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In late-April 2018, state company ANCAP officially declared the Uruguay Round 3 offshore bid round void after the deadline passed with no bids received. It was said that Tullow Oil (operator of Area 15 offshore block) and AziLat Petroleum submitted their documentations to qualify as operators before 6 April 2018, although no economic offers were received when the deadline passed on 26 April 2018. ANCAP is reportedly considering modifying the blocks and the terms for the future. The bid round started with a road show presented by representatives of the company and the Uruguayan Ministry of Energy in Houston, Texas in September 2017. There were 17 blocks offered, covering the offshore basins of Pelotas, Rio Salado, and Argentina Basin with areas ranging from 2,500 to 6,500 sq km. Most of the blocks are situated in shelf to deep water with depths ranging from 50 m to 3,500 m, along with few additional blocks located in ultra-deep water over 4,000 m deep. Background Information The announcement for Uruguay Round 3 was originally expected to take place in late-2014 but has been delayed several times, reportedly due to the low oil price situation.  Spectrum concluded a multi-client 3,600 km 2D seismic survey in the ultra-deep water Federal Open area of the Pelotas Basin during November 2014 to January 2015 in preparation for the bid round. This survey complements the multi-client Spectrum Recon 2D survey acquired in the same area in 2013 covering 1,625 km.

Uruguay, Area 15

It is understood that OMV Maurice Energy Ltd has discovered gas in Mitha 1 new-field wildcat (NFW) well within the Mubarak (Block 20) 2769-4 EL (Middle Indus Basin) onshore concession during late September 2018 after carrying out testing. The well was drilled to a TD of 3,610 m, reached in late August. Mitha 1 was spudded on 12 July 2018 using the Schlumberger’s SLR-15 land rig with a prognosed TD of 3,562 m in the Cretaceous. It was drilling at 1,731 m depth by the end of July 2018. The licence currently covers an area of approximately 1,000 sq km and is located in the Sindh province. The equity split for Mubarak EL is as follows: OMV Maurice Energy Ltd (57%, operator), Eni Pakistan Ltd (38%) and Government Holdings (Pvt) Ltd (GHPL) (5%). OMV had announced on 28 February 2018 that it signed an agreement with United Energy Group Ltd (UEG) for selling its upstream business in Pakistan to Dragon Prime Hong Kong Ltd (subsidiary of UEG) at an agreed sale price of USD 193 million (EUR 157 million). The agreement involves five development and production leases (D&PL) and five exploration licences (EL), including Mubarak EL. The transaction is expected to be completed by the end of 2018.   Background Information The Mubarak EL originally covered an area of 2,612 sq km and was awarded to Petronas Carigali (Pakistan) Ltd (57%, operator), Lasmo Oil Pakistan Ltd (name changed to Eni Pakistan Ltd from mid-2003) (38%) and Government Holdings (Pvt) Ltd (GHPL) (5%), on 14 April 1999. The work programme for the initial three-year exploration phase (with a minimum financial commitment of USD13 million) is believed to have included 1,000 km 2D seismic acquisition and the drilling of three exploration wells. A total of 674 km 2D seismic was acquired over the block between November 1999-February 2000 and the acquisition of a further 352.35 km 2D seismic (effectively satisfying the initial phase commitment) was completed between July-October 2001. The first well drilled by Petronas on the acreage, Rehmat 1, was suspended as a gas discovery at a depth of 3,536 m in the Lower Goru Formation in August 2001, having tested at a maximum rate of 25.6 MMcf/d through a 48/64" choke at a wellhead flowing pressure of 2,445 psi from the same formation. No gas-water contact was encountered and initial gas analysis indicated a small amount of carbon dioxide and negligible hydrogen sulphide. A second exploration well on the block, Khushbakht 1, was subsequently P&A at a depth of 2,930 m in the Lower Goru Formation in mid-December 2001 and a successful appraisal well to its earlier discovery, Rehmat 2, was suspended at a depth of 3,599 m in the Lower Goru Formation in May 2003 - the well believed to have flowed 30 MMcf/d through a 128/64" choke. Having previously been granted an extension to the end of 2002, the licence was granted an additional six month extension to the initial exploration phase with effect from 1 January 2003 and a further six week extension is believed to have been granted with effect from 1 June 2003 - presumably to allow for the drilling and evaluation of the third commitment well on the acreage. The well, Rehan 1, was plugged and suspended (pending further evaluation) on reaching a depth of 3,475 m in the Lower Goru Formation in July 2003 - good gas shows believed to have been encountered - and the licence was granted a further extension up to 30 June 2004. Petronas was awarded a Development & Production Lease - the Rehmat D&PL- over the Rehmat 1 gas discovery for a period of 13 years with effect from 22 March 2004. As a result of this, the area of Mubarak EL was reduced from the original 2,612.09 sq km to 2,398.95 sq km. An additional six month extension up to 31 December 2004 was subsequently granted to allow for a further seismic programme to be undertaken over the acreage - a total of 78.4 km 2D and 544 sq km 3D seismic being acquired between August-December 2004. The licence was granted its first one-year renewal period to the initial exploration phase with effect from 1 January 2005 - a part relinquishment of the block (319.59 sq km) also being made at the time (affecting the north western and south eastern parts of the acreage), as a result of which the licence area was reduced to 2,079.36 sq km. A six month extension (extended by a further six months and an additional seven months) was subsequently granted - presumably to allow for the drilling of the Saqib 1 well, which was prematurely P&A at a depth of 1,739 m in the Palaeocene in February 2007 following mechanical problems. The licence was granted an additional two month extension to the first one-year renewal period with effect from 11 August 2007 - presumably to allow for the drilling of a re-drill (Saqib 1A) on the acreage - and was granted its second one-year renewal period with effect from the date of rig release. The Saqib 1A well was reported to have flowed 25.15 MMcf/d and 53.3 bc/d, through an 80/64" choke, on reaching a final TD of 3,780 m in the Lower Goru Formation in February 2008. On 9 August 2009, Petronas plugged and abandoned the Putra 1 new-field wildcat as a dry hole at 3,350 m TD. The well had been spudded on 2 July 2009 with clastic objectives. The primary target of the well was the K55 and K60 sands, and although the well was untested, wireline logging was performed. All sand was logged were water wet. Petronas drilled the Saqib-2 appraisal well, which was plugged and abandoned in October 2009 after reaching a final TD of 3,550m by mid-month. It was drilled to appraise the Saqib 1A discovery. The company was granted a one-year extension to the second renewal period of the licence with effect from 25 March 2010. A Sale and Purchase Agreement between Petronas and OMV was signed on 20 September 2010, according to which OMV agreed to acquire all exploration and production interests from Petronas in Pakistan. These include the Mubarak and Mehar exploration licences and the Mehar and Rehmat (also known as Mubarak D&PL) development and production leases. The Daphro EL onshore concession, was however, not part of that deal. Following the acquisition of Petronas’ interest in the licence by OMV with effect from 11 July 2011, the equity split is as follows: OMV Maurice Energy Ltd (57%, operator), Eni Pakistan Ltd (38%) and Government Holdings (Pvt) Ltd (GHPL) (5%).  A 12-month extension to the second one-year renewal period of the licence was granted with effect from 25 March 2011. An additional six-month extension to the second one-year renewal period of the Mubarak EL was granted with effect from 25 March 2012. A third one-year renewal has been granted with effect from 25 September 2012 which also resulted in area reduction to 1,348 sq km. Towards late May 2013, OMV plugged and abandoned the Rehan 2 exploration well, after reaching a final TD of 3,550 m earlier in the month. OMV Maurice was granted a six-month extension to the third one-year renewal period of the Mubarak EL from 25 September 2013 to 24 March 2014. OMV drilled Kohar 1 new field wildcat (NFW) well in the block which was plugged and abandoned during June 2015 at a TD of 3,495 m after conducting unsuccessful drill stem test. OMV Maurice was granted an additional 12-month extension to the third one-year renewal period of the Mubarak EL effective from 25 March 2014 to 24 March 2015. It was followed by a further six-month extension effective 25 March 2015, and then an additional six-month extension from 25 September 2015 to 24 March 2016. It is understood that contract area was reduced to 1,000 sq km during 2016. OMV acquired 129 line km 2D seismic over the block during December 2016 - February 2017 period using the Bureau of Geophysical Prospecting’s (BGP) ‘BGP-2273’ seismic crew. The company was granted an 18-month extension to the third one-year renewal period of the Mubarak EL from 24 March 2016 to 23 September 2017. It was followed by a further one-year extension from 24 September 2017 to 23 September 2018.

Pakistan (Kirthar Fold Belt) Mehar

Press has been rife with reports of a super-discovery in Khuzestan, designated Namavaran and assumed made by NIOC. The massive reserves quoted (53 Bbo) are thought to be attributable to parts of the Mansuri, Sepehr, Susangerd and Ab-E-Teimur fields, in the Oligo-Miocene Gachsaran or Asmari fm's. The new reservoir would feature an already-respectable 22.2 Bbo of additional reserves, assumed to be in-place, possibly ca. 10% recovery factor.

Press has been rife with reports of a super-discovery in Khuzestan, designated Namavaran and assumed made by NIOC. The fields reservoir reportedly sits at a depth of 3100m with an average thickness of approximately 80m. The massive reserves quoted (53 Bbo) are thought to be attributable to parts of the Mansuri, Sepehr, Susangerd and Ab-E-Teimur fields, in the Oligo-Miocene Gachsaran or Asmari Fm's. The new reservoir would feature an already-respectable 22.2 Bbo of additional reserves, assumed to be in-place, possibly ~10% recovery factor.

Mari D&PL, onshore Middle Indus Basin, TD 3,936m, gas discovery + tested, w.o. results. Co. rig 3.

Tipu 1 op. by MPCL (100%) in Mari D&PL, gas discovery + tested, w.o. results. TD=3936m.

28 September 2018, Caspian Sunrise has announced signing of non-binding contracts to sell its interest in the Munayli contract area have been signed for a nominal purchase consideration. These contracts are subject to regulatory approval. The Munayli field is located in onshore southern Precaspian Basin approximately 70 km south-east of the town of Kulsary. It was discovered in 1947 and produced at low rates from 12 reservoirs in the Cretaceous to the Triassic at depths of 500-1,650 m. Roxi acquired 58.41% interest of the 0.67 sq km rehabilitation block in 2008 and funded two wells and one well re-entry. Following the Baverstock Merger, Caspian Sunrise’s interest in the Munayli Contract Area grew to 99.0% There are estimated 1.2 MMb of remaining recoverable oil reserves at Munayli. No oil was produced from Munayli in 2018. Background Information Munayli Kazakhstan LLP, the operator, holds a rehabilitation contract for the Munayli oil field. In April 2010, Munayli Kazakhstan was granted permission to proceed to a 15-year production phase of the relevant Sub-Soil User Contract. This allows production to be sold at international prices. On 2 December 2012, the operator began production from well H1. The well flowed at a rate of 125 bo/d at the time. In June 2016, Munayli Kazakhstan LLP concluded an agreement with EOR Petroleum Technology Aktobe LLP, the Chinese contractor, to re-enter up to 20 wells drilled in the Munayli field during Soviet period. The contractor was responsible for all workover costs. Any incremental production would be split on a 50:50 basis. In September 2016, EOR Petroleum Technology Aktobe LLP reentered one well in Munayli, however, no results of this work were announced at the time.

28 September 2018, Caspian Sunrise has announced signing of non-binding contracts to sell its interest in the Munayli contract area have been signed for a nominal purchase consideration. These contracts are subject to regulatory approval. The Munayli field is located in onshore southern Precaspian Basin approximately 70 km south-east of the town of Kulsary

China's CNOOC Limited has announced that the Company has recently made a mid-sized natural gas field discovery Bozhong 19-6 in Bohai Bay. Bozhong 19-6 trap is located in the southwest sag of Bozhong south central Bohai, with an average water depth of about 22 meters. The discovery well Bozhong 19-6-1 is drilled and completed at a depth of 4,181 meters and encountered oil pay zones with a total thickness of approx. 25 meters and gas reservoir with a total thickness of about 348 meters. The evaluation well was tested to produce about 1,000 barrels of oil and 6.4 million cubic feet of natural gas per day. Mr. Xie Yuhong, Executive Vice President of the Company and General Manager of Exploration Department commented: 'The natural gas field discovery of Bozhong 19-6 demonstrates the good prospects of buried hills for future gas exploration of Bohai Bay and lays a solid foundation for Company’s quality clean energy supply for Beijing-Tianjin-Hebei region'. Original article link Source: CNOOC Limited

Bozhong 19-6 (Bo) 1 (BZ 19-6-1) op. by CNOOC (100%) in Bozhong Block, medium-size hc field discovery, 25m oil pay + 348m gas pay in a pre-Tertiary buried hill reservoir. The evaluation well was tested to produce about 1000 bo/d and 6,4 MMscfg/d.

In the first quarter of 2020, Bashneft-subsidiary Sorovskneft discovered a new oil pool in the Unlorskoye Vostochnoye field in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Wildcat Unlorskaya Vostochnaya 11 tested oil at a rate of 125 b/d and gas at a rate of 1.3 MMscf/d through a 12 mm choke from the Tyumen Formation Unit Yu2 (Middle Jurassic) perforated at 2,831-2,840 m. IHS Markit estimates 3P reserves of the new pool at 153 MMbbl of oil. Unlorskoye Vostochnoye, located in the Ural-Frolov Province, was discovered in 2018 when Unlorskaya Vostochnaya 11 tested oil at a rate of 35 b/d from the Tyumen Formation Unit Yu7. IHS Markit estimated 3P reserves of the reservoir at 26 MMbbl of oil. Bashneft is owned by Rosneft.

Unlorskaya Vostochnaya-11 npw. (Bashneft 100%), Unlorskoye Vostochnoye field area, onshore, Khanty-Mansiysk AO, Unlorskiy Vost. Block, W. Siberia, tested 125 bo/d + 1.3 MMcfg/d on 12mm choke from the Tyumen Unit Yu2 between 2831-2840m. 3P reserves of the new pool est. 153 MMbo.

On 7 June 2018, the consortium of Petrobras with 30% working interest, ExxonMobil with 28%, Statoil with 28%, and Petrogal with 14%, was granted a preliminary award of the Uirapuru block from the 4th PSC Pre-Salt Bid Round.  There were three other bids for the Santos Basin block by Petrobras led consortiums. The Uirapuru block was the most contested block in the bid round with four bids and a first for the PSC bid rounds with a consortium without Petrobras winning the bid offering more state take than the Petrobras led consortium.   The consortium of ExxonMobil, Statoil, and Petrogal offered a state take of 75.49% while the Petrobras led consortium of Petrobras with 45%, Total with 20%, and BP with 35% bid 72.49% state take.  As a result Petrobras had to make a decision to join the winning consortium and take its minimum 30% working interest resulting in Petrobras as the operator with 30%, ExxonMobil with 28%, Statoil with 28%, and Petrogal with 14%.  There were two other bids by Petrobras led consortiums.  The third place bid was Petrobras 30%, Chevron 20%, Shell 30%, and QPI 20% who bid a state take of 72.05%.  The fourth place bid for the block was Petrobras with 30%, CNODC with 30%, and CNOOC with 40% that bid a state take of 68.15%.  The consortium will pay a fixed signing bonus of USD 736.11 million, at 1 USD to 3.60 BRL, and has estimated minimum investment guarantees of USD 68.33 million. The Uirapuru block covers an area of 1,285.33 sq km and the minimum state take was set at 22.18% for the PSC contract.

the consortium of Petrobras with 30% working interest, ExxonMobil with 28%, Statoil with 28%, and Petrogal with 14%, was granted a preliminary award of the Uirapuru block from the 4th PSC Pre-Salt Bid Round.

Terra Nova is looking to dilute its 51.5% interest in PEL 112 + 444, total 2,255 sq km in the Cooper-Eromanga. Both contain a number of prospects. Terra Nova (op), partner Holloman Petroleum. Contact: [email protected].

Terra Nova is looking to dilute its 51.5% interest in PEL 112 + 444, total 2,255 sq km in the Cooper-Eromanga. Both contain a number of prospects. Terra Nova (op), partner Holloman Petroleum. Contact: [email protected].

PEMEX plugged and abandoned dry the Yok 1EXP new-field wildcat (NFW) in the AE-0024-2M-Okom-07 block entitlement block during late-January 2019. The final total depth (TD) was 4,899 m. The NFW was spudded on 24 May 2018. The well had a proposed total depth (PTD) of 4,950 m and the primary target was the Cretaceous. The well was drilled by the “Prospector II” J/U in a water depth of 28 m. The well is located in the west central area of the block approximately 6.3 km south-west of the Cheek 1 ST completed as an oil and gas discovery in 2014. The drilling permit for the well was granted on 22 December 2017. PEMEX estimated unrisked prospective resources for the project at 41 MMboe. SENER awarded the AE-0024-2M-Okom-07 block entitlement block to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 965.63 sq km.

Yok 1EXP (NFW) (Pemex 100%) in the AE-0024-2M-Okom-07 block entitlement block, P&A dry.

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

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

Petronas has acquired a 45% stake from operator Repsol in the Sakakemang PSC in S. Sumatra, following on from Medco who took 10% during the summer. Govt approval is required for the deal to complete, after which partnership in the 1,607-sq km block will be Repsol (op), Petronas + Moeco.

