation of offers. In September 2018, the government plans to award the contracts and offer the Participation Contract. Reserve certification will be handled by a third-party company for the eight blocks,15 fields: Araza Este, Charapa, Chanangue, Espejo, Iguana, Panayacu Norte, Perico and Sahino. The total projected investment expected for the 930 sq km area, has been reviewed and it is now USD 756 to USD 1,159 million, and not USD 903 million, nor USD 1.25 billion as previously announced. The estimated peak production at 14-19 bo/d, is expected around 2024.

(Napo B.) Ecuador's Ministry on Non-Renewable Natural Resources plans to launch six onshore blocks, located in the Napo Basin, during the Intracampos II Bid Round.

Rampart Deep discovery area, NW part of Mississippi Canyon block 72, OCS lease G08483, WD 574m, cleared to plug back (result n/a) + bypass 4 Apr ’18, target supra-salt Middle Miocene, Ensco 8505 SS.

Mississippi Canyon 72 3S0B0 (Derbio), OCS lease G08483, WD 574m, cleared to plug back (result n/a)

OMV New Zealand Ltd, a wholly owned subsidiary of OMV AG, spudded the Toutouwai 1 exploration well in PEP 60093, located in the Taranaki Basin, on 8 March 2020. The well was drilled to a total depth of 4,317.3 m by the COSL Drilling Europe AS owned "COSL Prospector" rig which was released from the well location on 13 April 2020. The Petroleum Exploration and Production Association of New Zealand (PEPANZ) reported on 14 April 2020 that preliminary results indicate the well successfully encountered oil and gas. The implications of coronavirus disease 2019 (COVID-19) and restrictions imposed by New Zealand's transition to "Alert Level 4" have limited the testing phase, with the well subsequently plugged and abandoned following positive indications from multiple intervals. With reference to Toutouwai 1, John Carnegie, PEPANZ CE, stated "the potential benefits to Taranaki and all New Zealand are substantial" and that the find could "help New Zealand's long-term energy security" Toutouwai 1 is the first discovery to be made in New Zealand since 2014 and had pre-drill estimated recoverable resources of 90 MMboe. The well was drilled in a water depth of 131 m and had a target depth of 4,361 m, with the last casing point at 1,520 m. Targets included the Cretaceous North Cape Formation and Paleogene sandstones. The contingent well was the third of a multi-well exploration campaign being undertaken by OMV in the Taranaki and Great South basins. The "COSL Prospector" rig was contracted to undertake the campaign and arrived at the Toutouwai location in early March 2020 after drilling the unsuccessful Tawhaki 1 well in the Great South Basin. The Maui 8 new-pool wildcat (PML 381012, Taranaki Basin) was due to follow Toutouwai 1 in Q2 2020, however the implications of coronavirus disease 2019 (COVID-19) mean the programme is now indefinitely suspended. On 3 March 2020, climate activists boarded the COSL Prospector rig as it was moving to the Toutouwai 1 location. It is not clear if this resulted in a delay to the spud date. PEP 60093 covers an area of 2,137 sq km was awarded on 16 December 2015. Interests in the permit are OMV New Zealand Ltd (40% plus operatorship), SapuraOMV Upstream (NZ) Sdn Bhd Ltd (30%) and Mitsui E&P Australia Pty Ltd (30%).

Toutouwai 1 nfw. (OMV 40% op, Mitsui E&P 30%, Sapura Energy 30%) in PEP 60093, offshore block, several hydrocarbon-charged layers encountered while drilling in Cretaceous sst, well now assumed P&A but considered a discovery,preliminary results indicate the well successfully encountered oil and gas. Target North Cape fm + Paleogene sst. WD=131m, TD=4317m.

SK-408 off Central Luconia, Sarawak, ops terminated ~20 Jan ’18, Deepwater Nautilus SS off to drill Timi-1 in SK-318. Target assumed Middle Miocene Cycle IV / V carbs. Shell (well op), partners Sapura (blk op) + Petronas.

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

Add. DEA 6 Apr '20 (adds well content): 2nd of 2 wells planned in SK-408 off Central Luconia, Sarawak, P&A sub-commercial gas find on 2 Apr '20, PV Drilling VI JU. Target Middle Miocene Cycle IV/V carbs. SapuraOMV (op), partners Shell + Petronas.

Malaysia (Central Luconia Province) Remayong 1 op. by SHELL (30%), PETRONAS (30%), OMV (20%), SAPURA EN (20%) in SK-408 West (expl) block, water depth 100 m 2nd of 2 wells planned in SK-408 off Central Luconia, Sarawak, P&A sub-commercial gas find on 2 Apr '20. Target Middle Miocene Cycle IV/V carbs.

In early July 2020, Divine Inspiration Group (DigOil) – partner of Efora Energy in the local company Semliki Energy - confirmed being seeking a new partner for its Block III. Local sources suggested that Total may consider entering the licence, but this was not confirmed by the latter. The company plans to drill two exploration wells (potentially three) in the northern part of the licence. The licence is located in the Nord-Kivu province, eastern Democratic Republic of Congo (DRC), East African Rift System. Block III is crossed by the Semliki River and lies between Lake Albert and Lake Edward adjacent to Ugandan border. In May 2019, the company had received a fist validity extension for its licence. As a result, the exploration phase was set to expire in January 2020. On 22 November 2019, a second validity extension was granted and the licence is now valid until July 2020. Interest in the licence is held by Semliki Energy SPRL (85% + operator) and the State (15%).

Democratic Republic of Congo (East African Rift System, Western Branch), Block III, Divine Inspiration Group (DigOil) – partner of Efora Energy in the local company Semliki Energy - confirmed being seeking a new partner for its Block III. Interest in the licence is held by Semliki Energy SPRL (85% + operator) and the State (15%).

Odin is offering a negotiable interest in its 32-sq km 2018/1 offshore block, home to the E17 shallow-water oil prospect. Contact Tom Haselton, [email protected]. Partnership now Odin (op), Nostrum O&G + Geobaltic.

Odin is offering a negotiable interest in its 32-sq km 2018/1 offshore block, home to the E17 shallow-water oil prospect. Contact Tom Haselton, [email protected]. Partnership now Odin (op), Nostrum O&G + Geobaltic.

Subsequent to a portfolio review, Heritage Oil Ltd no longer sees Papua New Guinea as a core growth region. The company is looking to exit the country by divesting its entire PNG portfolio which includes exploration assets in the Western Forelands and the Southern Highlands (PPL 437 & PPL 486), and a gas field (Kuru, PRL 13). Heritage entered PNG in 2013 by acquiring operated interest in PPL 319 from Esrey Resources for around USD 4 million. The permit was later renewed in 2014 as PPL 486, which is still operated by Heritage. PPL 486 covers an area of 2,130 sq km in the Fly Platform, between the recently appraised, Oil Search operated, Barikewa gas field in the Papuan Fold Belt and the Total’s operated Elk-Antelope field in a carbonate platform, Fly Platform. The committed work programme was amended in October 2015 to move required 2D seismic acquisition from years 1&2, to years 3&4. However, after 11 lines were shot by Telemu (an Esrey subsidiary) in 2011, no known further ground works have taken place. The remaining programme includes three exploration wells by June 2020. Given the commitment from Heritage to exit the country, it is unlikely that the work programme will be altered again. Heritage reports two prospects and six leads within the permit area. The Tuyuwopi Prospect is considered ‘drill-ready’ by Heritage in a four-way dip closed drape structure which is thought to be on a direct migration pathway from a Jurassic source kitchen. Tuyowopi was the likely target for the first well to be funded by Heritage in the original farm-in agreement and site clearance work had commenced. It has the potential for gas within the Imburu, Iagifu and Koi Iange units, with Heritage reporting that it could contain 2P prospective recoverable resources of 600 Bcf in a gas case or 125 MMbo and 375 Bcfg in an oil and gas case. Both the Kutubu oil export pipeline and the PNG LNG natural gas pipeline run through the acreage which could aid in bringing resources to market in the case of a discovery with third-party pipeline access. Retention Lease PRL 13 is located directly east of PPL 486 and covers the Kuru gas discovery. Containing an estimated 30 – 50 Bcf gas, commercializing the field would benefit from aggregated resources of new finds. Discovered in 1956 after ground seepage was observed, Kuru 1 well blew out after penetrating around 12 m of the Puri Limestone. Kuru 2 was later drilled to test deeper targets including Miocene sandstones and the Darai Limestone. PRL 13 was set to expire on 15 June 2017. It is not thought that Esrey Resources applied for a licence renewal before exiting PNG. Pending confirmation, the licence could be inactive, meaning Kuru would no longer be under licence. Exploration licence PPL 437 is located immediately north of the Elevala and Ketu fields in Horizon’s operated PRL 21. It contains the drill ready Malisa Prospect, along with Ebony, Mango and Ketu North prospects. Partner and operator Kina Petroleum is also looking to farm-down interest in the licence which is currently under application for an extension. Malisa has the potential for gas within the Kimu and Elevala/Toro formations, with Heritage reporting that it could contain 2P prospective recoverable resources of 280 Bcf gas. The licence lies in close proximity to the Elevala, Ketu, Stanley, P’nyang and Juha discoveries, meaning opportunities for development could run through proposed Western LNG infrastructure or through third party access to the considered P’nyang to Kutubu pipeline. A total 170 km of 2D seismic was acquired over Malisa in 2014 during the Gosur Survey. Interpretation of this data was reported to be nearly complete in 2H 2017, along with integrated aerogravity data. Initial results showed significant prospectivity in the east of the permit. In addition, vintage seismic data was reprocessed within the licence and pending full interpretation. Under the work commitments, the option existed to either drill one well or complete an additional phase of seismic in place of the well, if the identification of a suitable drilling target had not been successful. Drilling targets could potentially be identified through interpretation of reprocessed vintage 2D seismic data. A seismic programme was expected in 2018 which did not materialize but could be included in the permit extension application programme. Heritage farmed into PPL 437 in 2013 with the condition that Kina would be free-carried through the first seismic programme. Additional interest could have been earned by Heritage (up to 50%) if the option to drill an exploration well was taken, in which Kina would also have been free carried. PPL 437, which covers an area of 1,537 sq km, was awarded on 19 February 2013. Heritage Oil is looking to divest its entire 42.5% interest. Operator Kina Petroleum is also looking to farm down its 57.5% interest. Companies interested in pursuing this opportunity should contact: Krey Stirland – Heritage Oil, Vice President Business Development Email: [email protected]