Indonesia, Sakakemang PSC

Linggao 35-2-1 (LG 35-2-1) was suspended (results TBC) on or around 20 December 2018 after having been spudded on or around 10 December 2018 using the "Nanhai 7" semi-sub. The gas exploration well was likely targeting the Huangliu Formation. Linggao 35-2-1 is in the CNOOC operated Linggao 15 Block in the offshore Yinggehai Basin. <P />

Linggao 35-2-1 (LG 35-2-1) was suspended (results TBC)

Ras Al Khaimah Petroleum Authority (RAKPA) assisted by national oil company RAK Gas LLC is re-offering the 769 sq km onshore Block 6 with extensive mountain front acreage contiguous to Oman and 430 sq km inland onshore Block 7 for participation. Existing vintage 2D seismic and Full Tensor Gravity (FTG) data is in the process of being supplemented by two new 2D & 3D surveys which are now scheduled for completion during 2H 2020. Interested parties should contact [email protected] for additional details. Blocks 6 and 7 were originally included in the Ras Al Khaimah License Round 2018 (also termed the RAK-2018 Bid Round) which launched on 1 March 2018 and closed in mid-November 2018. PGNiG was subsequently awarded one block (Block 5) as part of the formal bid round, while Eni reached an agreement to acquire consolidated offshore acreage (Blocks 1-4) following the closure of the round. Bid round data rooms had been opened in Ras Al Khaimah and Henley-on-Thames (ERCL UK offices) on 1 January 2018. Ras Al Khaimah is one of the seven emirates that comprise the United Arab Emirates (UAE).

United Arab Emirates former 2018 round onshore blocks 6 (769 sq km) & 7 (430 sq km) are being re-offered.

ONGC Videsh and Uzbekneftegaz (UNG) have signed a co-operation Agreement and a Confidentiality Agreement providing for joint preparation of specific proposals for co-operation through the exchange of information on the investment blocks in Uzbekistan within 4 months. The agreements were signed during President of Uzbekistan’s visit to India on 30 September – 1 October 2018. Uzbekistan offers 22 E&P investment blocks across all its petroleum basins on an open negotiations basis. Background Information This is not the first time that ONGC attempts to enter Uzbekistan. In May 2011, UNG and ONGC signed a co-operation memorandum on a possible 5-year exploration programme for the Middle Syr-Darya area (part of the Syr-Darya Basin). The preliminary studies were supposed to take 6 months, however, there have been no announcements of a concrete deal having been reached. Most of the Syr-Darya Basin is located on the territory of Kazakhstan, and only the basin’s south-western and southern margins fall within Uzbekistan. There are no existing discoveries in the basin in either of the countries. The 2011 agreement also provided for ONGC and UNG to co-operate in increasing production from low productivity wells. The project was to be funded from the Export-Import Bank of India’s USD 2 billion loan to Uzbekistan. In November 2013, ONGC and Petrovietnam Exploration & Production (PVEP) signed an MoU regarding joint development of the Kossor investment block in western Uzbekistan (Daryalyk-Daudan Depression). As part of the document, ONGC was supposed to present its proposals for the project in Q1 2014, however, no progress has been reported regarding this potential deal either. It is understood that PVEP has drilled at least one unsuccessful exploration well in the Kossor block.

ONGC Videsh and Uzbekneftegaz (UNG) have signed a co-operation Agreement and a Confidentiality Agreement providing for joint preparation of specific proposals for co-operation through the exchange of information on the investment blocks in Uzbekistan within 4 months.

AziNor Catalyst is farming down material equity in return for a significant portion of its interest in licence P2316 which contains the Marshall prospect. The licence was awarded in the 29th Licensing Round in May 2017. AziNor has calculated the prospect to hold 145 MMboe (Pmean) recoverable resources with an upside of 296 MMboe (P10). Reprocessed 3D Broadband Geostreamer seismic has allowed detailed mapping and visualisation of the Marshall prospect. An exploration well is planned for 2019 targeting the Sgiath paralic sands to a depth of 1,800 m TVDSS. As of February 2019, the opportunity was still available. Marshall is geographically located in the NW Witch Ground Graben up-dip from the Brule discovery. The prospect is on trend with Claymore, Piper and Highlander which all produce from Upper Jurassic reservoirs. Reactivation of the fault blocks throughout the Upper Jurassic resulted in a series of NW-SE trending rotated tilted fault blocks which form the trapping mechanism. The primary reservoir objectives consist of the Upper Jurassic Sgiath and Piper reservoir sands. The Sgiath Formation consists of sandstones deposited in a Deltaic / Coastal Plain environments in a series of fluvial distributary channels. The reservoir is interpreted to have moderate to good characteristics from the 14/14-1 well located immediately south of the acreage. The Piper Formation consists of offshore transition zone mudstones locally to the Marshall prospect with the shoreface reservoirs being limited to the east of the licence where they form the primary targets in the Mount prospect. AziNor have carried out recent seep studies and identified a potential local source kitchen in a restricted pull apart basin immediately to the east. Wells 14/10-1 and 14/10a-2 were both drilled on the flanks of this mini-basin and both encountered shows in the Upper Jurassic sands adding further evidence of a locally mature kitchen. Interest in P2316 is held by AziNor Catalyst Ltd (100%). For further information please contact: Nick Terrell Tel+44 (0)20 3588 0065 Email: [email protected]

AziNor Catalyst is farming down material equity in return for a significant portion of its interest in licence P2316 which contains the Marshall prospect. The licence was awarded in the 29th Licensing Round in May 2017. AziNor has calculated the prospect to hold 145 MMboe (Pmean) recoverable resources with an upside of 296 MMboe (P10).

On 18 March 2019, IEOC (Eni) temporary abandoned the Meleiha Southwest A3 exploration well in the onshore Southwest Meleiha block after reaching a depth of 5,134 m in the Desouqy formation. The well was spudded on 17 December 2018 with the Sino Tharwa’s “ST-12” land rig.  It had a planned TD of 5,150 m and objectives in the Albian Alam El Bueib 3D Unit and the Carboniferous Desouqy formation. IEOC operates the block with a 100% interest. Background Information On 25 September 2014, Eni announced that it was awarded the onshore block Southwest Meleiha as a result of the 2013 EGPC International Bid Round. The block is located in Egypt’s Western Desert, near the Meleiha Development Lease. The original license covers 2,058 sq km. In late February 2017, IEOC (Eni) completed its 673 sq km 3D and 135 km 2D seismic surveys over the onshore Southwest Meleiha block. BGP, the contractor, started the surveys on 2 December 2016 and 13 February 2017 respectively. In December 2018, IEOC (Eni) abandoned the Meleiha Southwest A1 (Id 11-2) exploration well in the onshore Southwest Meleiha block as a dry hole after reaching a TD of 5,134 m in the Desouqy fomration. The well was spudded on 5 October 2018 with the “EDC-41” land rig.

IEOC (Eni) temporary abandoned the Meleiha Southwest A3 exploration well in the onshore Southwest Meleiha block after reaching a depth of 5,134 m in the Desouqy formation.

Add. DEA 1 Mar ’18 : La Cira-Infantas field area, Midldle Magdalena Basin in Santander, TD 1,237m, 15m potential oil pay below 600m, tested 250 b/d of 33 API oil. Target Mugrosa fm. Ecopetrol (op), partner Oxy. Re. the other 2 discoveries reported (REX NE-1 & Cosecha V-1): - REX NE 1 ST2 nfw, Cosecha block, Llanos Basin, encountered 20m oil sst below 2,500m (likely in target Carbonera), tested 2,000 b/d of 35 API oil. Oxy (op), partner Ecopetrol.   - Cosecha V-1 nfw, Cosecha block, 4m oil sst in the L. Carbonera target below 2,600m, tested 600 b/d of 31 API oil.

Infantas Oriente 1 op. by Ecopetrol (52%, Oxy 48%) in La Cira-Infantas field area oil disc. encountered some 15m of potential oil pay below 600m, combined tests totaled 250 b/d of 33°API oil from Target Mugrosa fm.

Aker BP completed the acquisition of Hess's Norwegian subsidiary Hess Norge on 22 December 2017. The deal was first announced on 24 October 2017 and is backdated to 1 January 2017. Hess will receive US$ 2 billion cash consideration however Aker BP will benefit from Hess Norge's tax loss carry forward, nominally valued at US$ 1.5 billion after tax. The deal comprises PL033, PL006 B & PL033 B containing the producing Hod and adjacent Valhall oil fields, in the Southernmost Norwegian North Sea on the Norway-Denmark border. Hod production commenced in September 1990 from Late Cretaceous Hod & Tor formations and the Early Paleocene Ekofisk Formation, having original recoverable volumes of 80.8 MMboe and has produced 75.3 MMboe to end 2016. Valhall production commenced in October 1982 from Late Cretaceous Hod and Tor formations, with original recoverable volumes of 1,136.5 MMboe and has produced 899 MMboe to end 2016. The deal also includes 15% in Statoil operated 15th Round 1996 award PL220 (248 sq km) in the Northern most Norwegian Sea, currently under extension after drilling 6710/10-1 (2000, Den norske, 2,267m TVD) which was P&A dry. Hess previously held 64.05% in PL006 B (Hod) and 62.5% in PL033 & PL033 B (Valhall) and after becoming 100% operator Aker BP concluded on the same date the sale of 10% in both licences to Pandion Energy. Hess is also selling its Danish subsidiary which includes 61.5% operator share of South Arne oil field.

Aker BP (->100%) completed the acquisition of PL 006 B, PL 033, PL 033 B & PL 220 blocks from Hess for US$1,5 billion.

In September 2019 Overgas was still offering the opportunity for interested parties to farm-in to licences Provadia and 1-18 Trakiya. The Provadia licence is located in the eastern part of the country while the 1-18 Trakiya licence is situated in southern Bulgaria. The company started looking for partners in May 2016. Between 2011 and 2014 Overgas conducted two 2D seismic surveys and one 3D seismic survey totaling respectively 812 km and 55 sq km in the Provadia licence. No fields are situated within the permit area. The last known drilling activity consists of Krivnya 12 which was drilled to a total depth of 2,769 m in the Lower Triassic and abandoned as a dry hole in 1984. In the 1-18 Trakiya licence, the company drilled the Trakiya 1 exploration well between 2014 and 2015. The hole reached a total depth of 1,717 m bottoming in metamorphic rocks without reaching the targeted Jurassic sediments. It was subsequently re-entered for testing and recovered only gas shows. In late 2012 Overgas conducted a 474 km 2D seismic survey in the permit. For further information please contact: Dimitar Merachev Tel - +359 2 865 11 99 [email protected]

Overgas Inc AD Provadia and 1-18 Trakiya - Farm-in opportunity

Mumbai High NW Extn. (Add.) ML-Saurashtra block, Bombay offshore, susp. at TD 2,675m, Sagar Vijay released from location 3 Jan '20, now reported an o&g find, tested 535 bo/d + 7.75 MMcfg/d from the Bassein fm and 819 bo/d + 613 Mcfg/d from the Mukta fm.

B-218 A nfw (ONGC 100%) in NW Extn. (Add.) ML-Saurashtra block, Bombay offshore, susp. at TD= 2675m, reported an o&g find, tested 535 bo/d + 7,75 MMcfg/d from the Bassein Fm. and 819 bo/d + 613 Mcfg/d from the Mukta Fm. & B-219 A tested 204 bo/d + 1,7 MMcfg/d from multiple intv's.

Petronas is looking into a possible sale of its 35% interest in the Exxon-operated, 493-sq km Chari licence from which Exxon (40%) is also doing likewise. The project includes a pipeline to Cameroon. Currently ExxonMobil (op), partners Petronas + state SHT.

Petronas is looking into a possible sale of its 35% interest in the Exxon-operated, 493-sq km Chari licence from which Exxon (40%) is also doing likewise. The project includes a pipeline to Cameroon. Currently ExxonMobil (op), partners Petronas + state SHT.

The Minister of Mines, Industry and Energy of Equatorial Guinea H.E. Gabriel Mbaga Obiang is planning to launch a new oil and gas exploration licensing round in January 2019, the oil Minister reported in early September 2018. He 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 was certainly linked to stagnant mega-projects like Ophir’s Fortuna FLNG, likely to collapse 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.

Equatorial Guinea, Zafiro

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

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

On 19 October 2018 the results of the Aker BP, Gekko appraisal wells (25/4-13 S and A) was reported by the NPD. Well 25/4-13 S was located on the south of the structure and encountered a 43 m oil and gas column in the Hemidal Formation of which 6.5 m was oil. Almost the entire interval comprised of very good to excellent reservoir quality sandstones. The gas/oil contact was recorded at 2,100 m and the oil/water contact was measured at 2,107 m (TVD). 24/4-13 S had its top hole section drilled between 6 and 18 June 2018. The well was re-entered on 15 September 2018 and drilled to a TD of 2,653 m (Hemidal Formation). Sidetrack well 25/4-13 A drilled north on the structure encountered a 30 m oil and gas column also in the Hemidal Formation of which 6 m was oil. Approximately 15 m of net reservoir was very good to excellent quality. The thickness of the oil zone is uncertain due to the variations in reservoir quality. 25/4-13 A was kicked-off on the 29 September 2018 and reached a TD of 2,641 m (Hemidal Formation). Drilling operations were undertaken by the “Deepsea Stavanger” S/S and the wells have been plugged and abandoned. Following appraisal operations Gekko is thought to hold 9 MMbo and 173 Bcf (total of 38 MMboe recoverable). The licensees are considering a tie-back to the Alvheim FPSO. Gekko was discovered in 1974 by Elf’s exploration well 25/4-3. The well proved a 3 m gas column plus a 5 m oil column in the Paleocene Heimdal Formation. In 2003 the discovery was appraised by Marathon with 25/4-8 which was located updip, approximately 1.7 km to the northwest of the discovery well. This well confirmed a 9 m gas column above a 7 m oil column in the Heimdal Formation and also encountered gas in the Paleocene Lista Formation. The NPD quotes recoverable reserves of 22 MMboe for Gekko (December 2016). Gekko is located across blocks 25/4 and 25/7 in PL 203. Aker BP ASA operates PL 203 with a 65% interest. It is partnered by ConocoPhillips Skandinavia AS (20%) and Lundin Norway AS (15%).

025/04-13 S, A (Gekko) (Aker BP 65%, ConocoPhillips 20%, Lundin 15%) in PL 203 (Alvheim field area), P&A, Ø 025/04-13 S (southern flank of structure), 43m hc column in the Heimdal fm of which 6.5m oil, GOC at 2100m, PWC at 2106.5m

Nestoil is looking to sell part of its 80% equity in the Neconde special purpose vehicle, itself 45% owner/optr of OML 42, 814 sq km onshore in the W. Delta. Neconde took on Shell, Total + ENI’s 45% in the block in 2012, the balance held by NPDC.

Nestoil is looking to sell part of its 80% equity in the Neconde special purpose vehicle, itself 45% owner/optr of OML 42, 814 sq km onshore in the W. Delta. Neconde took on Shell, Total + ENI’s 45% in the block in 2012, the balance held by NPDC.

Neptune spudded Dugong prospect exploration well 34/4-15 S using the “Deepsea Yantai” S/S on 18 June 2020. The prospect lies in PL 882, approximately 9 km northwest of Snorre B. The well’s objectives are the Upper Jurassic Intra-Draupne Formation and the Middle Jurassic Brent Group. Neptune confirmed that hydrocarbons have been found in the reservoir which lies between 3,250 m and 3,400 m. The well has been cored and on 9 July 2020 the company is preparing for a down-dip appraisal sidetrack – 34/4-15 A. The TD of 34/4-15 S (actual depth not yet reported) was planned at 3,740 m (3,647 m TVD). According to partner Petrolia, potential pre-drill recoverable resources were 86 MMboe. 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.

Norway (Viking Graben Province), 34/4-15 S (Dugong) explo well, in PL 882, op. by Neptune (40%), CONCEDO (20%), IDEMITSU (20%), PETROLIA (20%). Neptune confirmed on 3 July 2020 that hydrocarbons have been found in the reservoir which lies between 3,250 m and 3,400 m. The well will be cored and a contingent down-dip appraisal sidetrack is likely. The TD of 34/4-15 S is planned at 3,740 m (3,647 m TVD). Preparing to sidetrack

Petrobras is offering equity in offshore Pelotas Basin contract BM-P-002 (P-M-1269, 1271, 1351 + 1353 blocks, total 2,600 sq km), EoI deadline originally 23 Dec ’19, now 15 Jan ’20. Total partners Petrobras with 50%.

Petrobras is offering equity in offshore Pelotas Basin contract BM-P-002 (P-M-1269, 1271, 1351 + 1353 blocks, total 2,600 sq km), EoI deadline originally 23 Dec ’19, now 15 Jan ’20

Coro Energy (formerly Saffron Energy in Italy) has signed conditional agreements for its 1st Indonesian asset, a 42.5% stake from AWE in the 698-sq km Bulu PSC off East Java for USD 10.96 MM plus re-imbursements of ab. USD 1.04 MM. The block contains the Lengo gasfield, for which an FDP has already been approved by the authorities. Partners-to-be KrisEnergy (op), HyOil, Coro, Satria Energindo + Satria Wijaya Kusuma.

Coro Energy (formerly Saffron Energy in Italy) has signed conditional agreements for its 1st Indonesian asset, a 42.5% stake from AWE in the 698-sq km Bulu PSC off East Java for USD 10.96 MM plus re-imbursements of ab. USD 1.04 MM.

Further to the announcement by RockRose Energy on 9 August 2018 where it agreed to acquire Dana Petroleum’s 20.43% in the Arran North field which is part of the Arran development along with Arran South the company notes that it has agreed a further deal to acquire another 10% interest in the development. The fields are located in blocks 23/11a (P1051), 23/16b (P1720) and 23/16c (359) in the Central North Sea. The field development is likely to be a tie-back to the Shell operated Shearwater Platform. On 10 October 2018 RockRose announced that the acquisition of 20.43% from Dana has completed. Additionally RockRose announced on 10 October 2018 that a final investment decision for the development of Arran has been made. Shell is to become operator of the project. The plan is to develop the fields via two drill centres (North and South) with two wells on each, tied-back to the Shearwater facilities in block 22/30 via the Scoter riser. A new 60-km pipeline will be installed between Shearwater and Arran. Work is scheduled to start on the development later in 2018 with development drilling commencing in Q3 2019. First production is targeted for late 2020 and life of the field is expected to be 12 years. Arran is expected to produce 100 MM cf/d of gas and 4,000 b/d of condensate which when combined is 21,000 boe/d. The Arran fields were previously called Phyllis and Barbara. The reservoir is Paleocene Upper and Lower Forties sandstones around a salt diapir. Plans were originally in place for development in 2010, when a unitised agreement was set up and in June 2010, Serica reported that an agreement had been reached between the operators of Lomond, Columbus and Arran on a FEED for a bridge linked platform on Columbus that would connect with the Lomond platform. An ES was submitted in July 2010, which included plans for three production wells and two drill centres on the Arran development. A drill centre was to be located on both Arran North and South. Two wells were to be drilled on Arran South and one on Arran North. Arran North was to be linked to South via a 7-km pipeline, which was to be linked in turn to a new riser Bridge Linked Platform (BLP) adjacent to the Lomond platform 21-km to the south. The drill centres were to have the capacity for two additional wells each. Development was originally expected to start (with modifications to host infrastructure) in February 2011 and drilling was expected to run from July 2011 until February 2012. First gas was initially expected December 2012. In March 2013 BG informed Serica that it would not be proceeding with the construction of a BLP to the Lomond field. Following full completion of the deals RockRose Energy will hold a 30.43% interest in the Arran development.

Further to the announcement by RockRose Energy on 9 August 2018 where it agreed to acquire Dana Petroleum’s 20.43% in the Arran North field which is part of the Arran development along with Arran South the company notes that it has agreed a further deal to acquire another 10% interest in the development.

Ledong block, Yinggehai Basin SW of Hainan, WD 90m, target HPHT Pliocene-Miocene gas, ops terminated mid-Apr ’18, results n/a, Kantan 3 SS.

Ledong 2-1-1 (LD 2-1-1) nfw Ledong block, Yinggehai Basin SW of Hainan, WD 90m, target HPHT Pliocene-Miocene gas, ops terminated mid-Apr ’18, results n/a, Kantan 3 SS.

On 9 December 2019, the Federal Agency for Subsoil Use held an auction for three blocks in Krasnoyarsk Kray (Eastern Siberia). Rosneft emerged as the winner of the three blocks and will obtain 27-year E&P licenses including a 7-year exploratory stage. The Mezeninskiy block covers 2,032 sq km in the Yenisey-Khatanga Basin. No wells have been drilled in the block. Reservoirs of the Mesozoic section are the main exploratory targets. Hydrocarbon resources (categories D1+D2) of the block are estimated at 33 MMbbl of oil and 891 Bcf of gas. The starting price amounted to RUB 9.4 million (USD 0.15 million). Rosneft offered RUB 2,605.7 million (USD 41.6 million). The Yangodskiy block covers 2,976 sq km in the Yenisey-Khatanga Basin. No wells have been drilled in the block. Reservoirs of the Mesozoic section are the main exploratory targets. Hydrocarbon resources (categories D1+D2) of the block are estimated at 10 MMbbl of oil and 945 Bcf of gas. The starting price amounted to RUB 5.9 million (USD 0.09 million). Rosneft offered RUB 2,180.6 million (USD 33.265 million). The Dzhangodskiy Severnyy block covers 1,363 sq km in the Yenisey-Khatanga Basin. No wells have been drilled in the block. Reservoirs of the Mesozoic section are the main exploratory targets. Hydrocarbon resources (categories D1+D2) of the block are estimated at 11 MMbbl of oil and 685 Bcf of gas. The starting price amounted to RUB 4.7 million (USD 0.07 million). Rosneft offered RUB 1,302.8 million (USD 19.4 million)

Rosneft won 3 block: Dzhangodskiy Severnyy (1,363 sq km), Mezeninskiy (2,032 sq km), Yangodskiy (2,976 sq km) in the Yenisey-Khatanga Basin, Krasnoyarsk Kray.

East Jabung block in S. Sumatra, P&A'ing o&g shows mainly in the Gumai, TD 1,233m (basement). Targets Batu Raja, Gumai + Air Benakat fm’s. Repsol (op), partner Pan Orient Energy. The latest results will likely endorse Repsol's intentions to exit the 1,236-sq km block next month.

Indonesia (S.Sumatra) Anggun 1X nfw. (Repsol (op), partner Pan Orient Energy) in East Jabung block, P&A, o&g shows mainly in the Gumai, TD 1233m (basement). Targets Batu Raja, Gumai + Air Benakat fm’s. The latest results will likely endorse Repsol's intentions to exit the 1236-sq km block next month.

Petro Brunei has extended the deadline for the 2,222-sq km onshore/offshore block L offered under the 2018 round. Data viewing now expires 7 November (formerly 12 October), and submission of bids now 8 November (previously 15 October). Address: Brunei National Petroleum Company Sdn Bhd, 2nd Floor, Block A, B & C, Yayasan Sultan Haji Hassanal Bolkiah Complex, Jalan Pretty, Bandar Seri Begawan BS8711, Brunei Darussalam. Tel. +673-2230720 ext 295 or 302), email [email protected].

Petro Brunei has extended the deadline for the 2,222-sq km onshore/offshore block L offered under the 2018 round. Data viewing now expires 7 November (formerly 12 October), and submission of bids now 8 November (previously 15 October).

Simba block, Gabon Coastal Basin, P&A dry at TD 2,600m mid-Jan ’19, Borr Norve JU off to the Ompoyi field (Gombe Sud block). Target assumed Madiela or Cap Lopez fm’s. Perenco (op), partner Tullow.

Gabon (North Gabon Sub-basin (Gabon Coastal B.)) Ompoyi

In late September 2018, Orinoco Natural Resources acquired Samsung Oil & Gas USA's entire 20% WI in Mississippi Canyon Block MC 21 (G28351), situated in the Louisiana Coastal Basin. The transaction is effective as of 1 August 2018. Following completion of the transaction, equity in MC 21 is now shared between ANKOR E&P Holdings (KNOC local subsidiary, 50.5% WI + Op), KOA Energy (29.5%) and Orinoco Natural Resources (20%).

Orinoco Natural Resources acquired Samsung Oil & Gas USA's entire 20% WI in Mississippi Canyon Block MC 21 (G28351), situated in the Louisiana Coastal Basin

In November 2018, the Government of Russia had registered seven new licenses awarded in the Volga-Ural Province and the Yenisey-Khatanga Basin. Bashneft obtained two five-year exploratory licenses in Bashkortostan Republic (Volga-Ural Province) offered in September 2018: The Abdulovskiy block (UFA02445NP) covers 75 sq km. Its oil resources are estimated at 10 MMbbl. The Mancharovskiy block (UFA02446NP) covers 284 sq km. Its oil resources are estimated at 11 MMbbl. Company NovoKhim obtained two seven-year exploratory licenses in Krasnoyarsk Kray (Yenisey-Khatanga Basin), also offered in September 2018: The Malo-Balakhninskiy block (KRR03109NP) covers 5,702 sq km. Its hydrocarbon resources are estimated at 234 MMbbl of oil and 3.083 Tcf of gas. The Bolshe-Balakhninskiy block (KRR03110NP) covers 5,681 sq km. Its hydrocarbon resources are estimated at 208 MMbbl of oil and 2.997 Tcf of gas. Three long-term licenses were registered based on results of auctions held in October-November 2018. Detailed information regarding the auctions and blocks may be found in the Pre-Award section of GEPS. Udmurtia-registered company Sabunskiy secured two licenses in Samara Oblast (Volga-Ural Province): The Matyanovskiy block (SMR02257NR) covers 528 sq km in the southwestern flank of the Tatarskiy Yuzhnyy Dome and encompasses the Bugulminskiy, Nabokovskiy, Suvarskiy, Khersonskiy and Lefanovskiy Yuzhnyy prospects with combined oil resources estimated at 20 MMbbl. Seismic coverage amounts to 1,320 km. 28 exploratory wells have been drilled in the block. Hydrocarbon resources (category D1) of the block are estimated at 50 MMbbl of oil and 3 Bcf of gas. The Podkolskiy block (SMR02258NR) covers 178 sq km in the northern part of the Buzuluk Depression and encompasses the Uvarovskiy Severnyy and Podkolskiy prospects and a part of the Ostrogorskiy prospect. Combined oil resources of the prospects are estimated at 6 MMbbl. Five exploratory wells have been drilled in the block. Hydrocarbon resources (category D1) of the block are estimated at 26 MMbbl of oil and 17 Bcf of gas. Gazprom Neft-Aero Bryansk registered license KRR03111NR in Krasnoyarsk Kray. The Leskinskiy block covers 3,027 sq km in the Yenisey-Khatanga Basin with some extension into the South Kara-Yamal Province. Seismic coverage amounts to 288 km. No wells have been drilled in the block. Hydrocarbon resources (category D2) of the block are estimated at 73 MMbbl of oil and 3.9 Tcf of gas.

Russia, KRR03111NR

In an attempt to secure a new operator, the authorities are reportedly inviting offers for Total-Eni's Kombi-Likalala-Libondo II two-block contract which expires in July. Involved are 165 sq km of shelf rights, bids for which are being accepted through end April. Of note, Eni's neighbouring units (Loufika-Tioni onshore, Zingali shallow water, all producing) also expire this summer but are extendable, therefore not necessarily to follow the same path as KLL.

Congo, Zingali (Kouilou)

NW sector of Tahe field in Tarim Basin, ops terminated Jun ’18, no results. Target deep Ordovician.

Tashen-6 expl, NW sector of Tahe field in Tarim Basin, ops terminated Jun ’18, no results. Target deep Ordovician.

OGDC secured sole rights to this 9.7-sq km devt licence around the 2017 Dhok Hussain gas-cond discovery (in the then so far undrilled) Baratai 3371-17 EL, Potwar Basin. The well had tested 15.4 MMcfg/d + 360 bc/d from the Lumshiwal + Paleocene Hangu fm’s. OGDC (op), partner Khyber Pakhtunkhwa O&G.

Pakistan, Baratai 3371-17 EL

In April 2019, it was reported that Royal Dutch Shell plc signed a Memorandum of Understanding (MoU) with the Zanzibar authorities for the Blocks 9, 10, 11 and 12, offshore Tanzania Basin. Initial PSA negotiations with the authorities were concluded on 6 June 2003. Background Information The Tanzania Second Offshore Licensing Round was launched at the AAPG convention in Denver on 3 June 2001. Seven new blocks were on offer, i.e. one in shallow waters south of Zanzibar (Latham) and six in deep waters off the Pemba and Zanzibar islands (Area-7, Area-8, Area-9, Area-10, Area-11 and Area-12). In addition, five blocks which received no bids in the Tanzania First Offshore Licensing Round were re-offered (Area-1, Area-2, Area-3, Area-4, Area-6). In total, acreage available for bidding covered 114,123 sq km. TPDC announced on 5 September 2002 that, upon evaluation of bids by a technical committee, Shell Exploration did meet basic requirements of the bidding instructions relevant to the licensing round contrary to Global Resources. Both companies had filed separate bids for Area 9, Area 10, Area 11 and Area 12. The round closed on 5 July 2002. Shell Exploration submitted a viable exploration programme, probably starting with 2D seismic acquisition, satisfactory financial guarantees and recognizable technical competence in deepwater exploration. In consequence, the technical committee and the tender committee recommended to invite Shell Exploration for PSA negotiations on blocks 9-12. On 14 January 2003, the government of Tanzania and TPDC held the first round of negotiations (three days) with representatives of Shell.

Tanzania, not found

Wu 1 flowed at an average rate of approximately 120 bc/d from two intervals in the Jurassic sandstone in mid-November 2017. Wu 1 was spudded in August 2017 and was drilled to a TD of 2,030m MD on 19 September 2017, having encountered strong gas shows while drilling from 1,529m. Wu 1 had a PTD of 2,150m and was targeting the Jurassic interval with the objective of exploring the hydrocarbon potential of the Wulan Structure in the southern Hongciliang Structural Area, Yabrai Basin. Wu 1 is in the PetroChina operated Yabrai Basin Block in the Yabrai Basin and is geographically located in Gansu Province, Minqin County, Donghu Town, Zhengxin Village.

Not Found

On 24 March 2020, industry sources reported that the schedule of the 6th Licensing Round could be communicated before the end of March 2020. Provisional plans anticipate nine offshore blocks (in the Zambezi Deep Sea Fan and the Zambezi Delta) and one onshore block (North of Maputo, in the Mozambique Basin) to be on offer. The National Petroleum Institute (INP) had reported at the Africa Oil Week held in Cape Town in early November 2019 that it was expecting to launch the 6th Licensing Round in late Q1 2020. In November 2018, CGG reported that the fast-track 3D multi-client survey acquired in the Zambezi Delta was available to interest companies. The 15,400 sq km 3D survey started in October 2017 and covers the Areas Z5-C and Z5-D and the open areas nearby. Background Information The 6th Licensing Round was initially expected in 2019. INP revealed the names of the winners of the Mozambique Fifth Licensing Round in October 2015. A total of fifteen areas were included in the licensing round and after evaluation of the bids, six blocks were awarded. Three offshore licences were awarded to ExxonMobil with Rosneft, one offshore licence was awarded to a consortium led by Eni that includes Sasol Ltd. and Statoil, Sasol was awarded an onshore block and Delonex Energy with its partner India Oil, were awarded an onshore block. Canadian Overseas Petroleum has been invited later to discuss with the Government of Mozambique about the terms for the Block PT5-B, onshore Mozambique.

nstituto Nacional de Petroleo planning 6th Licensing Round Mozambique On 24 March 2020, industry sources reported that the schedule of the 6th Licensing Round could be communicated before the end of March 2020. Provisional plans anticipate nine offshore blocks (in the Zambezi Deep Sea Fan and the Zambezi Delta) and one onshore block (North of Maputo, in the Mozambique Basin) to be on offer. The National Petroleum Institute (INP) had reported at the Africa Oil Week held in Cape Town in early November 2019 that it was expecting to launch the 6th Licensing Round in late Q1 2020. In November 2018, CGG reported that the fast-track 3D multi-client survey acquired in the Zambezi Delta was available to interest companies. The 15,400 sq km 3D survey started in October 2017 and covers the Areas Z5-C and Z5-D and the open areas nearby. Background Information The 6th Licensing Round was initially expected in 2019. INP revealed the names

Canacol Energy, which in December 2019 secured a 100% working interest in the Lower Magdalena Valley Basin VIM-33 Block, will acquire 62 sq km of 3D seismic and drill one exploration well during Phase 1. The company also has the option to extend the exploratory work programme by an additional three years (Phase 2). Canacol acquired three new conventional natural gas exploration contracts at the Agencia Nacional de Hidrocarburos (ANH) Phase II of the Permanent Process of Assignment of Areas, or PPA in Colombia. The blocks are: VIM-33, VMM-45, and VMM-49. As of 20 November 2019, Canacol had increased processing capacity of up to 330 MMcf/d in Colombia, as part of its drive to meet growing demand for the fuel in the South American nation.

Canacol is the 1st to confirm the formal award of its rights under the latest ANH Proceso Permanente de Asignación de Áreas (PPAA) Ciclo 2. Sole rights have been bagged for VIM 33 (629 sq km) in the Lower Mag B, VMM 45 (503 sq km) in the Middle Magdal B, and VMM 49 (600 sq km) in the Middle Magdal.B)

IPI OIL Exploração de Petróleo has transferred a 50% stake in the Rio Ipiranga lease to Imetame following ANP approval on 21 June. The 43-sq km lease lies onshore in the Espirito Santo Basin.

IPI OIL (->50% op.) tranfered 50% non op. WI in Rio Ipiranga production concession to Imetame Energia

In early-June 2020, state company ANCAP indicated that offers from Kosmos Energy on two adjacent offshore blocks OFF-2 and OFF-3 have been approved, although the signing of the corresponding contracts will continue to be delayed due to the current coronavirus disease 2019 (COVID-19) pandemic. The offers were submitted by Kosmos as part of the ongoing Uruguay Open Round back in October 2019. For each block, the company's proposed commitments include geologic and prospect evaluation, 3D gravimetry and magnetometry work, licensing of existing multiclient geophysical/geological data, along with new 3D seismic acquisition (5,900 sq km for OFF-2 and 5,100 sq km for OFF-3). Total investment cost is expected to be USD 60.82 million and USD 52.82 million for OFF-2 and OFF-3, respectively. The offshore blocks of OFF-2 and OFF-3 cover 11,151 sq km and 13,265 sq km of areas, respectively, in Pelotas Basin with water depths ranging from 50 m to over 1,000 m. OFF-2 block is situated next to OFF-1 block that includes a couple of plugged & abandoned wells drilled by Chevron in 1976. In addition, both OFF-2 and OFF-3 are adjacent to OFF-6 block that includes the recently drilled Raya 1 well that was P&A’d by Total in 2016. Background Information  ANCAP launched a new biannual open round process called Uruguay Open Round with six blocks offshore and five blocks onshore in May 2019. In addition to areas that were previously offered in the last Uruguay Round 3 offshore round in 2018, the new licensing round also offers parcels that cover several recently relinquished offshore blocks in the south, along with onshore blocks in the north which cover areas that previously have been offered in their own open round process since 2014.