Heritage Oil Plc is looking to divest its entire PNG portfolio

On 11 September 2018, Gazprom Neft reported that the State Commission for Reserves (GKZ) approved the revision of reserves for the Neptune discovery offshore Sakhalin. After integration of seismic data and drilling results, Gazprom Neft generated a new geological model of the discovery increasing its 3P reserves up to 3.035 Bbbl in-place and 911 MMbbl of recoverable. Background Information On 4 October 2017, Gazprom Neft reported an oil discovery in the Ayashskiy license offshore Sakhalin. Wildcat Ayashskaya 1, spudded in mid-June 2017, was drilled to 2,700 m by contractor Japan Drilling Co using semi-submersible Hakuryu-5. It is understood that oil flows were tested from four reservoirs in the Nutovo Formation (Miocene) at a depth range of 2,000-2,700 m. The operator estimated 3P reserves of the Ayashskoye discovery at 500-580 MMbbl of oil. The new discovery is located some 55 km from the Sakhalin coast. A water depth in the drilling location is 62 m. In mid-October, it was decided to re-name the discovery to Neptune due to some difficulties with pronunciation of the original name for non-Russian speakers. Also, Gazprom Neft announced its plan to drill a wildcat at the Bautinskiy prospect in 2018 at the same license.   The Ayashskiy block covers 4,294 sq km east of Sakhalin and encompasses several structures. Gazprom obtained a long-term license (a part of the Sakhalin-3 project) in 2009 and, by 2016, completed several seismic surveys in the area including acquisition of 2,150 sq km of 3D data. In January 2017, the rights were transferred to Gazpromneft-Sakhalin (license ShOM16292NR). It may indicate that, based on analysis of new acquired data, the area was considered as mainly oil-prone and it is more convenient for Gazprom Neft, Gazprom’s oil branch, to continue the exploration. According to Gazprom, hydrocarbon resources of the Ayashskiy prospect were estimated at 4.9 Tcf of gas and 1,022 MMbbl of oil and condensate.

Gazprom Neft reported that the GKZ approved the revision of reserves for the Neptune discovery. After integration of seismic data and drilling results, Gazprom Neft generated a new geological model of the discovery increasing its 3P reserves up to 3 035 Bboe in-place and 911 MMboe of recoverable.

PetroChina made a breakthrough in deep shale gas exploration drilling in the Sichuan Basin. Zu 201-H1, a horizontal well with a TD over 6,000 m, tested 3.7 MMcf/d of gas from the Longmaxi Formation in early November 2017, which is the deepest shale gas well so far completed in the Sichuan Basin with commercial gas flow.  PetroChina completed Zu 201-H1 well drilling in the Sichuan Basin in March 2017. Zu 201H-1, kicking off from Zu 201, reached a TD of 6,038 m. The well was started on 20 August 2016.  PetroChina completed Zu 201, a vertical shale gas exploration well, in the Sichuan Basin in October 2015. Zu 201 was located in Dazu-Rongchang block with target in the Longmaxi Formation and the well reached a TD of 4,412 m. Earlier in 2017 PetroChina achieved commercial gas flow in a shale gas well in this area. Zu 202 tested 1.7 MMcf/d of gas from the Longmaxi Formation. The well has a TD of 3,980 m. PetroChina is partnership with Sinochem and Chongqing Municipal local energy company in the Dazu-Rongchang block.

China, not found

Chevron and Petrobras disclosed on 4 February 2020 that both companies want to sell their 100% stake in the Papa Terra Field in the deepwater Campos Basin. Both companies want to cut costs by selling assets. Papa Terra came online in 2013 and now produces oil and gas through two offshore platforms. Petrobras has 62.5% of the field with Chevron holding the remaining 37.5%. The heavy oil, between 14 and 17 degrees API gravity, and the deep water of Papa Terra Field make it one of the more technically challenging projects in Brazil.Petrobras in 2015 took major asset write downs for several producing fields. Leading the way was Papa-Terra Field with losses of US$ 2.4 billion. The devaluation was based on dropping oil prices but also seismic data reprocessing. On 16 March 2016 after exactly one year of operations on the P-61 platform in Papa Terra Field, Petrobras has had disappointing results. The Tension Leg Wellhead Platform (TLWP), P-61, is the first of its kind to be deployed in Brazil but was producing just 2,500 bo/d from only one of the 13 wells planned to be hooked up in the initial plan of the ultra-heavy oil field. Papa Terra also produced from three other wells connected to the FPSO P-63 for a total production of 16,000 bo/d. The P-61 platform is installed in a water depth of 1,200m. Papa Terra, according to previous projections was planned to reach peak production in 2015 of 115,000 bo/d and 28 MMcfg/d

Chevron and Petrobras disclosed on 4 February 2020 that both companies want to sell their 100% stake in the Papa Terra Field in the deepwater Campos Basin.

KMG has withdrawn from the EX IV-5 Satu Mare licence in the Hajdusag sub-basin, its 40% transferred to Serinus who ends sole holder of the 2,949-sq km block in NW Romania. Serinus presumably continues to offer the permit for farmout.

Romania, not found

IGas subsidiary Island Gas Limited and Egdon Resources have acquired a 3.67% interest and 1.33% interest respectively in licence PEDL 070 from Brigantes Energy. The licence contains one block – SU/52a which hosts the Avington field. The deal completed in early May 2018. The Avington field is a composite structure comprising a northern footwall fault block and a southern hanging wall inversion anticline, covering 23 sq km. The Middle Jurassic Great Oolite reservoir is mapped juxtaposed across the fault separating the two structural elements of the field. The field was discovered in 1987 and was brought onstream in 2009. The field is expected to produce until 2022. Interest in the licence is now held by IGas subsidiary Island Gas Limited (53.67% + operator), Egdon Resources U.K. Limited (28%), Aurora Production (U.K.) Limited (8.33%), Corfe Energy Limited (5%) and UKOG (GB) Limited (5%).

United Kingdom, PEDL 070

Armour Energy Ltd is looking to farm-down its 100% owned exploration licences across the McArthur, Georgina, and Carpentaria (Isa Super Basin) basins. Armour operates six licences under the jurisdiction of the Northern Territory: EP 171, 174, 176, 190-192, and one in Queensland: ATP 1087-P which are all available for farm-in. There are also 12 applications in place which were lodged between 2009 and 2014, covering nearly 80,000 sq km. Armour is the preferred tenderer for the Queensland applications and Native Title negotiations are ongoing. Armour is seeking a partner to assist in additional seismic acquisition and drill a combination of exploration wells and appraisal/pilot wells to push the needle on 22 Tcf of prospective shale gas resources. A data room is available to review the shale gas plays and shallower, conventional plays which have been identified by Armour. The main farm-out focus for Armour is ATP 1087-P which covers an area of 7,100 sq km. The permit was awarded in 2012 and is currently due to expire on 31 December 2018. Armour reports that a four year extension has been granted but, as of early-February 2018, the grant is yet to be registered with Queensland Resource Authority. In 2015, work commitment changes were approved for the remainder of the term in response to the recognition of positive results achieved within the permit relating to production at the Egilabria field. Instead of drilling the proposed 22 exploration wells during 2015/16, Armour reduced the level of operational activity, yet retained commercial gas flow rates from Egilabria through trialing new gas extraction techniques and sweet spot delineation. Three exploration wells have been drilled thus far under the permit: Egilabria 2, Egilabria 2DW1 and Egilabria 4. Armour Energy is continuing to assess potential partnerships with global petroleum E&P majors in relation to ATP 1087-P. Armour reports 364 Bcf of contingent resources (3C) to date and anticipates enough gas in place to supply a 6 MMtpa LNG plant for 25 years. It was reported by the company that the proof of concept in Egilabria opens up a potential for additional 18.7 Tcf of prospective resources from shale gas, primarily within the Lawn formation and across staked plays. Both the Lawn and Riverleigh formations are considered proven source rocks, which lay under basal anticlinal plays. The source rock quality at Egilabria displayed TOC up to 11% with mature, dry gas. Armour would ideally revisit the wells to conduct an appraisal pilot to target 2-3 Bcf of recoverable gas. Within the Northern Territory permits areas, Armour is focusing on shale gas plays and deeper oil plays. The McArthur Basin contains large unexplored areas with stacked play opportunities as identified by Armour from seismic interpretation in the McArthur Group (Barney Formation), and the deeper Tawallah Group (Wollogorang and McDermott formations). To further delineate these opportunities, Armour is looking for a partner to assist with a regional seismic programme before drilling deep stratigraphic wells. To date, just six wells exploration wells have been drilled by Armour in over 53,000 sq km of licensed area. Gas flows up to 3.3 MMcf/d have been achieved from the McArthur Group. Prospective resources for the McArthur Group (Barney Creek Formation), within EP 171 and EP 176, has been reported by Armour to be around 1.2 MMbbl oil and 13 Tcf gas. There are also conventional oil and gas plays, including 18 prospects along the Batten Trough, dominantly in the Coxco Dolomite. The Glyde and Lamont Pass discoveries encountered gas bearing intervals within the dolomites and dolomitic shales of the target Middle Proterozoic Barney Creek Formation prior to drilling in to the Coxco Dolomite Formation which formed the wet gas discovery made by nearby zinc exploration well Glyde River 9, drilled in 1979. Armour Energy Ltd is offering participating equity in seven exploration licences as the company seeks to further test the shale gas/oil and conventional plays present.         .

Armour Energy Ltd is looking to farm-down its 100% owned exploration licences across the McArthur, Georgina, and Carpentaria (Isa Super Basin) basins. Armour operates six licences under the jurisdiction of the Northern Territory: EP 171, 174, 176, 190-192, and one in Queensland: ATP 1087-P which are all available for farm-in.

Faroe spudded appraisal well 31/7-3 S at Brasse East in PL 740 on 20 November 2018 using the “Transocean Arctic” S/S. It was targeting potential recoverable reserves of 12.5 MMboe on the eastern flank of the Brasse field, identified following recent seismic reprocessing and re-interpretation work. The well reached TD at 2,705 m (2,247 TVDSS) and is a dry hole. Water-wet sands were encountered in a Jurassic reservoir (48 m) with excellent reservoir quality. On 17 December 2018 sidetrack 31/7-3 A was kicked off targeting incremental reserves of 61 MMboe in the main Brasse reservoir. The well reached TD at 2,863 m (2,254 m TVDSS) and encountered oil. It penetrated around 40 m of Jurassic reservoir and reservoir depths and hydrocarbon contacts were similar to what was prognosed. On 16 January 2019 Faroe was abandoning the well. Brasse discovery well 31/7-1 was drilled in 2016 and proved a 21 m oil column plus an 18 m gas column in the Jurassic Fensfjord Formation. Sidetrack 31/7-1 A was drilled to appraise the southeastern part of the discovery and confirmed oil and gas columns of 25 m and 6 m respectively. In 2017 Faroe appraised the find with 31/7-2 S, which confirmed a 9 m oil column in the Sognefjord Formation and on test flowed at a maximum rate of 6,187 bo/d through a 1” choke from a 3.6 m perforated interval, and 31/7-2 A which proved an 18 m oil column plus a 4 m gas column. Both wells have the same OWC as the discovery well (2,172 m), although 31/7-2 A has a deeper GOC (2,154 m), and there is good pressure communication between all wells. Reserves have been upgraded from 43-80 MMboe to 56-92 MMboe (46-76 MMbo plus 59-97 Bcfg). Faroe is progressing plans for development as a subsea tie-back to either Brage or Oseberg and envisages 3 - 6 production wells plus a potential water injector. It believes that it could achieve a rate of 30,000 boe/d with first oil in 2021 / 2022. Capex is forecast at USD 500-700 million (based on four wells and one subsea template) and the final concept selection will take place in 2018 with PDO submission likely in 2019. Interest in PL 740 is divided between Faroe Petroleum Norge AS (50% + operator) and Point Resources AS (50%).

Norway (Oseberg Fault Block (Horda Platform)) Oseberg

CBM research well in Nomgon IX CBM PSC, S. Gobi Desert, TD 491m, coal seam targets met, 82m net, thickest seam 51m, ref. DEA 5 Feb '20 now determined a CSG discovery, avg total gas content in the thickest 49m gross (37m net) seam >5 cum/ton, well now P&A'd. Lab work required to determine saturation + ash content, results of which would determine a planning process to design a testing / delineation programme in the area.

Nomgon 1X expl (South Mongolian Petroleum LLC 100%), CBM research well in Nomgon IX CBM PSC, coal seam targets met, 82m net, thickest seam 51m, determined a CSG discovery, avg total gas content in the thickest 49m gross (37m net) seam >5 cum/ton, well now P&A'd. Lab work required to determine saturation + ash content, results of which would determine a planning process to design a testing / delineation programme in the area. TD 491m.

Shushan C-12 West block, Shushan Basin, W. Desert, susp late Oct ’17 after testing 1,963 bo/d from the Kharita, TD 4,348m (U. Safa), EDC rig 17. Target Alam el Bueib 6 Unit. Apache (op), partner Sinopec.

Hydra East 1 op. by Khalda (Apache 33,5%, Sinopec 16,5%, EGPC 50%, carried) in Shushan C-12 West block susp. after testing 1 963 bo/d from the Kharita fm. TD=4348m.

Committed well in Luna Muetse (E13) block, Gabon Coastal Basin offshore, WD 2,668m, 78, gross oil column, completed during 1Q ’18, assessment underway, PTD was 5,500m, West Capella DS. Repsol (op), partner Woodside.

Ivela 1 op. by Repsol (60%, Woodside 40%) in Luna Muetse (E13) block, 78m gross oil column, assessment underway, PTD= 5500m, WD= 2668m.

Add. DEA 20 Apr '20: Project Icewine area A, ADL 393380, Central North Slope, appraisal to the 1991 Malguk-1 light oil discovery, TD 3,387m (Kuparuk fm), over 85m of net pay interpreted over the Seabee, Torok + Kuparuk fm's, lab tests confirm 49-52 API cond gas in the Torok, GOR 17,000-23,500 cf/bbl calling for gas re-injection to maintain pressure should any production be undertaken. Release, sections + maps: www.88energy.com. 88 Energy (op), partner Burgundy Xploration

United States (North Slope B.) Charlie 001 op. by PREMIER (60%), 88 ENERGY (30%), BURGUNDY X (10%) in NS-0291B block, TD = 3387 m appraisal to the 1991 Malguk-1 light oil discovery, TD 3,387m (Kuparuk fm), over 85m of net pay interpreted over the Seabee, Torok + Kuparuk fm's, lab tests confirm 49-52 API cond gas in the Torok, GOR 17,000-23,500 cf/bbl calling for gas re-injection to maintain pressure should any production be undertaken.

XX Kultak-Kamashi block, Amu-Darya Basin on the Turkmen border, 2 intv's tested: upper zone (20m) gauging up to 6.9 MMcfg/d, lower intv fracked and yielded gas (volumes n/a). 2019 Ernazar Garbiy-1 discovery TD'd at 4,000m and was fracked.

Ernazar Garbiy (West)-2 appr XX Kultak-Kamashi block, Amu-Darya Basin on the Turkmen border, 2 intv's tested: upper zone (20m) gauging up to 6.9 MMcfg/d, lower intv fracked and yielded gas (volumes n/a). 2019 Ernazar Garbiy-1 discovery TD'd at 4,000m and was fracked.

Chevron secured retention lease WA-87-R, 160 sq km on the Exmouth Plateau, N. Carnarvon Basin, on 2 Mar ’18 for 5 years.  It contains the 2015 Isosceles gas discovery in former WA-374-P which has been correspondingly reduced. Chevron (op), partners Shell + ExxonMobil.

Chevron (50% + Op., Shell 25%, ExxonMobil 25%) was awarded retention lease WA-87-R.

In early February 2018, BP Canada Energy Group acquired 10% WI from Anadarko Canada E&P in two Grand Banks exploration licences: EL 1125 and EL 1126 (Labrador-Newfoundland Shelf). The transactions are effective as of 15 January 2018. The exploration licences were originally awarded to Chevron by the C-NLOPB on 12 November 2015, based on a US$43 million work commitment. EL 1126 is the site of sidetracked NFW Fitzroya A-12, which was kicked-off in February-March 2016 with the the "West Hercules" semi-sub. Fitzroya A-12 was drilled in a 743m of water, about 26km northwest of Statoil's 2013 Bay du Nord C-78Z discovery on EL 1112. That new field wildcat found between 300 and 600 MMb of 34-degree oil (recoverable) in what has been described as an "excellent" Jurassic reservoir with high permeability and porosity, spurring a great deal of renewed interest in the waters of the Flemish Pass. Following completion of the February 2018 transactions, equity in EL 1125 and EL 1126 is now shared between Statoil Canada (40% WI + Op), Chevron Canada (40%) and BP Canada Energy Group (20%).

BP (->20%) acquired 10% WI from Anadarko (-> 0%, Statoil 40% op, Chevron 40%) in 2 Grand Banks exploration licences: EL 1125 and EL 1126.

WB-ONN-2005/4 block, onshore Bengal Basin, TD 2,610m, tested 3.12 MMcfg/d during 3Q from the Miocene + 116 bo/d from a separate intv, FTP 0-200 psi. ONGC (op), partner Oil India.

Asokenagar 1 (ONGC 75%, Oil India 25%) in WB-ONN-2005/4, o&g disc, have tested oil and gas at the depth of 2370m, On testing, an interval in the Upper Miocene age flowed 3,12 MMcfg/d with 12 bc/d. One more interval flowed oil 116 bo/d in surges with average water cut of 7%.