Uruguay (Pelotas B.) OFF-2 op. by KOSMOS EN (100%) Kosmos (100%) secured approval for the award of blocks OFF-2 (11 151km²) and OFF-3 (13 265km²).

Bozhong 22-1-4 (BZ 22-1-4) was suspended, having intersected oil in the target reservoirs, on or around 10 September 2019 after having been spudded on or around 15 July 2019 using the "Haiyangshiyou 932" jack-up. The oil and gas appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations. Bozhong 22-1-4 is in the CNOOC operated Bozhong Block in the offshore Bohai Gulf Basin and is located approximately 18km W of Bozhong 22-1-1. <P />

Bozhong 22-1-4 (BZ 22-1-4) was suspended, having intersected oil in the target reservoirs. The oil and gas appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations. Bozhong 22-1-4 is in the CNOOC operated Bozhong Block in the offshore Bohai Gulf Basin and is located approximately 18km W of Bozhong 22-1-1.

EP 469, onshore Perth Basin, TD 5,100m, 1st stage of testing from 3 Kingia sandstone intervals yielded impressive maximum flow rates of 69 MMcfg/d, confirming excellent reservoir quality and deliverability. Tests of the High Cliff and Wagina gas are planned for a 2nd stage. Strike (op), partner Warrego. The partners plan to undertake further 3D seismic and drill additional delineation wells in 2020 to fully define the structure.

West Erregulla-2 expl EP 469, onshore Perth Basin, TD 5,100m, 1st stage of testing from 3 Kingia sandstone intervals yielded impressive maximum flow rates of 69 MMcfg/d, confirming excellent reservoir quality and deliverability. Tests of the High Cliff and Wagina gas are planned for a 2nd stage. Strike (op), partner Warrego. The partners plan to undertake further 3D seismic and drill additional delineation wells in 2020 to fully define the structure.

Corallian Energy Limited spudded appraisal well 98/11a-6 on the Colter discovery locater in licence P1918 on 6 February 2019. In an update on 25 February 2019 partner, United Oil and Gas plc announced that the well had reached TD in the Sherwood Sandstone at 1,870 m. The well remained (unexpectedly) on the southern side of the Colter prospect bounding fault but encountered oil and gas show over a 9.4 m section at the top of the Sherwood Sandstone reservoir, this is separate to the original appraisal target. Petrophysical evaluations indicate net pay of 3 m. Similar indications of oil and gas shows were encountered in the 1983 well – 98/11-1. It is thought that the two wells may share a common oil-water contact having both intercepted the down-dip margin of the Colter South prospect. On 25 February 2019 Corallian kicked-off sidetrack 98/11a-6Z targeting the Sherwood Sandstone target within the Colter prospect on the northern side of the bounding fault. In an update from partner Reabold Resources on 8 March 2019 it confirmed that the sidetrack had been completed after being drilled to 1,910 m (MD). The sidetrack encountered the Sherwood Sandstone below the Oil-Water contact. It did encounter oil and gas shows in the Jurassic Cornbrash-Lower Oxfordian interval as seen at the Kimmeridge field. Operations are now complete and a review of the data from the operations will be undertaken with a view for the future to focus on the Colter South section of the area. The Colter discovery was made by BP in 1986 where 41.9° API was recovered on test from a 10.5 m oil column. Through the merging and reprocessing of 3D seismic Corallian has mapped 100 m of vertical relief up-dip of 98/11-2. Well costs are in the region of GBP 7 million. Corallian announced on 28 September 2018 that it had contracted the “Ensco-72” for the well. Licence P1918 was initially awarded to Infrastrata from the 26th Seaward Licensing Round prior to Corallian taking the acreage. The company reprocessed 156 km of 2D seismic and 33.5 sq km of 3D seismic over the licence. It is thought that Colter could hold mean prospective resources of 22 MMbo (recoverable). Interest in P1918 following completion of two deals will be held by Corallian Energy Limited (34% + operator), Corfe Energy Limited (40%), United Oil and Gas Plc (10%), Andalas Energy and Power (8%) and Baron Oil Plc (8%).

098/11a-06 Z (Colter ST) (Coralian op. 49%, Corfe Egy. 25%, UOG 10%, Resolute O&G 8%, Baron Oil 8%) in P1918 / block 98/11a off the Dorset coast, intersected the target Sherwood sst. fm below the oil-water contact. In addition, the side-track encountered oil and gas shows in the Jurassic Cornbrash-Lower Oxfordian interval, the producing reservoirs in the Kimmeridge oilfield, and this provides an interesting potential target on trend to the west within the onshore licences

Subject to government approval, DNO and Wellesley with withdraw from PL 990, leaving operator Equinor with a 100% interest. A drilling decision has been made on the licence, with Equinor wishing to proceed but DNO and Wellesley declining. Drilling will take place at the Kvernbit / Mimung North prospects once Equinor has found a new partner for PL 990. The company is also looking at further prospectivity within the licence. PL 990 lies in the North Viking Graben between Vega and Visund and immediately north and east of Afrodite. It covers a 362 sq km area over parts of blocks 34/9, 35/7 and 35/10 and was awarded in APA 2018. Afrodite well 34/12-1 was drilled on a Jurassic horst structure by Eni in 2007 / 2008. It confirmed 52 m of net pay (gas condensate) in the Middle Jurassic Brent Group with no GWC. However, reservoir properties were poor, with an average of 13% porosity and less than 0.1 mD of permeability. Gas flowed at a maximum rate of 10 MMcf/d through a 40/64" choke and the total amount of condensate recovered at surface was 148 barrels. Following completion of the withdrawals, interest in PL 990 will be held solely by Equinor Energy AS.

DNO and Wellesley with withdraw from PL 990, leaving operator Equinor with a 100% interest.

On 20 July 2019, SOCAR announced the completion of appraisal well Absheron Garbi 10 at its offshore Absheron Garbi oil field (Caspian Sea). Absheron Garbi 10 reached a TD of 770 m in the Kirmaku Formation. The well was spudded from platform N°10 in mid-June 2019.

Azerbaijan, Absheron

Petsec has acquired Oil Search’s 34% + operatorship in Al Barqa block 7, Shabwah, bringing its interest now in the 4,987-sq km block to 100%. Kufpec (21.25%) and Yemen O&G (15%) interests were acquired earlier on. The block contains the 2010 Al Meashar oilfield.

Yemen (Sayun-Masila B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Block 7 (Al Barqa) op. by OIL SEARCH (34.0%, PETSEC EN 29.75%, KPC 21.25%, YEMEN OG 15.0%) to be check.

The Agence de Gestion et de Coopération entre la Guinée-Bissau et le Sénégal (AGC) is the joint commission established by Senegal and Guinea Bissau to manage their joint maritime zone. One of AGC’s tasks is to offer open exploration acreage blocks in the Joint Exploration Zone (JEZ). Note about the Joint Exploration Zone (JEZ) Senegal's former President Abdou Diouf and his Guinea-Bissau counterpart President Joao Bernardo Vieira signed an agreement on 12 June 1995 settling the maritime border dispute in southern Senegal and northern Guinea Bissau. A Joint Exploration Zone (JEZ) for hydrocarbons was established in the region, which encloses Senegal’s Dome Flore oil accumulation. The Agence de Gestion et de Cooperation (AGC) was set up in 1996 to administer the area. The resources split for fisheries is 50% Guinea-Bissau / 50% Senegal. The resources split for hydrocarbons is 15% Guinea-Bissau / 85% Senegal. The licensing authority is the AGC. Interested parties should contact the address below. Agence de Gestion et de Coopération 122, Avenue André Peytavin  PoBox 11195 Dakar Peytavin, Sénégal  Téléphone : +221 33 849 1349  Fax : +221 33 821 8702  Email: [email protected] Contact person for petroleum rights : Mr. Boucar Faye Email: [email protected]   The available blocks as of November 2018 are listed in the table below.   One block is available. There was no change to the list from the previous month.   Total open acreage amounts to 1,740 sq km, all offshore.   Open blocks       Block Name Area (sq km) Situation Block Basin Dome Flore 1,740 offshore Senegal (M.S.G.B.C.) Basin

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

After an initial effort in 2015, the 19-sq km Veselovskiy block in the Stavropol Kray (North Caucasus Province) will be auctioned again on 8 May ’18, applications by 25 April. It contains the Lower Cretaceous and Paleogene Veselovskoye gas discovery. Starting price USD 420,000. Contact: Kavkaznedra, email [email protected].

Veselovskiy block in the Stavropol Kray (North Caucasus Province) will be auctioned again on 8 May ’18, applications by 25 April. It contains the Lower Cretaceous and Paleogene Veselovskoye gas discovery. Starting price USD 420,000. Contact: Kavkaznedra, email [email protected].

Pulu 3 flow tested approximately 4.6 MMcfg/d through a 10mm choke from the horizontal section of 3,545-3,935m MD in the Jurassic Qianfuya Formation on 19 April 2020, after having underwent a six stage fracture stimulation progamme in early April 2020. The success of Pulu 3 has opened the continental shale/tight gas potential of the Puguang gas field area and is estimated to hold resources-in-place of 123.4 Bcm of gas. Previous exploration of the Jurassic continental tight gas in the Puguang field area focused on the Xujiahe Formation which was unable to achieve stabilized commercial gas flow. Pulu 3 was spudded in May 2019 and was suspended for testing on 4 November 2019 at a TD of 3,979m MD. Pulu 3 is in the Sinopec operated Daxian-Xuanhan Block in the Sichuan Basin and used the same well site platform as the Pulu 2 well that is geographically located in Sichuan Province, Xuanhan County, Puguang Town, Taya Village.

Pulu 3 npw, (Sinopec – Zhongyuan 100%) achieved an important breakthrough in the Puguang prod. block, well tested 4,6 MMscf/d of gas, through a 10 mm choke, at an interval between 3545 and 3945 m in the Jurassic Qianfoya Fm. The success of Pulu 3 demonstrated gas exploration prospective on the Jurassic play in this area and indicated 4.4 Tcf of geological gas resources. Pulu 3 was drilled in the outside of the Puguang field area with non-marine play target in the Jurassic Qianfoya Fm.

On 14 October 2017, Occidental together with Oman Oil Co Exploration & Production LLC (OOCEP), a wholly-owned subsidiary of state company Oman Oil Co SAOC (OOC), signed an Exploration & Production Sharing Agreement (EPSA) with the Omani Government for Block 30 (Hafar). The onshore block (1,185 sq km) is located in northern Oman and adjoins Occidental's Block 27 (Wadi Aswad) and Block 62 (Habiba).<P />The block has been awarded following the country's 2016 Licensing Round, which was launched in October 2016 and closed in February 2017. It was among a total of four blocks on offer, which are located in different parts of the country. <P />To date, gas has been discovered in four separate structures with reservoirs in the Cretaceous Natih and/or Shuaiba formations. These discoveries have not been fully appraised and adjacent structures remain undrilled. Altogether nine wells have been drilled, with six of those having encountered gas. Gas rates from DSTs and during long-term tests ranged from 7 MMcfg/d to 19 MMcfg/d. The last well, Hamrat Duru 4, was drilled by RAK Petroleum in 2010. It is understood that tight gas is the predominant play within the block and that there are currently two gas prospects mapped within the block.<P />Occidental operates the acreage with a 72.86% interest, with OOCEP holding the remaining 27.14%.

Oman, Block 30 (Hafar)

On late May 2020, PEMEX was abandoning dry the Holboton 1EXP directional new-field wildcat (NFW) in the AE-0155-Chalabil entitlement block. It is assumed reached the proposed total depth. The well is located approximately 70 m east of the Xux 1DL completed in 2010 by PEMEX on the northern side of the Xux Field that produces from the Jurassic. The NFW was spudded on 13 December 2019 with a proposed total depth (PTD) of 4,729 m measured depth (MD) and 2,970 m true vertical depth (TVD). The primary objective for the NFW was the Upper to Middle Miocene from 2,410 m to 2,840 m TVD. The trap is reported to be a fault bounded, combination structural stratigraphic trap with five zones of interest having seismic anomalies. The total unrisked prospective resources for the lead was 34 MMboe. It was drilled by the "Independencia 1" J/U in a water depth of 25 m. The drilling cost is estimated to be USD 33.2 million at 1USD to 20MXN and the completion cost is USD 10.3 million. On 28 August 2019, the 599.95 sq km AE-0018-2M-Okom-01 entitlement block was granted by SENER to Pemex 100% through Ronda 0 on 27 August 2014. The entitlement expired on 27 August 2019 and replaced by the 831.50 sq km AE-0155-Chalabil entitlement block. On 24 October 2019, PEMEX was granted approval by the CNH for the first exploration plan related to the 831.50 sq km AE-0155-Chalabil entitlement block that included drilling two new-field wildcats (NFW), the Zaziltun 1EXP, drilling in mid-December 2019, and the Holboton 1EXP. On 12 December 2019, PEMEX was granted a permit by the CNH to drill the Holboton 1EXP.

(Sureste) Holboton 1EXP directional new-field wildcat (nfw) (Pemex 100%) in the AE-0155-Chalabil entitlement block was abandoned dry. It is assumed that the well reached the proposed TVD = 2 970 m. The primary objective for the NFW was the Upper to Middle Miocene from 2 410 m to 2 840 m TVD. The trap is reported to be a fault bounded, combination structural stratigraphic trap with five zones of interest having seismic anomalies. WD=25m

The Ethiopian Ministry for Petroleum & Natural Gas is promoting the country’s open acreage which is available to companies for direct negotiations. The Ministry offers 23 blocks as follows: Ethiopia blocks on offer Block Name Block Sqkm Main Political Province Basin Names Gambela 157075.86 Binshangul Gumuz Amhara Massif~Abbay (Blue Nile) Basin North West 82516.38 Amara Mekele Basin~Amhara Massif~Northeast African Fold Belt Afar Area 62997.88 Afar Afar Basin~Red Sea Basin~Mekele Basin~Ogaden Sub-basin (Somali Basin)~Northeast African Fold Belt Rift Valley Block 43054.83 Ye Debub Biheroch Afar Basin~Amhara Massif Omo 30598.73 Ye Debub Biheroch Amhara Massif~South Omo Graben (EARS, East Branch)~Chew Bahir Graben (EARS, East Branch) Metema 29827.79 Binshangul Gumuz Mekele Basin~Northeast African Fold Belt~Amhara Massif Afar 24589.42 Afar Afar Basin~Mekele Basin~Red Sea Basin~Northeast African Fold Belt Block 05 18299.34 Oromiya Ogaden Sub-basin (Somali Basin) Block 07 12254.06 Sumale Ogaden Sub-basin (Somali Basin)~Mandera-Lugh Sub-basin (Somali Basin) Block 02 12232.2 Oromiya Ogaden Sub-basin (Somali Basin)~Mandera-Lugh Sub-basin (Somali Basin) Block 06 12232.2 Oromiya Ogaden Sub-basin (Somali Basin) Block 18 12232.19 Sumale Ogaden Sub-basin (Somali Basin) Block 01 12206.7 Oromiya Ogaden Sub-basin (Somali Basin) Block AB8 12135.44 Amara Abbay (Blue Nile) Basin~Amhara Massif Block AB9 12128.45 Amara Abbay (Blue Nile) Basin~Amhara Massif Block AB5 12108.5 Amara Amhara Massif~Abbay (Blue Nile) Basin Block AB6 12108.5 Amara Amhara Massif~Abbay (Blue Nile) Basin Block AB3 12068.51 Amara Amhara Massif Block AB2 12068.5 Amara Amhara Massif Block 19 6467.74 Sumale Ogaden Sub-basin (Somali Basin) Block 21 6094.66 Sumale Mudugh Sub-basin (Somali Basin)~Ogaden Sub-basin (Somali Basin) Area 4 3679.4 Ye Debub Biheroch Amhara Massif~East African Rift System, Eastern Branch Source: IHS Markit © 2019 IHS Markit   Following Africa Oil relinquishment of the Rift Valley block in August 2019, the block is now available for negotiations. According to the Ministry, Block AB1, Block AB4, Block AB7, Adigala and Block 10 were under discussions as of early November 2019. Petroleum contracts are in the form of Model Production Sharing Agreement of 1994 between the government of Ethiopia, represented by the Minister of Mines and Energy, and a contractor. The contracts have an initial exploration term of four years and an optional two-year term, with two possible further exploration periods of two years (4+2+2). The development and production period is of 25 years. The minimum exploration and expenditure obligations are negotiable. The signature and production bonuses are also negotiable. The income tax is 30%. For further details, interested companies are invited to contact: Mr. Ketsela Tadesse Director – Petroleum Licencing & Administrative Dictatorate Ministry of Mines, Petroleum & Natural Gas 486 Addis Ababa, Ethiopia Phone: + 251 11 646 12 09 Fax: + 251 11 646 34 39 [email protected]

The Ethiopian Ministry for Petroleum & Natural Gas is promoting the country’s open acreage which is available to companies for direct negotiations. Ethiopian Government offers 23 + 5 open blocks

On 9 December 2017, it was announced that Norm Ambalaj Sanayi ve Ticaret A.S. (Norm) had been awarded two new exploration licences, G24-C1,C2 and G25-D1,D2, on 4 December 2017. The licences were granted with five year terms and cover a total area of 586.68 sq km in the Western Pontides. Norm is 100% owner and operator of the licences.

Norm, 2 was awarded new exploration licences, G24-C1,C2 and G25-D1,D2.

On 12 February 2018, local media reported that Sonatrach International E&P Corp (Sipex) had encountered hydrocarbons in the Kafra 1 wildcat in the north of Kafra licence. The well was spudded around December 2017. Sipex is the sole participant of the 23,000 sq km Kafra permit located in the Seguedine Rift, Chad Basin.