On 30 July 2018, Petrofac Facilities Management Limited announced that it signed an agreement to sell 49% equity to Perenco in its Petrofac Netherlands Holding B.V., its subsidiary that holds the rights in the CNH-M2-Santuario-El Golpe/2017 PSC contract, the AE-0390-M-Arenque exploration and production entitlement and CIEP Service Contract, and the AE-0395-M-Magallanes-Tucan-Pajonal exploration and production entitlement and CIEP Service Contract.  The Santurario-El Golpe PSC contract is a production sharing contract (PSC).  Petrofac Mexico S.A. de C.V. is the designated operator with a 36% working interest and PEMEX is the lone partner with 64% working interest.  The other two CIEP Service Contracts are per barrel fee based service contracts with Petrofac as the service contract operator, PEMEX holding 100% of the working interest.  The two CIEP Service Contracts have been in the migration process to a PSC or License contract (CEE) for a couple of years now. The terms of the deal were reported to be that Perenco paid USD 30 million upon signing the agreement and will pay and additional USD 170 million upon completion of the deal which is pending formal governmental approvals.  The total final consideration includes a fixed amount and contingent consideration pending achieving certain milestones including future field development and the contract migration terms for the two legacy CIEP Service Contracts.  The final total consideration is subject to adjustment based on the aforementioned milestones but will be capped at a maximum of USD 274 million. During May 2016, the CNH reported that the A-0390-Arenque production entitlement and also a legacy CIEP Service Contract was migrated to an exploration and production entitlement.  The denomination for the block changed to the AE-0390-M-Arenque block.  This represented the first step in the process to migrate the entitlement to the new PSC or License Contract model (CEE).  The entitlement now has a 25 year total term with a three year exploration period and the possible extensions from the original production entitlement granting date of 13 August 2014.  The Service Contract is operated by Petrofac Facilities Management Limited who won the block in the PEMEX Service Contract Round in 2012.  SENER granted the A-0390-Arenque block to PEMEX 100% on 13 August 2014. It covers an area of 2,035 sq km in the northwestern, offshore Tampico-Misantla Basin. The block contains five oil and gas fields, Arenque, Jurel, Lobina, Merluza, and Nayade. During May 2016, the CNH reported that the A-0395-Magallanes-Tucan-Pajonal production entitlement and also a legacy CIEP Service Contract was migrated to an exploration and production entitlement.  The denomination for the block changed to the AE-0395-M-Magallanes-Tucan-Pajonal blockThe Service Contract is operated by Petrofac Facilities Management Limited who won the block in the PEMEX Service Contract Round in 2011.  SENER published in July 2015 that the Magallanes-Tucan-Pajonal field covers an area of 133.1 sq km and had original oil and gas in place (OOGIP) of 909.6 MMboe.  The secretariat reported remaining 2P reserves for the field are 32.4 MMboe of 33° API. SENER published in July 2015 that the Otates field covers an area of 35.7 sq km and had original oil and gas in place (OOGIP) of 243.7 MMboe.  The secretariat reported remaining 2P reserves for the field are 5.3 MMboe of 34° API.  SENER granted the A-0395 – Magallanes-Tucan-Pajonal block to PEMEX 100% on 13 August 2014.  According to SENER the block originally covered an area of 198.85 sq km in the northwestern, onshore Sureste Basin but now covers approximately 164.00 sq km after a part relinquishment for the modification of the entitlement. The block contains two main oil and gas fields, Magallanes-Tucan-Pajonal and Otates. On 18 December 2017, the CNH signed the contract granting an official award with Petrofac Mexico S.A. de C.V. and PEMEX for the CNH-M2-Santuario-El Golpe/2017 PSC contract (CEE).  The contract is a production sharing contract (PSC).  Petrofac Mexico S.A. de C.V. is the designated operator with a 36% working interest and PEMEX is the lone partner with 64% working interest.  The contract has a basic 25 year term from the 18 December 2017 effective date with the possibility of two, five-year extension periods.  During the next six months the operations of the contract area will be handed over to the designated operator by PEMEX and the operator will have to present its first development plan. The Santuario Service Contract area includes the A-0121-Campo El Golpe and the A-0396-Santuario production entitlements granted on 14 August 2014.  The migration process has been ongoing since July 2015.  PEMEX presented a production and development plan that involves activities over a 12 month period that would start when the new contract is signed, estimated to be June 2017.  The company is proposing to conduct 10 minor workovers, eight major workovers, 30 reservoir pressure surveys, three studies, and 12 infra-structure enhancements including oil and gas gathering lines and wellheads.  The total estimated cost of the 12 month project is estimated to be USD 13.86 million for development activities and USD 51.1 million for production activities.  Service contractor Petrofac is to migrate with the official operator PEMEX.  The El Golpe field covers an area of 42.6 sq km and had original oil and gas in place (OOGIP) of 234.8 MMboe. SENER reported remaining 2P reserves for the field are 5.9MMboe of 36° API.  SENER published in July 2015 that the Santuario field covers an area of 63.5 sq km and had original oil and gas in place (OOGIP) of 557 MMboe. The secretariat reported remaining 2P reserves for the field are 120.6 MMboe of 32° API.  The Service Contract originally covered an estimated area of 129.93 sq km in the northwestern, onshore Sureste Basin but now covers 153.19 sq km after the two entitlements were granted. The block contains two main oil and gas fields, Santuario and El Golpe and the minor Caracolillo field.  The Santuario Service Contract is operated by Petrofac Mexico S.A. de C.V., a subsidiary of London based Petrofac Services Limited, who won the block in the PEMEX Service Contract Round in 2011 after contract signature on 17 October 2011.

Perenco is acquiring 49% in Petrofac’s Mexico assets – including Santuario, Magallanes and Arenque fields for US$200 MM.

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

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

After considering a farmout or outright sale, Gran Tierra has agreed to sell its Peruvian assets to PetroTal and Sterling Res. The deal is involved and in a nutshell Sterling and PetroTal will be amalgamated under the name Sterling Resources. Five blocks would be involved in the Marañon and Ucayali basins.

Peru, not found

Greymouth Petroleum Turangi Ltd, a wholly owned subsidiary of Greymouth Petroleum Ltd, was granted an area increase to mining permit PMP 38161 located in the Taranaki Basin, on 19 March 2020. The permit has been increased by approximately 30% of the previous permit area, from 46 sq km to 60 sq km. The area has been increased to the east and now includes the areas previously being offered as 174E38/33-3 and 174E39/3-1 as part of the Block Offer 2018. The area now incorporated into PMP 38161 includes the dry Heaphy 1 well, drilled in early 2006. PMP 38161 now covers an area of 60 sq km. The permit was originally awarded on 28 April 2006 and covered an area of 26 sq km. Greymouth Petroleum Ltd holds 100% operated interest in the permit through four wholly owned subsidiaries.

New Zealand, PMP 38161

United Energy secured the 9.7-sq km Kamal North D&PL within the Khiro EL, Lower Indus onshore Sindh, retro-effective 20 Jul ‘07. United Energy (op), partners Bow Energy + Govt Holdings.  

United Energy secured the 9.7-sq km Kamal North D&PL within the Khiro EL, Lower Indus onshore Sindh, United Energy (op), partners Bow Energy + Govt Holdings.

On 16 October 2019, Ecopetrol reported an oil discovery in the Flamencos 1 new-field wildcat (NFW) well located on the Magdalena Medio contract in the Middle Magdalena Exploitation Agreement. The Flamencos 1 was spudded on 6 August 2019. It was drilled to a total depth (TD) of 2,620 m (8,561 ft) and encountered the La Paz Formation interval from 2,276-2,519 m (7,465-8,263 ft). Initial daily flow rates averaged up to 600 bo/d of 30° API gravity oil and the NOC reported a 2.4 Mbbl find. This block includes a cluster of mature fields operated by Ecopetrol with 100% interest.

Colombia, Magdalena Medio

Sinopec in April 2020 was starting a process to sell its 20% stake in the PAMA-M-192 and PAMA-M-194 exploratory blocks in the Para-Maranhao Basin, according to the company. Petrobras holds the remaining 80% on the two blocks and will have the rights of first refusal on any farmout offers received. However, that seems unlikely since Petrobras is selling up to 40% of its share in the blocks also. The Round 6 concession blocks have a total area of ??1,538 sq km. The minimum exploratory program for the second period of exploration calls for the drilling of a well in PAMA-M-192. Sinopec claims the blocks feature world-class prospects, with low exploration commitments and the potential to prove significant volumes of oil in a frontier area. Sinopec also touts a proven petroleum system both on the shelf and in deepwater for oil generation and migration. To express formal interest in the farmout process, companies must be listed by the ANP as Operator A or non-operator or be able to meet the requirements to qualify with the ANP. Interested companies should communicate this to Sinopec by 25 April. Petrobras, in late February 2020, extended the deadline to file documents showing interest in the teaser to divest the BM-PAMA-3 and the PAMA-M-192 and PAMA-M-194 exploratory blocks in the Para-Maranhao Basin. At an ANP Board of Directors Meeting on 28 September 2016, the board reviewed a Discovery Assessment Plan (PAD) for the 1BRSA903PAS discovery on the BM-PAMA-3 block in the frontier Para-Maranhao Basin. The final completion date for the PAD is now 15 December 2020 when Petrobras will have to issue a declaration of commerciality or relinquish the area. Petrobras acquired 3D seismic over the contract in early 2009. The ANP, in April 2012, approved Petrobras's discovery evaluation plan for the significant, rank wildcat, 1BRSA903PAS, Harpia prospect, on the south-central part of the BM-PAMA-3 Block. To date no follow up appraisals have been drilled for the discovery. Petrobras concluded operations during late September 2011 on the well after reporting oil and gas shows. It was considered by some to be the most significant well drilled in Brazil during 2011. Petrobras drilled the well in a water depth of 2,060m. Petrobras had a PTD of 5,908m for the wildcat and drilled a very large, gravity induced, faulted anticlinal structure. The principal targets were the Eocene portion of the Travosas Formation with secondary targets possibly in the Cenomanian section of the Travosas Formation. Additional targets were believed to exist in the Oligocene and Miocene sections of the Travosas Formation. The Travosas Formation ranges in age from Cenomanian to Pleistocene and is predominantly shale with sandstone turbidites, fans, and channels that range through the entire extent of the formation.

Sinopec in April 2020 was starting a process to sell its 20% stake in the PAMA-M-192 and PAMA-M-194 exploratory blocks in the Para-Maranhao Basin, according to the company.

Ayashskiy licence off Sakhalin, WD 80m, oil discovery assumed in the target Miocene Nutovo fm, in-place reserves pegged at 1 Bboe. HYSY982 SS. PTD was 2,850m.

Bautinskaya 1 (Triton) (GazpromNeft 100%) in Ayashskiy licence, oil discovery assumed in the target Miocene Nutovo fm, in-place reserves pegged at 1 Bboe, WD=80m, PTD=2850m.

The Ministry of Petroleum and Energy (MPE) confirmed on 18 June 2018 that it has offered 12 new licences to 11 companies in the 24th Licensing Round. The number of companies that applied is significantly down from the 26 companies that applied for acreage during the 23rd Round. The exploration acreage that has been offered is in both the Norwegian and the Barents seas, with most in the Barents Sea, and particularly the northwestern part. The following companies have been offered acreage: Aker BP, DEA, Equinor, Idemitsu, Lundin, M Vest, OMV, Shell, Spirit Energy, VNG and Wintershall. Official awards are expected before summer 2018. The 24th Round was opened by the MPE on 21 June 2017, with applications due by noon on 30 November 2017. This Round included 102 blocks (or part blocks) – nine in the Norwegian Sea and 93 in the Barents Sea. Background information: On 29 August 2016 the MPE invited companies to nominate blocks which they would like to see included in the 24th Round. All three areas of the NCS were open for nominations with particular focus on frontier areas with the greatest potential. Companies were invited to nominate up to 15 blocks which they would like to see included. Nominated blocks were to be divided into two categories – ‘interesting’ and ‘very interesting’. Nominations needed to be received by the MPE before 12:00 hours on 30 November 2016. Nominations were received from 22 companies. The nominations are an important part of deciding what acreage to include in the 24th Licencing Round. All areas open for petroleum exploration could be nominated in the round, excluding: areas already covered by licences, areas included in the Awards in Predefined Areas (APA) and areas where activity has been restricted through different management plans for the sea areas.   The MPE sent its proposal for the blocks to be included in the 24th Round to public consultation on 13 March 2017. It proposed that a total of 102 blocks were to be included – 93 in the Barents Sea and nine in the Norwegian Sea. Comments had to be received by 2 May 2017. Licence Block(s) Operator Partners New seismic/well commitments 537 B 7324/4 OMV (25%) Idemitsu (20%)         Petoro (20%)         Equinor (35%)   852 C 7322/4, 8 Spirit (60%) Aker BP (40%)   957 6201/6 and 6202/4 Equinor (100%)     958 6408/4, 7 Shell (50%) Petoro (20%)         VNG (30%)   959 6503/8, 11, 12 and 6504/10, 11 Equinor (50%) M Vest (10%)       Petoro (20%)       Spirit (20%)   960 7018/4, 5 Equinor (40%) DEA (20%) One firm well       Lundin (20%)         Petoro (20%)   961 7116/6 and 7117/4, 5 Equinor (50%) Petoro (20%)         Aker BP (30%)   962 7322/1, 2, 4, 5, 8 Equinor (60%) Aker BP (20%) Acquire new 3D seismic       Lundin (20%)   963 7422/10, 11 Aker BP (70%) Equinor (30%)   964 7320/1, 2, 3, 5, 6 and 7321/1, 2 and 7420/12 and 7421/10, 11 Aker BP (40%) DEA (15%)       Wintershall (20%)       Petoro (25%)   965  7323/5, 6 Lundin (60%) Spirit (40%) Acquire new 3D seismic 966  7325/2, 3, 6, 8, 9 and 7326/4, 7, 8, 9            and 7327/7, 8 and 7426/10, 11 Equinor (70%) Aker BP (30%)

Norway has awarded nine exploration licences in the Barents Sea among 12 tracts handed out to 11 oil companies under its 24th licensing round. Equinor gets 5 operatorships out of 7 awards, Aker BP 2 operatorships out of 6 awards.

A result of the closing of the OALP II & III rounds in May, Oil India has reportedly applied for 16 blocks, Vendanta for 30, ONGC for 20, Indian Oil Corp, GAIL and Sun Petro each for 2 blocks. It would seem that OIL could secure 12 blocks, ONGC + Vendanta 9 each, and a Reliance-BP partnership 1 block in the KG Basin. The DGH is looking to the OALP-IV & V rounds later in 2019.

A result of the closing of the OALP II & III rounds in May, Oil India has reportedly applied for 16 blocks, Vendanta for 30, ONGC for 20, Indian Oil Corp, GAIL and Sun Petro each for 2 blocks. It would seem that OIL could secure 12 blocks, ONGC + Vendanta 9 each, and a Reliance-BP partnership 1 block in the KG Basin. The DGH is looking to the OALP-IV & V rounds later in 2019.

On 29 June 2019, Novatek announced that it had signed a Sales and Purchase Agreement with Japanese Mitsui and JOGMEC for a 10% stake in Arctic LNG 2 project in Yamalo-Nenets Autonomous Okrug (Western Siberia). The agreement also foresees a long-term LNG offtake of 2 MMtpa of LNG by Japanese partners. The deal will be finalized after regulatory approvals. Note that on 5 March 2019, Novatek and Total SA signed a Sales and Purchase Agreement transferring to Total a 10% stake at the Arctic LNG 2 followed, on 7 June 2019, by the signature of Sales and Purchase Agreements with CNODC and CNOOC regarding the sale of 10% stakes in the Arctic LNG 2 project to each of Chinese companies. (CNODC is a wholly owned subsidiary of CNPC). Arctic LNG 2 will include three liquefaction trains with capacity of 6.6 MMtpa each installed on gravity-based platforms in the Ob Estuary. The Salmanovskoye (Utrenneye) gas/condensate discovery is the feedstock for the LNG plant. In 2014-2017, Novatek-subsidiary Arctic SPG2 drilled six appraisal wells that resulted at extension of the discovery’s productive area and increase of its reserves. As the end of 2018, the company estimated 3P reserves of the discovery at 67.7 Tcf of gas and 840 MMbbl of condensate and oil. Salmanovskoye, discovered in 1979, is located in the South Kara-Yamal Province in the Gydan Peninsula with a minor extension to the Ob estuary. About 60 identified hydrocarbon accumulations are distributed within the 2,100 m sedimentary section aging from Valanginian to Cenomanian.

Novatek announced that it had signed a Sales and Purchase Agreement with Japanese Mitsui and JOGMEC for a 10% stake in Arctic LNG 2 project in Yamalo-Nenets Autonomous Okrug (Western Siberia).

Petroperú has embarked on the search for possible partners in block 192 when the contract with Frontera Energy expires early next year. The 5,123-sq km block in the Marañon Basin on the Ecuadorian border, Loreto, produced some 1,010 bo/d during July.

Petroperú has embarked on the search for possible partners in block 192 when the contract with Frontera Energy expires early next year. The 5,123-sq km block in the Marañon Basin on the Ecuadorian border, Loreto, produced some 1,010 bo/d during July.

In early September 2018, the Minister of Mines, Industry and Energy of Equatorial Guinea, H.E. Gabriel Mbaga Obiang, reported that his country was planning to launch a new oil and gas exploration bidding round in January 2019. The oil Minister added that he may refuse extensions of existing permits to oil operators unless they collectively invest a minimum of USD 2 Billion in the country. This strong message is in line with the announcement made in late 2016, when the government warned companies to be active with drilling or to hand back their permits. Obiang’s reaction is certainly linked to stagnant mega-projects like Ophir’s Fortuna FLNG, still a risk since Schlumberger decided to end its participation into OneLNG, due to delayed financing solution. Other oil players in the country include US-giant ExxonMobil, producing almost half of the country’s oil output from its Zafiro field, Kosmos who not only took over Hess’ producing oil assets Ceiba and Okume but also the surrounding exploration blocks. Marathon still dominates the gas production in the country, from its Alba Complex, representing almost 90% of the total country gas output. Noble recently signed Heads of Agreement regarding Alen gas monetization. And Atlas, which is looking for farm-in partners since years, prior exploration drilling in its permits that expired in April 2018. The latest licensing round in Equatorial Guinea ended in early April 2017, when seven companies won six exploration blocks offered during the EG Ronda 2016 Licensing Round. Out of 23 companies expressing interest in the licensing round, 12 submitted official bids. Of those, seven companies proceed to negotiations and ultimately signed Production Sharing Contracts (PSC) around late year 2017.