Kafra 1 op. by Sonatrach Sipex (100%) in Kafra block “had encountered hydrocarbons” - local media reported.

On 30 July 2019, it was announced that a consortium of Cairn Energy, SOCO International and Ratio Oil Exploration had been awarded eight new oil and gas exploration licences by the Israeli Petroleum Council following Israel’s 2nd Offshore Licensing Round. Blocks 39, 40, 47 and 48 are located in the designated Zone A area and blocks 45, 46, 52 and 53 are located in the designated Zone C area. Both zones lie to the south of Israel’s offshore area in the Levantine Basin. To complete the awards the consortium will be required to pay a signature bonus and licence fees. The contracts will be awarded for an initial period of three years, with the possibility to extend. The three participants will each hold 33.33% interest in the licences. Block 40 contains Myra 1 and its sidetrack Myra 1ST1, which was previously plugged and abandoned in 2012. The wells were drilled under the Myra (347) contract with GeoGlobal Resources (India) Inc. as the operator. No other wells have been drilled within the other seven awarded contracts. Israel’s 2nd Offshore Licensing Round was launched on 4 November 2018 with a revised bid submission deadline of 15 July 2019 (extended from June 2019). The Ministry of Energy announced that five companies had submitted proposals for 12 out of the 19 exploration blocks offered. The bid round comprised 19 offshore exploration blocks which were issued within five zones. Each of the blocks measures approximately 400 sq km whereas a zone may measure up to 1,600 sq km. The zones and blocks are all located in the southern part of Israel’s offshore area. Exploration licences, once granted, will be valid for an initial three year period. After completing any work commitments, the licence can be extended for a further two years with the submission of an additional work plan. The licence may then be extended for an additional two years. The number of licences granted to any one party is limited to eight. The participation guarantee for the first block licenced in a zone will be USD 2.5 million. Every additional block in the zone will require an additional guarantee of USD 0.5 million with the maximum guarantee required for four consecutive blocks in a zone being USD 4 million. An additional guarantee of USD 5 million is required prior to drilling.

On 30 July 2019, it was announced that a consortium of Cairn Energy, SOCO International and Ratio Oil Exploration had been awarded eight new oil and gas exploration licences by the Israeli Petroleum Council following Israel’s 2nd Offshore Licensing Round. Blocks 39, 40, 47 and 48 are located in the designated Zone A area and blocks 45, 46, 52 and 53 are located in the designated Zone C area. Both zones lie to the south of Israel’s offshore area in the Levantine Basin.

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

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

The Department of Energy (DOE) received a nomination for Area 4 located in the East Palawan Basin, under the Philippines Conventional Energy Contracting Program (PCECP), in late August 2019. Block description Nominated Area 4 (NA4) covers an area of 9,320 sq km at water depths between 5 m and 2,000 m. The area is adjacent to the SC 76, which was officially awarded to Ratio Petroleum on 17 October 2018, under Philippines Energy Contracting Round V (PECR V). Upon approval of the nomination, the nominating party for Area 4 had published its application in local newspapers on 28 August 2019. The deadline for document submission is on 28 October 2019. A large portion of NA4 was offered during PECR 2005 (Area 2) and First Contracting Round 2003 (0911A, 09119B, 09120A). Area 2 received two bids, however no preferred bidder was selected. Only one well was drilled by Shell in 2010. Silangan 1 was plugged and abandoned with gas shows. The area is covered by 2D seismic data from multiple surveys, including Mialara 2D Broadband Survey (2014). Petroleum System Petroleum system in the East Palawan Basin is unproven. Gas shows and traces of dead oil suggest gas and oil-prone system is present. Potential reservoir targets include Lower to Middle Miocene carbonates and sandstones with possible source of oil-prone from the Upper Oligocene to Lower Miocene deep marine claystones. Intraformational Middle Miocene to Pliocene fine clastics provides effective seals in the adjacent Sulu Sea region. Play types identified in the block including anticlines, wrench-fault related folds, listric fault associated closures, stratigraphic pinch-outs against fault blocks and carbonate build-ups on paleo-highs. The main risk from an exploration viewpoint is hydrocarbon generation. Background Information Mialara 2D Broadband Survey The Mialara 2D multi-client survey, commenced on 8 September 2014, was conducted using the “Aquila Explorer” M/V by Searcher Seismic. Around 5,000 km data over a 10 km by 10 km grid was acquired in offshore East Palawan Basin, covering three bidding blocks (Areas 4, 5 and 6) offered under the PECR V and in-filled the previous Pala-Sulu multi-client survey in 2012. The acquisition was completed on 27 October 2014. The survey provided long offset, broadband data. The previous Pala-Sulu Seismic Survey was conducted to provide a consistent regional overview between the basins to create a uniform seismo-stratigraphic framework. It has been specifically designed to meet the challenging tectonic framework of the petroleum basins and to improve the imaging of the lower sedimentary sections and the Basement. East Palawan Basin East Palawan is a frontier basin and its full hydrocarbon potential remains largely untested. Out of the eight wildcat wells drilled in the Philippine sector of the East Palawan Basin, only two revealed minor gas shows and one traces of dead oil. DOE reported that the estimated volume of total risked recoverable resources excluding the unmapped resources in East Palawan Basin is around 448 MMbo and 895 Bcfg. The East Palawan Basin is an elongated basin situated offshore north-eastern Sabah. Trending southwest-northeast, it covers an area of 100,200 sq km. The basin comprises a platform area in the west and an offshore basin in the east. The East Palawan Basin lies almost entirely in the Philippines territorial waters of the Sulu Sea. The basin has been only partially explored to date, and its full hydrocarbon potential remains largely untested. The deep water part of the basin is considered to be potentially prospective for gas. Potential hydrocarbon kitchen areas in the East Palawan Basin are large Paleogene graben-like sub-basins with a pre-Middle Miocene sediment thickness in excess of 5 km. An Upper Oligocene to Lower Miocene source facies, within the Paleogene graben-fills, would have reached the oil window, with the deepest horizons possibly being depressed into the gas window, and beyond, during subsequent burial. The source rock potential of the East Palawan Basin is evidenced by dead oil encountered in the Dumaran 1/1A and gas shows in the Sulu Sea A-1 wells. A number of hydrocarbon seepages have also been recorded in the basin and compelling direct hydrocarbon indicators (DHIs) are seen on the East Palawan seismic data.

Philippines, not found

Europa Oil and Gas reported on 11 June 2020 that it was acquiring, subject to regulatory approval, 100% interest in Frontier Exploration Licence (FEL) 3/19 from DNO. The acquisition requires Europa to pay an upfront nominal fee and grant DNO a 5% Net Profits Interest for any future hydrocarbon production from accumulations within the licence. These include the Edge Prospect, with estimated un-risked prospective resources of 1.2 Tcfg. Prior to this transaction, the Department of Communications, Climate Action and Environment (DCCAE) had reported on 31 March 2020 that FEL 3/19 was held by CNOOC (80% + operator) and DNO (20%). Therefore, during Q2 2020 and prior to the deal with Europa, DNO acquired CNOOC's operated interest (the terms of which have not been reported). FEL 3/19 spans the Slyne and Erris sub-basins, 18 km east of the producing Corrib gas field and around 24 km east of Europa's drill-ready Inishkea prospect in FEL 4/19. The Edge prospect and leads such as Clayton, Downey, Lynott and McGowan were identified in the licence and reported by Faroe Petroleum in 2016. Edge was described by Faroe Petroleum as a Triassic Sherwood Sandstone reservoir, with a reported chance of success of around 15%. The Corrib reservoir consists of the same formation at 3,300 m depth, whereas the Edge prospect is reportedly much shallower. Europa intend to re-launch the farmout of FEL 3/19 alongside its FEL 4/19 (Inishkea) farmout which, due to the proximity to the Corrib field, provide infrastructure-led exploration opportunities. Following regulatory approval, FEL 3/19 will be wholly owned by Europa Oil and Gas (Holdings) plc.

Europa announces the conditional acquisition of FEL03/19, off NW Ireland, from DNO. The 956-sq km permit contains the 1.2 Tcf Edge prospect, adding onto Europa's other regional assets.

Block 6, Eastern Flank sub-basin in S. Oman, drilled 12-22 Dec '19, TD 1,548m, ops terminated (results n/a), rig 104.

Rakid SW-1 expl Block 6, Eastern Flank sub-basin in S. Oman, drilled 12-22 Dec '19, TD 1,548m, ops terminated (results n/a),

On 24 January 2019, Nautilus Marine Services, formerly Global Energy Development, announced it continues efforts to divest the Bolivar and Bocachico blocks located in the Middle Magdalena Basin. The sale of these non-strategic assets will eliminate annual operating costs and any future abandonment obligations. Nautilus was assessing divestment and partnership opportunities during 2018 and evaluations continue until an acceptable deal is secured.  The company name change to Nautilus was effective 8 February 2017.

Colombia, Bocachico

Equinor has agreed a deal with Chevron to acquire the latter’s 40% interest in the Rosebank field in the West of Shetlands. The field, located over licences P1026, P1272 and P1191, has been planned for development following submission of the Environmental Statement for the field in 2018. Equinor previously held interest in the asset which is one of the UK’s largest undeveloped fields. The deal is subject to regulatory approval. The concept for development submitted by Chevron was for an FPSO with 17 wells. Oil will be transported via a shuttle tanker and gas will be exported via a new 236 km pipeline tied-into the Shetland Island Regional Gas Export System (SIRGE). The ES looked at the development of the Colsay reservoirs with nine producers and eight water injectors. Installation of the pipeline is scheduled for late Q1 2022, followed by the installation of the manifolds and drilling of the wells during Q2 2022. The final wells are expected to be completed by 2027. First oil is planned for late 2024 with peak production in 2025 before a steady decline in 2033, and gas production will peak in 2031. It is understood that Chevron extended its re-tender for the Rosebank field development drilling campaign during 2018. The plan was to drill 11 top holes commencing in 2020 until 2021 lasting approximately 120 days. Then the main drilling programme would commence in 2022 with the drilling of the 17 subsea wells. A Final Investment Decision for the project was planned for early 2019. Rosebank was discovered in August 2004 by well 213/27-1Z which encountered two reservoirs – Rosebank and Lochnagar - with a total net pay of 52 m. Rosebank has a Paleocene reservoir and Lochnagar has an Upper Jurassic reservoir. Appraisal well 205/1-1, drilled in 2007 on the Rosebank structure, tested 6,000 b/d of good quality oil with API values of 37°. The field is situated in water depths of approximately 1,100 m. Between April and August 2011 a 350 sq km High Density 3D OBN survey was performed over Rosebank with SeaBird’s “Munin Explorer”. This was the second phase of the Rosebank High Density 3D survey. The first stage was shot in 2010 and covered an area of 256 sq km. Front End Engineering Design studies commenced in 2012. In 2013 Chevron submitted and Environmental Statement for the project. The produced oil was to be shuttled by tanker, while gas will be exported via a newly installed pipeline. Back when the Environmental Statement was submitted it was thought that peak oil production was expected to reach 82,000 b/d with peak gas production, expected three years after the initial oil production, at 134 MMcf/d. Interest in the Rosebank field will be held by Equinor (40% + operator), Suncor Energy (30%), Siccar Point Energy (20%) and INEOS (10%).

Equinor has agreed a deal with Chevron to acquire the latter’s 40% interest in the Rosebank field in the West of Shetlands. The field, located over licences P1026, P1272 and P1191, has been planned for development following submission of the Environmental Statement for the field in 2018.

On 11 May 2018 Norwest Energy Ltd, joint venture partner in the L14 licence, located in the Perth Basin, announced that RCMA Australia Pty Ltd had been assigned operator, taking over from Cyclone Energy Pty Ltd. RCMA already held a 60% interest in the permit and has now taken over operatorship. Cyclone Energy and RCMA Australia both acquired interest in the permit in 2017, after acquiring it from previous participants Origin Energy Developments Pty Ltd, AWE Ltd, Roc Oil Ltd and John Geary. Norwest Energy, which is also a joint venture partner and holds 6.278%, elected to maintain its interest in the asset. The L14 licence contains the Jingemia field, was discovered in November 2002.  The field came onstream in July 2004, but was shut-in, along with the production facilities, in December 2012. RCMA and Cyclone, upon acquiring interest, announced their intention to re-start production, with workovers planned as part of this. L14, which covers an area of 45 sq km, was awarded on 21 June 2004.  Now that the change of operator is complete, participants in the permit are RCMA Australia Pty Ltd (60% + Operator), Cyclone Energy Pty Ltd (33.72%) and Norwest Energy NL (6.28%).

On 11 May 2018 Norwest Energy Ltd, joint venture partner in the L14 licence, located in the Perth Basin, announced that RCMA Australia Pty Ltd had been assigned operator, taking over from Cyclone Energy Pty Ltd. RCMA already held a 60% interest in the permit and has now taken over operatorship.

Spirit spudded an exploration well on the Sandia prospect in PL 719 using the "Leiv Eiriksson" S/S on 1 June 2020. 7321/8-2 S was drilled as a tight hole on the Fingerjupet High, between the 7321/8-1 (1987) and 7321/9-1 (1988) wells. The primary target formations were the Middle Jurassic-Upper Triassic Sto, Fruholmen and Snadd. Sandsone reservoirs were encountered in all three, at thicknesses of 20 m, 30 m and 2 m respectively, but were found to be water-bearing. The well had an additional target in the Lower Cretaceous Kolje formation, which was also found to be dry with traces of hydrocarbon. The well was drilled to a TD of 1,899 m MD (1,777 m TVDSS) and terminated in the Upper Triasic Snadd formation. Sandia was thought to have had the potential to contain 240 MMboe, but on 1 July 2020 the well was abandoned as a dry hole. There are a number of nearby wells which were also unsuccessful, including Spirit's 2018 Scarecrow well, and the company believes that these results were due either to the traps being blown or underfilled. The objectives for Scarecrow well 7322/7-1 were clinoforms in the Lower Cretaceous Kolje and Knurr formations, with Top Reservoir expected at just 642 m. The trap was mapped to be dip-closed to the west, faulted to the east and stratigraphic to the south, and the prospect was analogous to the Matzen field in Austria. A low velocity anomaly and high resistivity was seen over the prospect. Spirit expected to find oil with a gas cap in the structure which lies approximately 70 km west of Wisting and partner Aker BP put potential recoverable reserves at 83-245 MMboe prior to drilling. However, there was no reservoir present (only siltstone) and the well reached TD at just 767 m in the Lower Cretaceous Adventdalen Group. 7321/7-1 was drilled by Mobil in 1988 and found gas shows in the Triassic Snadd Formation where permeability was low. Residual shows were also recorded in the Snadd Formation and the Jurassic in Norsk Hydro's well 7321/8-1, and the same company's 7321/9-1 confirmed weak shows in the Jurassic Sto, Nordmela and Fruholmen sequence. Spirit Energy Norway AS operates PL 719 with a 50% interest. It is partnered by Lukoil Overseas North Shelf AS (30%) and Aker BP ASA (20%).

Norway (Barents Sea Platform), 7321/8-2 S nfw (Sandia), in PL 719 op. by CENTRICA (35%), LUKOIL (30%), AKER BP (20%), MUNCHEN ST (12%), BAYERNGAS (3%), Tigas (0%), P&A dry. The primary target formations were the Middle Jurassic-Upper Triassic Sto, Fruholmen and Snadd. Sandsone reservoirs were encountered in all three, at thicknesses of 20 m, 30 m and 2 m respectively, but were found to be water-bearing. The well had an additional target in the Lower Cretaceous Kolje formation, which was also found to be dry with traces of hydrocarbon. The well was drilled to a TD of 1,899 m MD (1,777 m TVDSS) and terminated in the Upper Triasic Snadd formation.

CNOOC announced a large-sized oil field discovery has been made in Bohai Gulf Basin. KL 6-1 field is located in the Laibei low uplift of north Laizhou Bay Sag of Bohai offshore, in a water depth of 20 m. The discovery well, KL 6-1-3, was drilled on a Miocene stratigraphic trap and completed with a TD of 1,596 m in May 2019, it is reported the well was tested to produce at an average rate of 1,178 b/d of oil from the Miocene sandstones. During drilling the well penetrated 20 m. Following the discovery well, CNOOC has drilled several appraisal wells in 2019 with success. Around KL 6-1 area, CNOOC has made several discoveries with reservoir in the Tertiary clastics over the past few years, but they are small-sized and pending for appraisal: In 2019 KL 10-1N-3d completed and reported as an oil discovery well. In 2018, the company made an oil discovery in KL 5-1-1D. In 2017, the company made discoveries in Kenli 3-2S-1, Kenli 6-5-1 and Kenli 4-1-1d. In 2010, CNOOC made an oil discovery in KL 6-4-1. The well penetrated 213 m oil pay during drilling operations and reported to be a breakthrough with a medium sized discovery in this area. Background Information The Laizhou Bay Sag lies in the southern part of the Bohai offshore in the Bohai Gulf Basin and covers 1,200 sq km. Like other geological units in the basin, Laizhou Bay Sag is mainly a Tertiary sediment depocenter with a maximum thickness up to 7,000m. To the north of the Laizhou Bay Sag it is Huanghekou Sag in the Bohai offshore where BZ 34 fields complex is, to the south it is the Jiyang Depression onshore where extensive exploration work has been done and many fields are found. With more discoveries made, it represents a further potential in the Laizhou Bay area, the main risks are oil and gas generation volume in such a small sag and effectiveness of the traps.

China (Jiyang Depression (Bohai Gulf B.)) Kenli 6-5 (Bo) 1

Further to DEA 17 Apr '20: M-08, Moattama Basin, WD ca. 150m, P&A dry at TD ca. 960m, Noble Clyde Boudreaux SS. Target gas in Lower-Middle Miocene Upper Burma lmst. Drilling the SR prospect was to follow 40km SE of above, well understood cancelled + rig released to Vietnam. 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).