In early September 2018, the Minister of Mines, Industry and Energy of Equatorial Guinea, H.E. Gabriel Mbaga Obiang, reported that his country was planning to launch a new oil and gas exploration bidding round in January 2019.

In April 2020 it was learned from company sources that Equinor, formerly Statoil, was in the relinquishment process with its interests in four blocks in the offshore Espirito Santo Basin. These blocks are: ES-M-596, ES-M-598, ES-M-671 and ES-M-673. All are ANP Round 11 blocks awarded in May 2013 and each has an area of about 720 sq km. The ES-M-596 Block is operated by Petrobras with 50% while Equinor holds the remaining 50%. In this block Petrobras could absorb the 50% of Equinor by using its right of first refusal. The other three blocks are operated by Equinor. ES-M-598 and ES-M-673 are Equinor (40%) while Petrobras is partner with 40% and Queiroz Galvao 20%. ES-M-671 is Equinor 35%, Petrobras 40% and Total 25%. These blocks could be relinquished by Equinor or its partners could take over the Equinor interests after approval by the ANP. Brazilian government sources in September 2019 indicate that Petrobras new-field wildcat 1BRSA1360ESS on the ES-M-596 Block had oil shows. Previous reports had the well ending drilling operations by 14 May 2018 and since no oil or gas show reports were previously announced by the ANP for the well, it was believed to be plugged and abandoned as a dry hole. The well had a planned total depth of 5,532m and was drilled by the Odebrecht’s ODN I drillship in a water depth of 1977m. The projected objective was the Late Cretaceous Urucutuca Formation. Since 2016, Equinor has been trying to farmout interest in the offshore Espirito Santo Basin including four Round 11 blocks: ES-M-598, ES-M-673, ES-M-671 and ES-M-743. Petrobras drilled a dry hole in 2004 with a total depth of 6,814m in ultra-deepwater on block ES-M-671. The stated reason for offering the farm-out was wanting to reduce their risk exposure. In December 2014 a multi-client 3D seismic survey in the offshore Espirito Santo Basin called Espirito Santo Phase III completed shooting. The survey was shot by the French company CGG for a planned data acquisition of 9,605 sq km. The ES-M-596 Block was covered in the survey along with others signed in 2013 from ANP Round 11. The data was acquired by the Oceanic Champion M/V.

Not Found

On 11 January 2018, Reuters reported that Shell West Qurna BV, a subsidiary of Royal Dutch Shell plc, had sold its 20% interest in the West Qurna 1 field development to Itochu Corporation. The report has not yet been officially confirmed by the Iraqi Ministry of Oil or Shell. The West Qurna-1 field development contract was originally awarded to a consortium led by Exxon Mobil Corporation in November 2009. The agreement was finalised on 25 January 2010 after the consortium reportedly accepted amendments made by the Iraqi government. Interests in the project were later sold to PetroChina Co Ltd (32.7%) and PT Pertamina (10%). The remaining 4.6% interest is held by the Iraqi state Oil Exploration Company. The contract has a 20 year duration and is expected to raise the field production from initial levels of 244,000 b/d to a revised plateau level of 1.6 MMbo/d. Current production is estimated at approximately 400,000 b/d. Shell is also planning to sell its 45% interest in the Majnoon field development. The West Qurna phase 1 field development was originally offered in the first Iraqi licensing round for field development contracts held in June 2009. At the time, none of the bids received for the field met the government's remuneration fee requirements. Four consortia, led by Lukoil, ExxonMobil, CNPC and Total were believed to be originally competing for the West Qurna-1 field development contract. The Lukoil and ExxonMobil consortia were said to have accepted the government's remuneration fee of USD 1.9 per barrel, and CNPC and Total were expected to meet with Iraqi officials to discuss whether they would also accept the fee. ExxonMobil proposed a production increase of 2.1 MMb/d for the field whereas Lukoil initially proposed 1.5 MMb/d, however this was later revised upwards to an undisclosed target.

Itochu has agreed to acquire 20% stake in West Qurna 1 oilfield from Shell (->0%, Exxon 32,7% + op. PetroChina 32,7%, Pertamina 10%, Iraqi Oil Explo. 4,6%).

Equinor (Op), Idemitsu Petroleum and Neptune have been awarded PL090 JS for stratigraphies below Base Cretaceous over 4.061 sq km in North Sea part block 35/11, covering the SW portion of the Grosbeak discovery. The licence is in the Production phase and became effective 9 October 2018, valid until 9 March 2024 and was split out of Equinor-operated PL090 F. Grosbeak is mostly licensed under Wellesley Petroleum-operated PL248 I and PL925, immediately to the E. It was discovered by 35/12-2 (2009, Wintershall, 2,541m) and appraised during July-Oct 2018 by 35/11-21 S & 21 A (Wellesley Op) which confirmed recoverable resources of 50-128 MMbo and 0.6-1.3 Tcfg in Jurassic Ness, Etive, Sognefjord and Fensfjord Formations. PL090 JS equity partners are Equinor Energy AS (45% + Op), Idemitsu Petroleum Norge AS (40%) and Neptune Energy Norge AS (15%).<P />

Norway, PL 090

EnQuest has agreed to acquire 40.8125% and operatorship from Equinor in Bressay heavy oil field licences P234 (3/28a), P493 (3/28b), P920 (3/27b) and P977 (9/2a & 9/3a), as released on 31 July 2020. Initial consideration is GB£ 2.2 million (US$ 2.86 million), to be payed as 50% of Equinor’s net share of costs from deal completion (expected Q4 2020) with a contingent consideration of US$ 15 million following Field Development Plan (FDP) government approval for Bressay. The contingent payment increases to US$ 30 million if EnQuest sole risks Equinor in the submission of the FDP. The development concept selection was deferred in 2016 due to challenging market conditions and the need to simplify the development concept. Extensions to licence expiry dates and commitments are condition precedents to completion. A development concept being considered is a tie back to Kraken heavy oil field (EnQuest Op, 12km NE). EnQuest will become operator on P&A of discovery well 3/28-1 (1976, Chevron, 1,527m, Tertiary reservoir). The field was later successfully appraised. Estimated gross STOIIP is 600-1,050 MMbo and 100-300 MMbo estimated gross recoverable. 50km S is the Equinor operated Mariner Field. Chrysaor entered the licence when it acquired a package of assets from Shell in 2017. Current field partners Equinor UK Ltd (81.625% + Op) and Chrysaor Ltd (18.375%).

(East Shetland Platform) EnQuest has agreed to acquire 40.8125% and operatorship from Equinor in Bressay heavy oil field licences P234 (3/28a), P493 (3/28b), P920 (3/27b) and P977 (9/2a & 9/3a). Current field partners Equinor UK Ltd (81.625% + Op) and Chrysaor Ltd (18.375%). After completion, new field partners will be EnQuest (40.8125%, op.), Equinor UK Ltd (40.8125%) and Chrysaor Ltd (18.375%).

Key is offering 50% in Cooper-Eromanga ATP 783, 920 + 924-P in exchange for contributions to the planned explo programmes. The blocks cover resp. 1,615 sq km,  1,157 sq km (recently reduced from 2,160 sq km) +  1,075 sq km (recently reduced from 1,841 sq km). Contact: [email protected] or [email protected]:

Key is offering 50% in Cooper-Eromanga ATP 783, 920 + 924-P in exchange for contributions to the planned explo programmes. The blocks cover resp. 1,615 sq km, 1,157 sq km (recently reduced from 2,160 sq km) + 1,075 sq km (recently reduced from 1,841 sq km).

In late December 2017, Rosneft completed testing of a new pool wildcat at the Salymskiy Vostochnyy license in Khanty-Mansiyskiy Autonomous Okrug (Western Siberia). Vuyemskaya 4, spudded in late June 2017, reached its TD of 3,152 m in August. In December, the company reported a new pool in the Cherkashinskaya Formation (Neocomian) after testing oil and water at rates of 41 b/d and 13 b/d, accordingly, through a 2 mm choke from the interval 2,173-2,187 (AS8). Vuyemskoye, discovered in 2000, is located in the southeastern part of the Ural-Frolov Province. As of 2016, 3P reserves of five pools, distributed within the Middle Jurassic-Neocomian section, were estimated at 74 MMbbl.  

Russia (West Siberian B.) Vuyemskaya 4 op. by ROSNEFT (100.0%) in Salymskiy Vost. block. the company reported a new pool in the Cherkashinskaya Formation (Neocomian) after testing oil and water at rates of 41 b/d and 13 b/d, accordingly, through a 2 mm choke from the interval 2,173-2,187 (AS8).

BP and partner Kosmos Energy have reportedly secured 5 offshore blocks with 10% partner Petroci. Involved are CI-526, CI-602, CI-603, CI-707 + CI-708, total 14,740 sq km in WD 1,000-3,500m and actually previously held by the likes of Total or ExxonMobil. Details awaited.

BP and Kosmos Energy awarded 5 new DW offshore oil blocks: CI-526, CI-602, CI-603, CI-707 and CI-708.

1st well in block 42, offshore Khorat Swell, P&A results n/a 28 Feb ‘19, KS Java Star 2 JU. Target possibly Khorat Group clastics and/or Lower Nam Phong clastics. PetroVietnam (op), partner Vietsovpetro.

42-PQ-1X (Phu Quoc-1X) nfw, (PetroVietnam 51% op, Vietsovpetro 49%), 1st well in block 42, offshore, P&A results n/a. Target possibly Khorat Group clastics and/or Lower Nam Phong clastics.

On 5 April 2017, Premier Oil plc announced that it had signed a share purchase agreement with Al-Haj Energy Limited. Under the agreement Premier will sell its subsidiary Premier Oil Pakistan Holdings BV to Al Haj for a cash consideration of USD 65.6 million. Al-Haj have already paid a deposit of USD 15 million to Premier and are obliged to pay a further interim deposit of USD 10 million within 60 days. Closing of the transaction, which will have an economic date of 1 January 2017, is subject to all necessary government and regulatory approvals. It is expected to be finalised by the end of 2017. It was subsequently reported in January 2018 that due to delays in regulatory approvals the completion will take place in 2018. Al-Haj had paid USD 23 million deposit by the end of July 2017. Premier currently hold non-operated interests in six gas producing onshore fields in the country which include Qadirpur, Kadanwari (including Kadanwari 14), Zamzama, Bhit and Badhra and Zarghun South. Oil and Gas Development Company Ltd (OGDCL) operates Qadirpur field which is one of the major producing field in the country with a production rate of 355 MMcfg/d during 2016. Kadanwari, Bhit and Badhra fields are operated by ENI, Zamzama field is operated by Tri Resources whereas Mari Petroleum Pakistan Ltd (MPCL) operates the Zarghun South field.   Field Name Operator Premier Interest Badhra Eni 6%   Bhit Eni 6%   Kadanwari Eni 15.79%   Qadirpur OGDCL 4.75%   Zamzama BHP 9.375%   Zarghun South MPCL 3.75%      

Premier Oil announced that it had signed a share purchase agreement with Al-Haj Energy. Premier currently hold non-operated interests in six gas producing onshore fields in the country.

Mubarek Shimoliy field area, Mubarek investment block, tested 13.7 MMcfg/d from a weathered Paleozoic basement. This is a first from a basement play in the Amu-Darya Basin.

Mubarek Shimoliy 53 npw. Mubarek Shimoliy field area, Mubarek investment block, tested 13,7 MMcfg/d from a weathered Paleozoic basement. This is a first from a basement play in the Basin.

The C-NLOPB has reportedly granted Statoil and partner Husky a significant discovery licence for their 2015 Bay du Nord L-76Z o+g discovery in the Flemish Pass Basin, results of which were recently disclosed (DEA 18 Oct ’17). The well had TD’d at 4,870m in EL 1112, WD 1,100m.

Canada (Flemish Pass B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: EL 1112 op. by STATOIL (65.0%, HUSKY 35.0%) to be check.

Cairn confirmed in its full year announcement in March 2020 that it had agreed an asset exchange agreement with Shell involving two licences P2379 (blocks 22/11b, 22/12b, 22/16b and 22/17c) and P2380 (block 22/12d). The exchange concerning the two licences was complete on 23 June 2020. In the UK, Cairn operates through its wholly owned subsidiary - Nautical Petroleum. Shell has acquired a 50% interest in licence P2379 which contains the Diadem prospect, the licence has a firm well commitment that is expected to be drilled in 2022. In exchange for the P2379 interest, Cairn has acquired a 50% interest in licence P2380 from Shell. The P2380 licence has a firm well commitment well on the Jaws prospect, which is expected to be drilled in 2H 2021. The Jurassic Fulmar sandstone play is prolific in the area and if the wells are successful then they could be tied into the Nelson facilities. The commitment well for Jaws is required to be drilled to a depth of 3,730 m or the base of the Upper Jurassic. P2380 was awarded in the 30th Offshore licensing round which focussed on ‘mature’ areas of the North Sea and comprises of just one block – 22/12d. Any potential discoveries could be used to extend the field life at Nelson. Shell also picked up licence P2377 in the 30th Round which also contains a firm commitment well on a prospect known as Orlov and is within reach of a tie-back to Nelson. In September 2019 Zennor Petroleum and ONE-Dyas pulled out of licence P2379 leaving Cairn as the sole participant. The licence comprises of four blocks – 22/11b, 22/12b, 22/16b and 22/17c and contains three discoveries 22/11b-3 (Lima), 22/12a-10 (Phoenix) and 22/16-6 (Dalziel). The first of the three discoveries was 22/12a-10 (Phoenix) back in 2004. The discovery was made by Shell as a near field exploration project for the Nelson facilities. The discovery was appraised in 2010 with well 22/12a-12 which confirmed oil bearing sands within the Forties Sandstone Member within a relatively simple and low risk 4-way dip closed structure. A sidetrack of the appraisal well 22/12a-12Y was kicked-off and penetrated the reservoir outside of the structure and did not encounter any hydrocarbons. 22/11b-13 (Lima) was discovered in 2008. The well targeted three Jurassic pods. Of the three pods, only one (Fulmar 1) contained oil which is stratigraphically trapped within thin sandstones pinching out before the pod. The most recent discovery was 22/16-6 (Dalziel) in 2015. This was drilled by ENGIE targeting the Upper Jurassic Fulmar prospect. It encountered oil and tested in excess of 8,000 boe/d. Following completion of the deals interest in the licences will be held by 50% each between Cairn and Shell.

United Kingdom (Central Graben Province), Cairn confirmed in its full year announcement in March 2020 that it had agreed an asset exchange agreement with Shell involving two licences P2379 (blocks 22/11b, 22/12b, 22/16b and 22/17c) and P2380 (block 22/12d).

Oilex has reached a conditional agreement with Armour Energy for the sale of its Cooper-Eromanga assets held under the CoEra name. This follows on a similar HoA with Doriemus, which fell through last month. In exchange for shares + some cash, Armour would acquire the issued capital of CoEra, an Oilex sub. Involved are PEL 112 + 444 and a right to acquire 27 Retention Licences from Senex (Northern Fairway PRLs). Oilex intends to focus on the UKCS and India. Release here.

Oilex has reached a conditional agreement with Armour Energy for the sale of its Cooper-Eromanga assets held under the CoEra name. Involved are PEL 112 + 444 and a right to acquire 27 Retention Licences from Senex (Northern Fairway PRLs). Oilex intends to focus on the UKCS and India. Release here.

Lufeng Sag in PRMB, South China Sea, WD 270m, ops terminated 20 Apr ’19, Nanhai 9 SS. Target Mio-Oligocene clastics.

Lufeng 16-7-1 (LF 16-7-1) nfw in Lufeng Sag in PRMB, South China Sea, WD 270m, ops terminated 20 Apr ’19. Target Mio-Oligocene clastics.

Pandion announced on 16 April 2019 that it has agreed a deal with Equinor to acquire its 20% interest in PL 263 D and PL 263 E. PL 263 E is a new licence that will be carved out from PL 263. The PL 263 D and PL 263 E licences are located in the Haltenbanken area in the Norwegian Sea in blocks 6407/1 and 6507/10, respectively. PL 263 D was awarded in APA 2017. Equinor is currently maturing the Appolonia prospect which could be incorporated to Equinor’s drilling program for 2020, subject to a positive drill decision. The deal is subject to government approval and completion of the carve-out of PL 263 E from PL 263. The annual APA rounds are designed to enhance exploration activity in mature areas where smaller discoveries can make use of existing infrastructure for fast-track development. The rounds have proven particularly popular in recent years with the newer companies to the NCS which bring fresh new thinking to these much-explored areas. The APA system has resulted in quicker circulation of acreage, increased exploration activity in mature areas and a more diverse mix of companies working on the NCS. Following completion of the deal interest in PL 263 D and PL 263 E will be held by Equinor Energy AS (50% + operator), Spirit Energy Norway AS (30%) and Pandion Energy AS (20%).

Norway, PL 263 D

Shell Australia announced on 21 Novemebr 2018 that it had reached an agreement to sell its 26.56% interest in the Greater Sunrise asset to the East Timor Government.  Shell becomes the second company to sell its interest in the project to the government, after ConocoPhillips reached a similar agreement in October 2018. The sale and purchase agreement entered into by Shell and the East Timor Government, values the interest at USD 300 million (AUD 414 million).  Shell reported that the sale is in line with its global strategy, which is seeing it become a “simpler and more resilient company”. The sale and purchase agreement is conditional on a number of conditions, including regulatory approvals, joint venture pre-emption rights and funding approvals. Upon completion of the deal, Shell will assign its 26.56% 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. Shell’s sale comes after ConocoPhillips reached an agreement to sell its 30% interest in the assets to the East Timor Government, though this also remains subject to similar conditions to the Shell sale.  Both companies outlined that they differed in opinion with the East Timor Government over how the Greater Sunrise fields should be developed. Shell reported that it “[understood] the priorities of the Timor-Leste Government”. The development scenario for the fields has been long debated, with the Greater Sunrise joint venture (JV) preferring a Floating LNG (FLNG) option, 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. Both deals will have significance, as the East Timor Government has outlined that its preference remains, and with greater interest in the project it will have additional input into the development decisions. Upon announcement of the initial 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 joint venture are: Woodside Petroleum Ltd (33.44% + Operator), OG ZOKA Ltd, a wholly owned subsidiary of Osaka Gas Co Ltd (10%) and Shell Australia Ltd (26.56%) and ConocoPhillips (30%) – both selling their respective shares to the East Timor Government.