Brazil's first pre-salt oil auction on 30 May failed to attract any offers, and the PPSA is now reportedly intending to re-launch the round later this year. The auction will presumably be held under revised terms. It offered future oil output from the Mero (Libra project), Lula and Sapinhoá areas.  Oil from the Tartaruga Verde area was due to be offered too but was not be released since the percentage of govt profit oil is still under negotiation.

Brazil's first pre-salt oil auction on 30 May failed to attract any offers, and the PPSA is now reportedly intending to re-launch the round later this year. The auction will presumably be held under revised terms. It offered future oil output from the Mero (Libra project), Lula and Sapinhoá areas. Oil from the Tartaruga Verde area was due to be offered too but was not be released since the percentage of govt profit oil is still under negotiation.

AziNor Catalyst announced on 14 June 2018 that a subsidiary of Cairn Energy has agreed to farm-in to licence P1763 (blocks 9/9d and 9/14a) taking a 25% interest. Carin has also agreed to join AziNor for 50% of the sole risk drilling activity on Agar-Plantain. AziNor has signed a contract to secure the Transocean Leader to drill a well in Q3 2018 of which the company is in the final stages of planning. Furthermore, AziNor will retain operatorship for the proposed appraisal well and Cairn will have an option to take operatorship in the future. The deal is subject to regulatory approval.   The initial appraisal wellbore will delineate the down dip section of the Agar discovery reservoir with a sidetrack targeted to test the Plantain prospect. The target depth is 1,675 m and combined mid-case resources of 60 MMboe with significant upside of 98 MMboe are estimated. The gross well cost is USD 9.2 million (dry hole) or USD 12.8 million (success case including Plantain sidetrack). Agar has a CoS of 58%. The rig contractor has been identified and a spud date slated for Q2 2018. The success case will take 37 days to drill. The Agar discovery is located in the Viking Graben east of Beryl field and west of the Alvheim hub. The Eocene Agar discovery was made in 2014 with well 9/14a-15A which encountered an 11 m oil-down-to in high quality Eocene Frigg Formation sands. The well was drilled by MPX which was primarily targeting the Upper Jurassic sands of the Aragon prospect. The Upper Jurassic sands were encountered in the well but was water bearing. The sands are trapped within a stratigraphic trap which was also proven by the discovery well with the reservoir package being mapped confidently on high quality 3D broadband seismic data. Through high quality seismic data and advanced quantitative interpretation techniques AziNor have significantly de-risked the Plantain prospect. If the operations are successful then development options could be tie backs to Beryl Bravo, Alvheim FPSO or a standalone FPSO. On completion of the deal interest in P1763 is held by Apache Beryl I Limited (50% + operator), AziNor Catalyst Limited (25%) and Cairn Energy Plc (25%).

AziNor Catalyst announced on 14 June 2018 that a subsidiary of Cairn Energy has agreed to farm-in to licence P1763 (blocks 9/9d and 9/14a) taking a 25% interest. Carin has also agreed to join AziNor for 50% of the sole risk drilling activity on Agar-Plantain.

ADX Energy announced on 26 August 2019 that the drilling of the Iecea Mica 1 appraisal well in the DEE V-19 Iecea Mare production license in western Romania reached the measured depth of 2,335 m on 25 August 2019. The company indicated that a number of potential Pliocene to uppermost Miocene (PA) reservoirs were intersected and logged. A two-meter “PA III” stratigraphic interval, within which two significant gas peaks were recorded, was intersected at the depth of 1,863 m, i.e. three meters shallower that the control well (Iecae Mare 35). Very strong C1 and some C2 gas shows were recorded within the “PA IV” section over a five-meter interval at the depth of 2,033 m as well as two more strong peaks associated with a claystone section at the respective depths of 2,053 and 2,051 m. Finally, the “PA V” interval was encountered at 2,140 m (MD), where strong C2 and C3 gas peaks were recorded over a 23-m section composed of an alternation of claystone, siltstone and finely laminated sandstone less than two meters thick. ADX will now run the 7” casing and start the drilling of the 6” hole to total depth. The well is expected to intersect potential Badenian and Sarmatian as well as fractured basement reservoirs belonging to deeper hydrocarbon systems below the depth of 2,400 m, after crossing the crest of a significant basement high. The area is lacking a number of Lower Pannonian reservoirs due to onlap and non-deposition. The well was spudded on 6 July 2019. Drilling operations using the “Tacrom Futura Rig 6” drilling rig should last 29 days from spud. Iecea Mica 1 is a re-drill of the Iecea Sud 35 well which was drilled to a TD of 2,350 m by Petrom between 1986 and 1988. The upper 2,350 m of the well will be a re-drill of the original discovery well and will evaluate multiple gas zones mapped on 3D seismic data including a gas zone which was flow tested. The well will then be deepened by a further 250 m to evaluate a larger exploration target, which has been proven to contain oil in other fields within the basin. The costs are estimated at USD 3 million, including evaluation, logging and running casing but does not include the well testing operations which are planned to be undertaken with a smaller and cheaper workover unit. The company is also planning the re-drill of Carpinis 55 which will be named Iecea Mica 2 in the E X-10 Parta licence. If successful, the wells will be tied-in to the nearby Galacea gas plant in late 2019. Wellsite operations were launched in June and the rig mobilization took place between 29 July and 5 August. On 18 August 2019 the well reached the depth of 1,346 m. The 9 5/8” casing was successfully cemented to the depth of 808 m and the well head and blow out preventer installed. The contingent resources based on an independent expert’s report of the historic well data with recently acquired 3D seismic is 6.1 Bcf 2C and prospective gas resources are 13 Bcf best estimate potential. The best-case prospective resource for the deeper exploration upside potential accessible by the well that is mapped on 3D seismic is 16 Bcf (for a gas success case) and 2 MMbbl (for an oil success case). In October 2017 the company confirmed that it had spotted two potential drilling opportunities following the data interpretation of a modern 3D survey which covers some 20 sq km in the northern part of the licence. According to ADX with the exception of one reservoir target all other targets have been proven either by long term testing or free gas flow to surface. The Carpinis 55 and Iecea Sud 35 wells have been drilled in the 1980s. The Iecea Mare oil and gas field was discovered in 1985 and put onstream in 1986. In 1998 the field considered as depleted was shut down. Interest in the DEEV-19 Iecea Mare licence is held solely by ADX Panonia Srl. ADX Energy Panonia is 100% held by Danube Petroleum which belongs to ADX Energy (62.5%) and Reabold Resources (37.5%).

Iecea Mare 1 (ADX Energy 62.5%, Reabold Resources 37.5% ) in Iecea Mare production licence intersected a number of sst. reservoir intervals, noting two “significant” gas peaks encountered in the Pa III stratigraphic interval, a number of potential Pliocene to uppermost Miocene (PA) reservoirs were intersected and logged. A two-meter “PA III” stratigraphic interval, within which two significant gas peaks were recorded, was intersected at the depth of 1,863 m, i.e. three meters shallower that the control well (Iecae Mare 35). Very strong C1 and some C2 gas shows were recorded within the “PA IV” section over a five-meter interval at the depth of 2,033 m as well as two more strong peaks associated with a claystone section at the respective depths of 2,053 and 2,051 m. Finally, the “PA V” interval was encountered at 2,140 m (MD), where strong C2 and C3 gas peaks were recorded over a 23-m section composed of an alternation of claystone, siltstone and finely laminated sandstone less than two meters thick.

Sarta block north of Erbil in Kurdistan, TD 4,023m, preparing to test. It is recalled ops on this well had been suspended in Oct ’18 after the independence referendum caused tensions between Baghdad and Kurdistan’s semi-autonomous govt. Partner OMV.

Sarta-3 appr Sarta block north of Erbil in Kurdistan, TD 4,023m, preparing to test. It is recalled ops on this well had been suspended in Oct ’18 after the independence referendum caused tensions between Baghdad and Kurdistan’s semi-autonomous govt. Partner OMV.

Lion Energy reported on 24 July the sale of its 40.7% participating interest in the South Block A PSC, located in onshore North Sumatra, to Blue Sky Resources Ltd. Consideration for the sale was a nominal amount of USD 10. Lion will have no further obligations towards the PSC joint venture, however it will retain entitlement to royalties from future production from the block, up to a maximum of USD 4.5 million. The royalty, equal to 0.8% of the revenue from the block, will become payable as soon as 50% of the cost recovery pool at first production has been recovered. Lion was holding the participating interest through fully owned subsidiary KRX Energy. The deal is subject to final approval from Indonesian government. Operator RENCO Elang will retain operatorship and 59.3% interest in the block. RENCO is planning to drill exploration well Amanah Timur 2 in the block, possibly in Q3 2018, to further evaluate the potential oil and gas discovery made by the Amanah Timur 1 wildcat in January 2017. After the completion of Amanah Timur 1, the operator received a four-year extension for the exploration period of the South Block A PSC, until January 2021. The work programme for the extension includes three wells and 50 sq km of 3D seismic acquisition. After the first two years, work progress will be monitored by SKK Migas and failure to complete the programme or to submit a Plan of Development may result into PSC expiry, with no financial penalty. Future drilling in the block could be targeting the Jerneh prospect which is considered by Lion among the largest undrilled prospect in the North Sumatra Basin. With the sale of South Block A, Lion has mostly completed its portfolio review towards focusing on producing and near-producing assets in Southeast Asia. The company retains interests in several unconventional Joint Study Areas in onshore North and Central Sumatra, which could be still under consideration for potential disposal. A key focus area for the company will be the Seram Island, where Lion holds a 2.5% participating interest in the Seram (Non-Bula) PSC and has been awarded the East Seram Gross Split contract, with 100% operating interest, on 2 May 2018. Background Information South Block ‘A’ PSC The block was awarded in May 2009 to Realto Energi Nusantara Corelasi (RENCO) (51%, operator) and PT Prosys Oil & Gas International. Prosys (49%). KRX Energy Pte Ltd was reported on 31 October 2012 to have received government approval for the acquisition of 35% non-operating stake in the block from Prosys, which retained a 14% stake. Lion Energy provided the funds to KRX for the said stake acquisition. Lion Energy, in return, would earn a 30.77% stake in KRX under an earlier deal announced on 18 June 2012. Consideration for the participating stake in the block would involve KRX paying 49% of the gross cash calls of USD 8 million made by operator RENCO for the current and future work program. After the payment of the said amount (USD 3,920,000), expenditures by the participants would be on an equity share basis. KRX’s 35% stake was delivered free and clear of all loans, liens, mortgages, and any other encumbrances, specifically clear of any requirement to reimburse Prosys for the paid signature bonus, or part thereof. Lion Energy announced on 22 January 2013 an agreement with KRX Energy for the acquisition of all the remaining issued share capital of KRX, in addition to the 30.77% it was previously holding. RENCO and KRX increased the respective stakes in November 2016 following the default of PT Prosys Oil & Gas International. The new interest holding became RENCO, 59.3% and KRX, 40.7%. After partial area relinquishments, the PSC covers 421 sq km which include all the previously identified prospects and leads. The top six prospects in the block are estimated to contain recoverable resources of approximately 25 MMbbl of oil and condensate and 514 Bcfg (mid-case, on a 100% interest basis). In early April 2014, the operator had completed 183 km 2D seismic survey in the block. The main objective of the survey was to identify high-grade lead and prospects (Simpang, Djerneh, Amanah, Sungai Iyu, Paya Bili). The survey was conducted by PT Quest Geophysical Asia. This seismic campaign is one of the firm commitments for the PSC. Previous wells in the block were drilled by Asamera from the mid-1960s up until the mid-1980s. In A-1: Krueng Tuan 1, Geudongdong West 1, Pineueng South A1 and A2, Pelawi, all encountered gas shows. Three appraisals of the Paya Bilik discovery, not covered by this block, recovered minor oil. In A-2 both Sungai Lyu A-1 and Talaga Muka had oil shows, the former also had gas shows. Amanah Timur 1 Wildcat Amanah Timur 1 was plugged and abandoned on 19 January 2017 after unsuccessfully attempting to free a stuck pipe. The well was spudded on 3 January 2017 and was drilled to a TD of 347 m, shallower than the PTD of 570 m. Despite not reaching the deeper targets (“800” and “900” sandstones), the well encountered several potential gas and oil zones in the shallower section from 115 m down to 347 m (“400”, “450”, “500” and “700” sandstones of the Keutapang Formation). The reservoir was encountered 29 m shallower than anticipated. The stuck pipe incident occurred at a depth of 347 m within the “700” sandstone reservoir, where high gas readings caused increased pressure. During well control operations, a flare of condensate-rich gas was observed, which was interpreted to originate from the “700” reservoir Amanah Timur 1 targeted multiple sandstone reservoirs within the Upper Miocene Keutapang Formation. The shallower reservoirs, between approximately 100 and 400 m depth, have produced approximately 200,000 bo in pre-WW II time at the nearby Paya Bilik field. Additional targets were deeper, untested sandstones of the Lower Keutapang Member. The final operating cost for Amanah Timur 1 is expected to be lower than the budgeted cost of USD 1.3 million which included well site preparation, completion and up to three production test runs. Amanah Timur 1 fulfilled exploration commitments for the block, preventing the USD 3 million penalty stipulated in the PSC in case of non-fulfilment. The Amanah Timur structure is a faulted anticline, well defined by seismic imaging. As of end July 2017, prospective resources (P50) for Amanah Timur was estimated at 3.9 MMbo and 4.5 Bcfg, with low case (P90) of 1.7 MMbo and 2 Bcfg, and upside of 8.8 MMbo and 10 Bcfg (P10). Jerneh Prospect The Jerneh prospect is a large four-way closure on trend with the Pase and Matang fields. According to Lion, Jerneh is the largest undrilled prospect in North Sumatra, with a potential closure area between 7.9 and 63 sq km. The proposed Jerneh 1 well could have a PTD of around 1,900 m and will primarily target the Lower Miocene Peutu Formation limestones. Lower-Middle Miocene Belumai Formation sandstones are secondary targets. The Jerneh prospect is estimated to contain unrisked mean prospective resources of 329 Bcfg and 7.5 MMbc, with a 34% chance of success. Estimated well cost would be around USD 5 million. Analogues for the prospect are the Pase and Matang fields in the basin. Prospective resource estimates for the Jerneh structure are: low case (P90) of 64 Bcfg and 1.5 MMbc, medium case (P50) of 223 Bcfg and 5.3 MMbc, and high case (P10) of 760 Bcfg and 17.6 MMbc.

Lion Energy has sold its 40,7% interest in South Block A PSC (421km²) to Blue Sky Resources (Renco op.59,3%)

On 26 June 2019, SDX Energy announced that the Raboul 7 development well was completed as an oil producer in the West Gharib concession, onshore Gulf of Suez. The well was tied-in to existing production facilities and was brought on-stream at an initial rate of 415 bo/d. Raboul 7reached a TD of1,623 m and encountered approximately 41m of net heavy oil pay cross the Yusr and Bakr Miocene sandstones. The Rabul field was discovered by SDX Energy in 2017. So far, eight development wells had been drilled there.

SDX Energy announced that the Raboul 7 development well was completed as an oil producer in the West Gharib concession, onshore Gulf of Suez. The well was tied-in to existing production facilities and was brought on-stream at an initial rate of 415 bo/d.

On 4 February 2020 RockRose Energy announced that it has signed a Sales and Purchase Agreement to acquire 100% equity of Speedwell Energy (1) Limited which holds 100% interest in the Cotton discovery formerly known as Carna located in licence P2341. RockRose has initially paid a limited consideration but a further payment will be made at the Final Investment Decision (FID). The plan to develop the field includes the drilling of two horizontal development wells which are planned to produce at 12,000 boe/d (70 MMcf/d). Speedwell has prepared a draft Field Development Plan for submission to the OGA. The field was discovered with well 43/21b-5Z in 2009 encountering a gas column of up to 1,260 ft over six gas sandstone packages. Speedwell estimated the discovery to contain 97 Bcf. Following completion of the deal interest in P2341 will be held by RockRose Energy Plc.

RockRose Energy announced that it has signed a Sales and Purchase Agreement to acquire 100% equity of Speedwell Energy (1) Limited which holds 100% interest in the Cotton discovery formerly known as Carna located in licence P2341.

Tullow has secured these 2 onshore blocks around the Ehy lagoon and adjacent to the Ghana border, meaning Tullow now controls most of the CI coastal onshore. Contracts can be expected to be signed before year-end with Tullow (op) and state Petroci partnering with 10%. CI-521 covers 1,334 sq km while CI-522 is 1,250 sq km.

Cote d'Ivoire (Cote d'Ivoire B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: CI-522 op. by QUEST (100.0%) to be check.CI-521 op. by QUEST (100.0%) to be check.2 op. by PEMEX (50.0%, RWE 50.0%) to be check.Block S op. by KOSMOS EN (40.0%, MOSMAN OG 40.0%, GEPETROL 20.0%) to be check.

Licensing authority is the Ministry of Petroleum.Contracts are normally of concession type, but the Government of The Gambia is open to PSCs if so desired. Rights are normally granted for a six-year exploration period (+10 years) with the state having up to a 15% back-in right. Most of the terms and conditions under the Petroleum Act and Model Contract of 2004, amended in 2007, are negotiable. Licensing is to be through direct negotiations with the country's Petroleum Commission. Interested companies are invited to contact: Jerreh Barrow Commissioner for Petroleum Ministry of Petroleum & Energy Petroleum House Brusubi Roundabout Bijilo The Gambia Tel: +220 996 33 13 E-mail: [email protected]   The available blocks as of February 2020 are understood to be as listed below. Five blocks are available. There was no change compared to the previous list. Total open acreage amounts to 15,495 sq km of which 11,443 sq km is onshore and 4,052 sq km is offshore. Open blocks       Block Name Area (sq km) Situation Block Basin Block A3 1,300 offshore Senegal (M.S.G.B.C.) Basin Block A4 1,376 offshore Senegal (M.S.G.B.C.) Basin Block A6 1,376 offshore Senegal (M.S.G.B.C.) Basin Lower River 6,475 onshore Senegal (M.S.G.B.C.) Basin Upper River 4,968 onshore Senegal (M.S.G.B.C.) Basin

Licensing authority is the Ministry of Petroleum.Contracts are normally of concession type, but the Government of The Gambia is open to PSCs if so desired.

Armour Energy Ltd has been awarded three exploration permits located in the Roma Shelf, Bowen-Surat Basin on 20 December 2018: ATP 2034-P, ATP 2035-P and ATP 2041-P.  The awards add to Armour’s increasing acreage for the Roma Shelf Project with 15 production licences and 10 exploration licences (seven of which have been awarded in 2018), now covering over 4,000 sq km.  The permits will have an effective start date of 1 January 2019. The permits increases Armour’s net acreage by 500 sq km in the basin (or over 10% increase) and are operated by Armour’s subsidiary company Armour Energy (Surat Basin) Pty Ltd. They have effective start dates of 1 January 2019 after being applied for in May 2018 and will expire on 31 December 2024. ATP 2041-P, located in the Taroom Trough, has been specifically awarded as a domestic gas supply area and covers an area of 457 sq km.  Any gas supplied under the permit or any future associated production licences must be supplied to the Australian domestic gas market under the conditions of the award. ATP 2034 and 2035 do not hold this obligation. ATP 2041-P was applied for as PLR201718-2-4 on 31 May 2018, with Armour announced as the preferred tenderer on 15 November 2018.   ATP 2035-P and ATP 2034-P, which cover areas of 12 sq km and 30 sq km respectively, were announced as being offered to Armour Energy, as the preferred bidder, on 26 September 2018.  Both are also located in the Taroom Trough and were applied for under PLR201718-2-6 and PLR201718-2-7, respectively. In the ATP 2034 area there is one previously drilled well, Onerry 1. The well was a dry hole.  The ATP 2035 area does not contain any exploration wells. Armour reported that the permits are all prospective for both gas and liquids, and are located close to existing Armour acreage in the basin, as well as being in close proximity to existing gas infrastructure, that is linked to Armour’s Kincora gas plant.  Armour is planning to increase production from Kincora to 20 TJ/d (18.86 MMcf/d) and will likely look to exploring its new acreage for additional resources to add to production. Armour was required to complete the negotiation of land access, native title and environmental agreements before the permits were awarded, as Authority to Prospect permits. The three permits are prospective for both gas and liquids with the possibility of over-pressured tight Triassic and Permian reservoir sections which has been observed across neighbouring permits. Close to existing gas infrastructure linked to Armour’s Kincora gas plant, any commercial discoveries could be utilized to increase Armour’s production from Kincora as planned to 20 TJ/d (18.86 MMcf/d).

Australia, ATP 2041-P

WA-45-R, Dampier Basin off WA, WD 63m, TD 3,998m,  638m gross intv, said to be one of the largest columns ever discovered across the NW Shelf, 245m net (gas-cond.) pay between 3,360-TD in the North Rankin + Mungaroo fm’s, CGR up to 10 bbl/MMcf, 7% CO2, to P&A after completion of logging, Noble Tom Prosser JU then to Dorado-2 appr.

Australia (Rankin Platform (North Carnarvon B.)) Rankin

Equinor spudded 30/6-31 S using the "West Hercules" S/S on 4 April 2020. The rig was on site on 11 March 2020 but a few days later it had left and was back at shore, delayed due to the coronavirus disease 2019 (COVID-19). 30/6-31 S targeted the Middle Jurassic Helleneset prospect on the eastern flank of Oseberg in PL 053 and it was drilled to TD at 2,852 m (2,832 m TVD) in the Middle Jurassic Ness Formation. The Intra Heather Formation objective contained poorly developed sands and the well is dry. It was abandoned on 25 April 2020. Equinor was successful earlier in the year (July 2019) in drilling a well on the western flank of Oseberg. An exploration extension of development well 30/6-H9 (T4) found a 112 m oil column in the Lower Jurassic Statfjord Formation in the southern part of the Alpha structure, a segment of Oseberg that was previously undrilled (and known as Alpha Main Statfjord). Estimated recoverable reserves are 22 MMbo. Equinor brought the new volumes online shortly after discovery and was considering the use of water injection to boost production further. The drilling was part of the Oseberg Vestflanken 2 project which came onstream in October 2018 using a new platform – Oseberg H. Interest in PL 053 is divided between Equinor Energy AS (49.3% + operator), Petoro AS (33.6%), Total E&P Norge AS (14.7%) and ConocoPhillips Skandinavia AS (2.4%).

Norway (East Shetland B. (Viking Graben Province)) Statfjord

PL 836 S, location between Kristin + Maria, WD 313m, TD 4,566m (Åre fm), 35m hc layers in the Ile fm, 120m oil in the Tilje fm (75m poor-good reservoir), 60m oil in the Garn fm (poor-moderate reservoir), OWC 4,095m. 4-15 MMcum boe recoverable. Well to TP&A, Scarabeo 8 SS. Wintershall Dea (op), partners DNO + Spirit.

6406/03-10 (Bergknapp) expl. (Wintershall Dea 40%. op, DNO 30%, Spirit 30%), in PL 836 S, location between Kristin + Maria, WD 313m, TD=4566m (Åre fm), 35m hc layers in the Ile Fm, 120m oil in the Tilje Fm (75m poor-good reservoir), 60m oil in the Garn Fm (poor-moderate reservoir), OWC=4095m. 4-15 MMcum boe recoverable.

Biyaq Oil Field Services has agreed to farm out a 20% interest to Tethys Oil in Mudawrat block 56, 5,808 sq km mostly onshore Eastern Flank + Oman Tertiary Basin. The USD 9.5 MM cash-and-carry deal is subject to govt approval and will result in partnership becoming Medco (op) 50%, Intaj 25%, Tethys 20% + Biyaq 5%.

Tethys Oil announced that it had signed an agreement with Biyaq Oil Field Services (->5%, Medco Arabia op. 50%, Intaj LLC 25%), to acquire a 20% interest in the Block 56 (Mudawrat).

CGX Energy and Frontera Energy, on 4 December 2018, announced that they have signed a farm-in letter agreement thus enabling the Guyana-focused explorer to finance the drilling costs for two shallow-water offshore blocks in the Guyana-Suriname Basin. The blocks are 100% owned and operated by CGX subsidiary, CGX Resources. CGX has been seeking a farm-in partner for the past few years. Frontera, formerly known as Pacific Rubiales, holds 45.6% in CGX's outstanding shares. The deal is structured as thus: in exchange for a US$ 33.3 million signing bonus, Frontera will gain 33.33% WI in the Corentyne and Demerara blocks. Frontera will also pay for a third of applicable costs, as well as funding an additional 8.333% of CGX's direct drilling costs for the initial exploratory commitment wells in the two blocks. CGX will remain operator, with assistance from Frontera. The farm-in is subject to the necessary regulatory approval.The Corentyne Block is located on the Guyana's eastern maritime border, directly south of ExxonMobil's prolific Stabroek Block. The named Utakwaaka NFW is required to be drilled by 27 November 2019, with an additional well to be drilled by 27 November 2022. ExxonMobil's Pluma 1 NFW, on the Stabroek Block, was announced as a discovery on 3 December 2018. It is located roughly 3km to the north of the Corentyne Block boundary. Exxon and partners also plan to spud the Aimara 1 NFW in mid-December 2018, located roughly 15km to the north of Corentyne.The Demerara Block, awarded in February 2013, is located directly to the south-west of the Stabroek Block, and is adjacent to the Tullow operated Orinduik Block. A commitment exploration well is required by 12 February 2021, with another further well by 12 February 2023. Demerara lies roughly 35km up-dip of Exxon's April 2018 Sorubim 1 NFW on the Stabroek Block, which failed to encounter commercial quantities of hydrocarbons.CGX will repay roughly US$17 million in debt owed to Frontera using the US$ 33.3 million signing bonus. That debt is due by 31 March 2019, but is expected to be paid earlier, by way of offset against the signing bonus. Frontera have also agreed to extend its 25 April 2018 bridge loan to 30 September 2019, to the tune of US$ 8.8 million plus interest. Frontera will seek regulatory approval to have the option to have the outstanding bridge loan repaid in CGX common shares at any point on or before maturity of the loan. Separately, Frontera will also agree to guarantee equity financing of CGX up to US$ 20 million, which will enable CGX to settle its US$ 8 million liabilities with Japan Drilling Co, leaving CGX with net cash of US$ 27 million to fund drilling costs. If Frontera can exercise a conversion right attached to the bridge loan, the Canadian company could increase its ownership from around 45.6% to up to approximately 77.5%.Frontera's acquisition of WI in Corentyne and Demerara would mark the company's first foray into Guyana under its rebranded name. The majority of Frontera's asset are located onshore Colombia, with a few blocks onshore Guatemala and Peru, and a solitary offshore Peruvian block.<P />

CGX Energy and Frontera Energy, on 4 December 2018, announced that they have signed a farm-in letter agreement thus enabling the Guyana-focused explorer to finance the drilling costs for two shallow-water offshore blocks in the Guyana-Suriname Basin. The blocks are 100% owned and operated by CGX subsidiary, CGX Resources. CGX has been seeking a farm-in partner for the past few years. Frontera, formerly known as Pacific Rubiales, holds 45.6% in CGX's outstanding shares.

Baraka Energy and Resources Ltd has reported that it is seeking a farm-in partner for exploration permit EP 127, located in the Georgina Basin. The permit is located in the Northern Territory, where discussion around the future of fracking was ongoing throughout 2017.  The ban on fracking was lifted in 2018 and Baraka reported in August that this has allowed it to continue seeking a farm-in partner within the permit.  While the moratorium on fracking activity was in place, Baraka commented that the lifting of this would a positive towards is future work on the permit. During the latter part of 2017 Baraka reported that it was continuing to plan a Resource Imaging Technology Survey, using Seismo-Electric technology. Baraka would like to acquire a trial survey close to existing wells in the permit, as it is a new technology in its infancy in Australia. In March 2016 it was reported that an offer of intent from the Northern Territory Department of Mines and Energy to renew the permit had been accepted.  This was approved on 6 April 2016, with the permit renewed for a further five years as of December 2015. In March 2015 Baraka announced that its joint venture partners in the permit, PetroFrontier and Statoil, would be withdrawing from the asset.  This will give Baraka a 100% interest position, and operatorship. Baraka reported on 18 March 2016 that the transfer of interest was underway. A recent unconventional exploration programme, undertaken over four permit areas, including EP 127, by Statoil as part of a farm-in, saw three wells drilled within the permit in 2014.  The wells were targeting shale liquids potential, alongside the other wells in the programme, though results were disappointing. This led to Statoil’s withdrawal from further work in the programme to farm-in and withdrawal from the permits. EP 128 was originally included in Baraka’s farm-in opportunity.  Initially, in 2015, Baraka had lodged for a renewal for EP 128, which was due to expire on 13 June 2015. However, the terms for renewal did not meet Baraka’s requirements and so the permit was subsequently relinquished in January 2015. EP 127 was due to expire on 13 December 2015, however Baraka applied for a renewal in early 2016.  This was granted and the permit is now valid until December 2020.  The permit covers an area of 14,280 sq km and was awarded on 19 December 2007. Baraka holds 100% interest and operatorship. Baraka reported in early 2016 that it had been approached by a Canadian company interested in pursuing the conventional potential within several Georgina Basin permits and reported that it would continue discussion during the renewal process, whilst looking for additional farm-in partners. However, in October 2016 Baraka reported that discussions with the Canadian company had ceased and it now would continue to market the opportunity to other interested companies.

Baraka Energy and Resources Ltd has reported that it is seeking a farm-in partner for exploration permit EP 127, located in the Georgina Basin. The permit is located in the Northern Territory, where discussion around the future of fracking was ongoing throughout 2017.

Arar secured sole, 5-yr rights to 3 licences in the Zagros Fold Belt, SE Turkey, on 22 Nov '18: N42-A (615 sq km), N42-B (615 sq km), M42-C (613 sq km).

Arar Petrol ve Gaz Arama Uretim Pazarlama A.S has been awarded the M42-C, N42-B, N42-A exploration licence.

Discover Exploration is embarking on a farmout offer for its 25% in the Tullow-operated blocks 35, 36 + 37, total 17,853 sq km in Indian Ocean deepwaters. Drilling is tentatively planned in 2021. Tullow (op), partners Discover + Bahari Res.

Discover Exploration is embarking on a farmout offer for its 25% in the Tullow-operated blocks 35, 36 + 37, total 17,853 sq km in Indian Ocean deepwaters. Drilling is tentatively planned in 2021. Tullow (op), partners Discover + Bahari Res.

The authorities have lowered the number of blocks that will be offered in the planned offshore bid round from 48 to 38. Total area on offer is 225,000 sq km in shallow-to-ultradeepwaters, schedule unclear but presumably shortly. 14 blocks are in the N. part of the Argentina Basin, 18 blocks over 90,000 sq km in the W. part of the Malvinas Basin, and 6 blocks over 5,000 sq km in the Austral Basin. Contact: Rodrigo Garcia Berro at [email protected] or +54-911-6648-9244.

The authorities have lowered the number of blocks that will be offered in the planned offshore bid round from 48 to 38. Total area on offer is 225,000 sq km in shallow-to-ultradeepwaters, schedule unclear but presumably shortly.

Statoil, sole holder of PL 630 + 630 BS (part-blocks 31/1 + 35/10) after the witdrawal of Capricorn, Engie and Idemitsu in Nov ’17, has transferred a 40% stake to Wellesley Petroleum effective 29 Dec ’17. Statoil retains operatorship.

Statoil, sole holder of PL 630 + 630 BS (part-blocks 31/1 + 35/10) after the withdrawal of Capricorn, Engie and Idemitsu in Nov ’17, has transferred a 40% stake to Wellesley Petroleum effective 29 Dec ’17. Statoil retains operatorship.

The Sepia and Atapu areas, which were unbid in the recent highly anticipated but disappointing Onerous Assignment Surplus Production Rights Bid, also called the Transfer Rights area, in the Santos Basin pre-salt polygon, could be again put up for bid in the first half of 2020, according to sources in the Brazilian government. The idea is to review and evaluate the bid parameters with enough time to requalify the areas for bid was the message delivered at a conference, in Rio de Janeiro. The official maintained that the government should continue planning the 2020 rounds while also discussing with Congress whether to maintain the Petrobras right of first refusal and the possibility of offering blocks in the pre-salt polygon under the concession model. The debate over what will be done with these unbid blocks will be on the agenda at the first Investment Partnership Program (PPI) meeting in 2020. On 6 November 2019, Brazil held its Onerous Assignment Surplus Production Rights Bid. What was touted to be the richest bid round ever wound up being disappointing as high signature bonus requirements deterred most oil majors from bidding in the round except for Petrobras with a minor participation by Chinese state companies CNOOC and CNODC. The minimum profit oil specified for the bid round was set at 23.24% for Buzios and 18.15% for Itapu. The Petrobras bid offered the minimum for both blocks. These companies were the only bidders as over a dozen majors registered for the round declined to place bids and two of the four offered blocks did not receive bids. The CNPE set the signature bonus 22.86 billion reais (US$ 5.5 billion, first oil expected 2021) for Sepia, 13.74 billion reais (US$ 3.5 billion, first oil expected 2020) for Atapu. The lack of participation in the round was a harsh blow to Brazil which was depending on a big revenue boost from the round to offset substantial government deficits from a sagging economy over the last few years. The failure of the round was blamed by experts on the expensive signing bonuses, the complex and difficult to understand production-sharing contracts which would require unitization and an untested framework where Petrobras would have full rights to some reserves while winning bidders would in theory only have the rights to reserves above 5 Bboe. Complicated Petrobras reimbursement requirements lacking transparency and marginal economics with substantial risk over time were other factors cited for the poor results of the round. Brazilian officials said the results were satisfactory but acknowledged that giving Petrobras preferential rights ownership and operating rights in the pre-salt was bad for competition and suggested the government might end that legal provision in the future. Reimbursable investment costs in the round were determined to be US$ 2.37 billion for Sepia and US$ 1.93 billion for Atapu and surplus volumes for the blocks were estimated to be 550 MMboe in Atapu and 500 MMboe in Sepia.

The Sepia and Atapu areas, which were unbid in the recent highly anticipated but disappointing Onerous Assignment Surplus Production Rights Bid, also called the Transfer Rights area, in the Santos Basin pre-salt polygon, could be again put up for bid in the first half of 2020, according to sources in the Brazilian government.