Timor Sea JPDA, JPDA 03-20

Armour Energy has been retained as the preferred bidder for explo rights to PLR201718-2-4, on the Roma Shelf, Surat Basin in QLD. Pipeline Licence 20 traverses the said block, an asset in case of a discovery. Local targets Permian gas + cond. Release here.

Armour Energy has been retained as the preferred bidder for explo rights to PLR201718-2-4, on the Roma Shelf.

On 29 January 2019, the Federal Agency for Subsoil Use held an auction for eight blocks in Bashkortostan Republic (Volga-Ural Province). Nine companies submitted bids and Bashneft, Lukoil-Perm, UDS Neft and Sabunskiy (Udmurtia) emerged as the winners. The companies will obtain 25-year E&P licenses.   The Amzyanskiy block covers 76 sq km and encompasses four prospects with combined oil resources estimated at 7 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 9 MMbbl of oil and 27 Bcf of gas. The starting price amounted to RUB 17.05 million (USD 0.26 million). UDS Neft offered RUB 18.755 million (USD 0.28 million). The Baykinskiy block covers 348 sq km and encompasses six prospects with combined oil resources estimated at 8 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 26 MMbbl of oil and 52 Bcf of gas. The starting price amounted to RUB 19.81 million (USD 0.3 million). Bashneft offered RUB 21.791 million (USD 0.33 million). The Verkhne-Yarkeyevskiy block covers 349 sq km and encompasses nine prospects with combined oil resources estimated at 12 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 10 MMbbl of oil and 17 Bcf of gas. The starting price amounted to RUB 24.95 million (USD 0.38 million). Bashneft offered RUB 39.92 million (USD 0.6 million). The Toshkurovskiy block covers 244 sq km and encompasses three prospects with combined oil resources estimated at 7 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 5 MMbbl of oil and 2 Bcf of gas. The starting price amounted to RUB 13.5 million (USD 0.2 million). Lukoil-Perm offered RUB 14.85 million (USD 0.23 million). The Turtykskiy block covers 358 sq km and encompasses eight prospects with combined oil resources estimated at 9 MMbbl and seven oil fields excluded from the offer. Hydrocarbon resources (category D1) of the block are estimated at 8 MMbbl of oil and 1 Bcf of gas. The starting price amounted to RUB 22.47 million (USD 0.34 million). Bashneft offered RUB 296.604 million (USD 4.5 million). The Kushkulskiy Severnyy block covers 424 sq km and encompasses six prospects with combined oil resources estimated at 7 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 1 MMbbl of oil and 2 Bcf of gas. The starting price amounted to RUB 14.52 million (USD 0.22 million). Sabunskiy offered RUB 15.972 million (USD 0.24 million). The Burayevskiy Zapadnyy block covers 451 sq km and encompasses eleven prospects with combined oil resources estimated at 20 MMbbl and several oil fields excluded from the offer. Hydrocarbon resources (category D1) of the block are estimated at 23 MMbbl of oil and 10 Bcf of gas. The starting price amounted to RUB 51.06 million (USD 0.77 million). Bashneft offered RUB 66.378 million (USD 1 million). The Shakhtauskiy block covers 67 sq km and encompasses the Novo-Berezovskaya prospect with oil resources estimated at 2 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 1 MMbbl of oil and 34 Bcf of gas. The starting price amounted to RUB 3.5 million (USD 0.05 million). Bashneft offered RUB 3.851 million (USD 0.06 million).

Russia, not found

Discussions between BP and Shell over the latter’s possible acquisition of BP’s 27.5% in the Shearwater o&g field in P188, Central Graben, have reportedly fallen through over the price. The interest had been valued at about USD 250 MM, and BP is once more on the quest for a buyer. Currently Shell (op), partners BP + Exxon.

Discussions between BP and Shell over the latter’s possible acquisition of BP’s 27,5% in the Shearwater o&g field in P188, have reportedly fallen through over the price. The interest had been valued at about US$250 MM, and BP is once more on the quest for a buyer. Currently Shell (op) 28%, BP 27,5%, Exxon 44,50%.

On 5 February 2018, Total SA announced that it has agreed to farm-in for 25% WI in the shallow water Kanuku Block and 35% WI in the deepwater Canje Block in the Guyana-Suriname Basin. The 25% equity is to come from operator Repsol which has been seeking to dilute its 70% WI in return for funding a NFW on the block. The Kaieteur prospect in the north east of the block has been identified and is likely to be drilled in Q1 2019 or may be fast tracked to late 2018. Tullow holds the other 30% WI after farming in for 30% WI from Repsol in May 2013 to the newly defined block. Repsol had to cancel a farm-out agreed in 2013 to the then-known RWE Dea following an injunction with TSX-listed CGX Energy. In November 2014, CGX received a US$ 900,000 settlement after CGX filed claims against Repsol for failing to seek a renewal of the Georgetown licence which expired in 2012 and covered a similar area to Kanuku. It appears that Tullow is to gain a further 7.5% WI in the block from operator Repsol to leave Repsol and Tullow each with 37.5% WI and Total with 25% WI when the transactions are completed. The company also has a 25% WI option agreement for the Orinduik Block with Eco Atlantic in the same basin. A large 4,000 sq km 3D survey was acquired over the Kanuku Block by WesternGeco in May to July 2017. The block which is sited in water depths of 70-100m is located only around 50km to the south of the 1 Bboe plus Liza-1 discovery.

Total SA announced that it has agreed to farm-in for 25% WI in the shallow water Kanuku Block and 35% WI in the deepwater Canje Block in the Guyana-Suriname Basin.

Sumbagsel 2 PPC in S. Sumatra Basin, P&A results n/a Feb ’19. PTD was ca. 3,500m, targets assumed Batu Raja + TAF, PDSI rig 42.

Belimbing Deep-1 (BED) dpw, in Sumbagsel 2 PPC in S. Sumatra Basin, P&A results n/a Feb ’19. PTD was ca. 3,500m, targets assumed Batu Raja + TAF

Moftinu field area, E IV-5 Satu Mare block, Hajdusag sub-basin in NW Romania, TD 1,600m, of 6 zones identified, the 3 lower were tested, up to 6.3 MMcfg/d on 40/64” choke (late 5.5 MMcf/d on 36/64”), no progressive pressure decrease, no water. The well is now under a 5-day pressure buildup. Winstar (op), partner KMG.

Moftinu-1003 appr Moftinu field area, E IV-5 Satu Mare block, Hajdusag sub-basin in NW Romania, TD 1,600m, of 6 zones identified, the 3 lower were tested, up to 6.3 MMcfg/d on 40/64” choke (late 5.5 MMcf/d on 36/64”), no progressive pressure decrease, no water. The well is now under a 5-day pressure buildup. Winstar (op), partner KMG.

The DoE is inviting counter-proposals on 3 nominated areas for the Philippines’ conventional energy contracting programme. Three co’s have submitted LoI’s for open areas in the Sulu Sea (area 1,  14,920 sq km), off NW Palawan (area 2,  1,280 sq km) + SE Luzon (area 3,  3,440 sq km), shown in pink below. Deadline between 16-20 Aug ’19. Map extract below: GEPS.

The DoE is inviting counter-proposals on 3 nominated areas for the Philippines’ conventional energy contracting programme. Three co’s have submitted LoI’s for open areas in the Sulu Sea (area 1, 14,920 sq km), off NW Palawan (area 2, 1,280 sq km) + SE Luzon (area 3, 3,440 sq km),

Los Caldenes block, Neuquén Basin, drilled May . mid-Jun ’18, suspended w.o. test at TD 2,890m. Targets Sierras Blancas + Quintuco fm’s.

Caldenes block, Neuquén Basin, drilled May . mid-Jun ’18, suspended w.o. test at TD 2,890m. Targets Sierras Blancas + Quintuco fm’s.

ATP-1189-P / Naccowlah(a), Cooper-Eromanga, P&A’ing oil shows at TD 1,973m, Ensign rig 950. Targets Birkhead + Hutton sst. Santos (op), partners Beach, Bounty, Bridgeport + Energy World Corp.

Pallano E.-1 (Santos 55,5% (op), Beach 38,5%, Bounty 2%, Bridgeport 2%+ Energy World 2%) in ATP-1189-P / Naccowlah(a) block, P&A’ing oil shows at TD=1973m, Targets Birkhead + Hutton sst.

In late November 2019, the General Directorate of Mining and Petroleum Affairs (MAPEG) granted Turkish Petroleum Corp (TPAO) a new and exclusive exploration licence for block N46-c. The onshore licence is located in the SE Turkish province of Mardin (District X), along the border to Syria, in close proximity to a number of oil and gas fields. It will be valid for an initial five-year exploration term. <P />The acreage covers a total area of 334.74 sq km, with most of it having been licenced previously. It is largely unexplored with only a handful of wells having been drilled. So far there are no discoveries but oil shows have been encountered.<P />MCB Madencilik San. Tic. Ltd. Sti submitted the original application for the area in early February 2019, with TPAO submitting a rival application on 23 May 2019. TPAO now operates the licence with 100% equity.

Turkey, N46-C