On 13 November 2017, Western Gas Corporation Pty Ltd announced that it has acquired the Equus Project fields and surrounding permits from Hess Corporation. Western Gas reports that it has acquired 100% interest in Retention Lease WA-70-R, which covers all of the project’s 11 gas and condensate fields and four surrounding exploration permits: WA-390-P, WA-474-P, WA-518-P and WA-519-P, all located in the Exmouth Plateau, North Carnarvon Basin. The deal is yet to be registered with the National Offshore Petroleum Titles Administrator (NOTPA). On 30 March 2016 Hess was granted a retention lease over the Equus Project fields and announced in late-2016 plans to defer further development of the project to focus on other assets in its portfolio. The commercial discoveries in permit WA-70-R were to produce to Woodside’s operated NWS LNG facilities for processing, through an agreement with Hess in 2015. The final development concept and marketing studies were due to take place by Hess in 2016 but Western Gas has still received a fully appraised and development-ready project and plans to develop the gas and condensate for domestic supply to Western Australia. Western Gas believes this opens a critical window to increase supply into a market which could enter a shortfall by 2021 without new developments. Western Gas reported that it plans to commercialise the eight main discoveries, which were made between 2008 and 2010: Mentorc, Bravo, Nimblefoot, Chester, Glencoe, Glenloth, Briseis and Rimfire. The discoveries hold combined estimated 2P recoverable gas reserves of 4.3 Tcf. Hess’ field development plan included 17 production wells, and the installation of associated infrastructure to allow the production of gas from the discoveries to an offshore Floating Production System (FPS), with gas then transported via subsea pipeline to third party offshore infrastructure (NWS facilities). Upon the award of WA-70-R in 2016, Hess signed up to continue field developing planning and broadband reprocessing of the Glencoe 3D seismic survey data over 1,539 sq km to further define the development potential of the deeper Equus resources. Marketing studies and planned to run through until the end of the current licence validity period which ends on 29 March 2021. The four surrounding exploration permits cover a combined area of 3,218 sq km. WA-390-P lies to the east of the Equus Project fields. Hess renewed the permit on 9 March 2017 for a period of five years, until 8 March 2022. Upon its award on 6 February 2007, the permit covered an area of 3,143 sq km over the Equus Project gas fields before being reduced in area upon the award of Retention Lease WA-70-R. In the remainder of the work programme, broadband reprocessing of 804 sq km of the Glencoe 3D seismic data is planned, which was acquired in 2008 after WA-390-P was awarded. Subsequent work will involve geological and geophysical studies along with depositional modelling of the Mungaroo Formation, seismic inversion and interpretation and prospect characterisation. WA-474-P lies to the north of the Equus Project fields. Unlike WA-390-P and WA-518-P, the work conditions have not been altered in response to Hess’ option to defer the project development. WA-474-P still covers its original area of 1,050 sq km and is due to expire on 3 May 2018. WA-518-P lies to the northwest of the Equus Project fields. On 4 October 2017 Hess varied the work commitments and extended the first three year term by 12 months. The extension was planned to facilitate time to complete 885 sq km broadband reprocessing of the Honeycombs 3D survey data which was purchased for around AUD 6.2 million earlier in the term. The first exploration well is scheduled at the end of the first term, following the seismic reprocessing, geological/geophysical studies and well planning. The well is expected to cost around AUD 50 million. WA-519-P lies to the southwest of the Equus Project fields and was awarded on 18 September 2015. One exploration well has been scheduled in term five at a forecasted cost of AUD 31.3 million. The commitment to drill the well must be made prior to the commencement of that term on 18 September 2019. On 13 November 2017, Western Gas Corporation Pty Ltd announced that it has acquired 100% interest of the Equus Project and surrounding exploration permits from Hess Corporation. Completion of the deal will see Hess exit the region to focus on its core assets.      

Australia (North Carnarvon B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: WA-474-P op. by HESS (100.0%) to be check.WA-518-P op. by HESS (100.0%) to be check.WA-390-P op. by HESS (100.0%) to be check.WA-70-R op. by HESS (100.0%) to be check.WA-519-P op. by HESS (100.0%) to be check.

Petrobras signed a sales and purchase agreement with Petronas for a 50% non-operated interest in the Tartaruga Verde prod. lease (BM-C-036 contract, Campos Basin), the Espadarte prod. lease Module III,  and a 100% interest in the Bauna lease, Santos Basin.  The deal is pending ANP and CADE approvals.

Petronas entered into a SPA with Petrobras (->50% op.) for 50% of the Tartaruga Verde field in BM-C-036 Concession and its facilities, and Module III of the Espadarte field, both located in DW. No terms were disclosed, and completion of the transaction is subject to certain conditions.

On 12 February 2020 Horizon Energy completed the acquisition of a 40% interest in licences P2329, P2427 and P2486 and a 30% interest in P2300 from Simwell Resources. Horizon also acquired a further 10% interest in P2300 from Comtrack Ventures. Operator of the licences, Ardent Oil Limited has been farming out the acreage. A highly prospective Upper Permian Zechstein (‘Z2’) play fairway has been interpreted within the acreage. The play has broad similarities with established analogues further east in Poland and Germany. A total of 12 leads have been mapped with individual most likely prospective resources of 165 Bcf, all 12 leads approximately contain 2 Tcf. The leads are a combination of structural and stratigraphic trapping, and the play fairway is identified on isopach maps of the Z2 Zechstein interval. Reservoir objectives consist of the Hauptdolomite carbonate buildups deposited in high energy shoals / barriers or reefal facies. Zechstein carbonates have been encountered in nearby wells and flowed hydrocarbons from intervals 40 – 60 m thick. Porosities of 6 – 20% have been recorded. The Stassfurthalite of the Z2 cycle provides top seal for the Hauptdolomite leads. Depths to the top of the Hauptdolomite are approximately 2,100 – 2,300 m subsea. Dinantian or early Namurian deep marine shales are the most likely sources of gas. Reservoir performance and trap integrity are considered the main risk. Following completion of the deals, interest in P2329, P2427 and P2486 is held by Ardent Oil Ltd (25% + operator), Horizon Energy subsidiaries Horizon Energy Partners Ltd (45%), Horizon Energy Acquisition Ltd (20%) and Simwell Resources Ltd (10%). Interest in P2300 will be held by Ardent Oil Ltd (50% + operator), Horizon Energy Partners Ltd (20%), Horizon Energy Acquisition Ltd (20%) and Simwell Resources Ltd (10%).

United Kingdom, P2427

Buzi block, north of the Pande, Temane + Inhassoro fields onshore Mozambique Basin, TD 1,567m in March, believed gas find likely in the L. Grudja target (6 zones of interest identified), Kain Vincent-5 rig. Ops, tests and therefore confirmation, are on hold as is also current Buzi-2 appr owing to CV19 restrictions. Buzi Hydrocarbons (op), partner ENH.

(Mozambique b.), Buzi-1 exploration well in Buzi block, operated by Buzi Hydrocarbons Pte (75%), partner ENH (25%), believed gas find likely in the L. Grudja target (6 zones of interest identified).

BGM was drilling with oil shows the 1-SDR-001-ES (1-BGM-001-ES) new-field wildcat (NFW) in the ES-T-476 block in the onshore Espirito Santo Basin during mid-July 2019.  The operator filed an oil show report with the ANP for the well on 17 June 2019 and a second oil show report on 7 July 2019. The NFW was spudded on 21 May 2019. The NFW has a proposed total depth (PTD) of 1,605 m with the Early Cretaceous Sao Mateus and Mariricu Formations as the primary target. The well is located in the south-central area of the block approximately 1.2 km south-west of the 1-LB-0001-ES wildcat plugged by Petrobras in 1973. BGM Petroleo e Gas Ltda holds 100% working interest in the ANP Round 14, ES-T-476 contract. On 6 December 2018, the ANP approved of Bertek divesting its 100% working interest in the ES-T-345 and ES-T-476 blocks in the onshore Espirito Santo Basin to newcomer BGM Petroleo e Gas Ltda.  On 29 January 2018, Bertek with 100% working interest was granted official awards by the ANP for the ES-T-345 and ES-T-476 blocks in the onshore Espirito Santo Basin from the ANP Round 14.  The company paid a total signature bonus of USD 153,312.30 for the two blocks and has work commitments of USD 551,735.02.  The blocks cover a total area of 46.14 sq km. The contract has one five-year exploration period and 7.5% royalties.  The rentals for the blocks are USD 14.15/sq km/year.  The local content is stipulated as 50% in the five-year exploration phase and in the development production phase is 50%.

1-SDR-001-ES (1-BGM-001-ES) nfw. (BGM %) in the ES-T-476 onshore block, P&A with oil shows.

As announced on 18 March 2019, Pan Orient has completed the drilling of outpost well L53 DD3, within the L53 DD field in the L53/48 Reserve Area A, located onshore Chao Phraya Basin, as an oil well. The well encountered an interpreted combined 38.5 m true vertical thickness of net oil pay within five separate sandstone reservoirs. The well results have exceeded pre-drill expectations and encountered the thickest net oil pay within the L53 DD field. Spudded on 3 March 2019, L53 DD3 was drilled back-to-back with a new pool wildcat, L53 DD4, using the “E-02” land rig. The structural high L53 DD3 was designed to effectively access the thick reservoirs in the DD/EE, BB/CC and AA sands which were penetrated earlier in L53 DD2 and L53 DD1 wells. The well was drilled to a total measured depth of 1,380 m (1,110 m TVD) to a bottom hole location approximately 600 m southwest of the surface location. The top of the primary target BB/CC sand was encountered 9.3 m higher than L53 DD2. Oil pay was also encountered in AA2 sand, which was observed in L53 DD4 well. The previous exploration well, L53 DD4 encountered a total net oil pay of 15.6 m in the BB/C sand, as well as a new pool, AA2 sand. The CC sand was encountered 7.5 m structurally higher than in L53 DD1 with good reservoir quality and thickness. However, the shallower AA sands were poorly developed while the deeper DD/EE sands were water bearing. The well reached a total depth of 1,950 m (1,400 m TVD). The operator is currently waiting for approval from Department of Mineral Fuel (DMF) to proceed with the commencement of a 90-days well test for L53 DD4 and L53 DD3 wells. As of 31 January 2019, the concession holds remaining crude oil reserves of 2.7 MMbbl from the Lower Miocene sandstone reservoir. The L53/48 concession is fully owned and operated by Pan Orient (Siam) Ltd, which is in turn controlled by Pan Orient Energy Corp (50.01%) and Sea Oil Public Company (49.99%). The exploration Area A and B will expire in January 2021, after which the production areas (A, B, D and G) will be retained. Background Information The L53 DD field was discovered in November 2018, by L53 DD1 wildcat. Oils were trapped in the Lower to Middle Miocene Series structural play sealed by Middle Miocene Series mudstone. The daily oil production for L53 DD1 is around 530 barrels, based on the reported cumulative production from 21 November 2018 to 10 February 2019. This discovery was immediately appraised by L53 DD2 well. L53 DD2 was drilled to an optimized up-dip location, approximately 560 m southwest of the discovery well L53 DD1, originally targeting the deepest two of the three reservoirs encountered in the discovery well. The well flowed heavy oil at approximately 580 b/d through a 3.9 m true vertical thickness of perforations within the DD and EE sands. Production test results confirms that the DD/E sands in L53 DD1 well and BB/C sands in L53 DD2 well are within the same oil pool. Both wells have also been shut-in after the completion of its production test in February 2019, until an approval is granted for L53 DD field Production License by the Department of Energy Fuel (DMF). The approval is anticipated to be granted in April/May 2019.

Pan Orient has completed the drilling of outpost well L53 DD3, within the L53 DD field in the L53/48 Reserve Area A, located onshore Chao Phraya Basin, as an oil well. The well encountered an interpreted combined 38.5 m true vertical thickness of net oil pay within five separate sandstone reservoirs.

Faroe Petroleum, the independent oil and gas company focussing principally on exploration, appraisal and production opportunities in Norway and the UK, has been awarded eight new prospective exploration licences, including four operatorships, in the Norwegian North Sea under the 2017 Norwegian APA (Awards in Pre-defined Areas) Licence Round. Licence PL926 Blue Libelle – Blocks 33/9, 33/12 and 34/10: Faroe (40% and operator), DNO (30%) and Concedo (30%): The Blue Libelle is on the Tampen Spur on the north-western margin of the North Viking Graben. It is a structural prospect of Middle Jurassic age sandstones that sits between the producing fields Statfjord and Gulfaks. The work programme involves acquiring and/or reprocessing 3D seismic data and a drill or drop decision by February 2020. Licence PL908 Århus – Block 9/11, 9/12, 10/10 and 10/11: Faroe (30%), Statoil Petroleum (70% and operator): The Århus Prospect is located in the Åsta Graben, north of the Trym Field in the Central Graben where various targets in the Oligocene Vade Formation have been mapped. The work programme involves the acquisition of new 2D data with Electromagnetic data and a drill or drop decision by February 2020. Licence PL906 Skræmetindan – Blocks 7/11 and 7/12: Faroe (20%), Aker BP (40% and operator), Maersk (20%) and Statoil (20%): The Skræmetindan Prospect is located on the Cod Terrace in the Central Graben. It is a structural prospect of Jurassic age containing sandstones in the Ula Formation. The work programme involves acquiring and reprocessing 3D seismic with a drill or drop decision by February 2020. Licence PL006 E  SE Tor Extension – Block 2/5: Faroe (85% and operator), AkerBP (15%): This licence contains a portion of the Paleocene Gomex exploration target which extends outside the existing SE Tor Licence. The work programme is the same as the existing PL006C SE Tor. Licence PL810 B  Katie Extension – Blocks 2/1 and 8/10: Faroe (40% and operator), Spirit Energy (30%) and AkerBP (30%): The licence contains the north-eastward extension of the Katie Prospect located on the eastern side of the Oda Development. The work programme is the same as the existing PL810 Katie Licence, involving seismic reprocessing and a drill or drop decision by February 2019. Licence PL740 C  Brasse North Extension – Blocks 31/4: Faroe (50% and operator), Point Resources (50%): The licence contains the northward extension of the Brasse Extension on the eastern side of the Brage Field. The work programme is the same as the existing PL740/B Brasse Licence (Faroe 50%). Licence PL065 B  Tambar Extension – Block 1/3: Faroe (45%), AkerBP (55% and operator): This licence contains a potential north-westward extension of the Tambar Field. The work programme is the same as the existing PL065 Tambar licence. Licence PL019 E  Ula Extension – Block 7/12: Faroe (20%), AkerBP (80% and operator): The licence contains a potential eastward extension of the Ula Field. The work programme is the same as the existing PL019 Ula Licence. Graham Stewart, Chief Executive of Faroe Petroleum, commented: 'We are very pleased to announce the award of eight new and prospective licences in the latest Norwegian licensing round. We have further consolidated our position in core areas of the Norwegian continental shelf in which we have delivered recent exploration success. 'We look forward to high-grading these new licence opportunities in the coming period. This good quality new exploration acreage, together with our enhanced production portfolio and development pipeline, ensures that our shareholders are exposed to a well balanced and sustainable set of growth opportunities going forward. 'Faroe has a material and exciting drilling programme in 2018. We are currently drilling the Iris and Hades exploration well in the Norwegian Sea, to be followed by the Fogelberg appraisal well. Two further exciting Norwegian exploration wells, Rungne and Cassidy, are planned to be drilled in the second half of 2018.' Original article link Source: Faroe Petroleum

Faroe Petroleum, the independent oil and gas company focussing principally on exploration, appraisal and production opportunities in Norway and the UK, has been awarded eight new prospective exploration licences, including four operatorships, in the Norwegian North Sea under the 2017 Norwegian APA (Awards in Pre-defined Areas) Licence Round.

On 3 October 2018 Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd had signed a Heads of Agreement with Rathlin Energy (UK) Ltd (wholly owned subsidiary of Connaught Oil and Gas Ltd) on a proposed farm-in for a 16.667% interest each in PEDL 183. On 5 November 2018 in an update from Union Jack Oil, the company confirmed that it has now signed a farm-in agreement for the deal. The licence is located in East Yorkshire and contains the West Newton A-1 gas discovery. There are also plans to drill the West Newton B appraisal well in Q1 2019. The deal is subject to regulatory approval. West Newton B will be located approximately 1.5 km south of the 2013 West Newton well. It is planned to target three potential Permian reservoirs in the Brotheran, Kirkham Abbey and Cadeby formations. The well has a planned TD of 2,000 m to the base of the Permian section. It was initially planned to be drilled with the KCA Deutag T-61 rig. In November 2017 Rathlin confirmed that it still plans to drill the well and in December the company stated that it is currently out to assess and determine rig availability. Drilling is planned to take 6 - 12 weeks where the company is not planning to test any shale horizons (TD likely to be 1,000 m above the Bowland Shale) estimated to be deeper than its Permian targets. It is hoped that the well will determine the commerciality of the discovery. In an update from the company on 17 June 2015 it confirmed that East Riding of Yorkshire Council has granted planning permission for the well. On 26 November 2015 Rathlin announced that it was pleased that the planning committee has unanimously approved the planning application for an extension at West Newton A. Following the well encountering gas the company can move forward with investigating the commerciality of the discovery within the Permian Kirkham Abbey Formation. On 26 July 2016 the OGA confirmed that the Environment Agency has granted a permit for the drilling of the well. In 2013 Rathlin Energy drilled with West Newton 1 (A) well. The well was drilled to a TD of 3,150 m into the Dinantian Carbonate section in the Carboniferous and was tested. The well was located north of West Newton and east of Marton in the parish of Aldbrough, East Riding Yorkshire. It had a primary target based from 2D mapping and is a Permian aged Caedby Carbonate reef. The source rock potential is present within the Permian basinal sediments, the Westphalian coal measures and the Bowland shale sequence. PEDL 183 was awarded in the 13th Onshore Licensing Round and covers an area of 913 sq km. Interest in the licence following the deal will be held by Rathin Energy (66.666% + operator), Humber Oil and Gas (16.667%) and Union Jack Oil Plc (16.667%).

Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd had signed a Heads of Agreement with Rathlin Energy (UK) Ltd (wholly owned subsidiary of Connaught Oil and Gas Ltd) on a proposed farm-in for a 16.667% interest each in PEDL 183