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1-21 Han Asparuh offshore block, WD ~1,950m, ops susp. 9 Dec ’18, Noble Globetrotter II DS, results yet undisclosed. A 90-day option follows completion of the well. Total (op), partners OMV + Repsol.

Melnik-1 nfw Bulgaria WD ~1,950m, ops susp. 9 Dec ’18, Noble results yet undisclosed. A 90-day option follows completion of the well. Total (op), partners OMV + Repsol

Thr 3,379-sq km, undrilled Lepchinskiy block in the Baykit Basin, Krasnoyarsk Kray (E. Siberia) was auctioned 15 Dec ’17 to NovoKhim with a USD 0.43 MM offer (starting price USD 0.39 MM).    

Russia, not found

On 11 November 2019, Genel Energy plc reported that the deal to acquire East Africa Resource 25% stake in the SL10B, SL13 licence has been completed. Genel’s acreage is located onshore within the Somali and Sagaleh basins. In early November 2019, the company appointed Stellar Energy Advisor to run the farm-out process. The interpretation of the 2018 2D seismic data together with continued basin analysis has led to the maturation of a prospects and leads inventory for the SL10B, SL13 licence. A number of potentially high impact exploration targets have been identified within play types directly analogous to the prolific Yemeni rift basins. The SL10B, SL13 licence contains the Bur Dab 1 well, which found oil shows in 1958. Genel acquired a total of 3,150 km of speculative 2D data over the SL-10B, SL13 and neighbouring Odewayne licences. The portion over the SL-10B, SL13 was completed in January 2018, while the portion over the Odewayne block was completed in October 2017. The acquisition started in March 2017 and was conducted by the contractor BGP Inc. The survey was part of a Somaliland-owned speculative 2D seismic project. Genel purchased the seismic data covering its onshore acreage, which fulfilled its minimum work obligations. A surface oil seep study completed in 2015 supposedly confirmed the presence of a working hydrocarbon system with Late Jurassic source rocks and several potential reservoir/seal pairs. Genel believes that all its acreage in Somaliland could host over 2 Bbbl of oil. Interest in the SL10B, SL13 licence is held solely by Genel Energy plc. The Republic of Somaliland is bordered by Ethiopia in the south and west and it is located in northern Somalia. Somaliland remains internationally unrecognized but is considered economically stable and democratic. Somaliland declared independence from Somalia in 1991. Contact details Mike Adams Head of Africa Exploration Tel: +44 (0) 20 7659 51 43 Email: [email protected]   John Fisher Principal Geoscientist Tel: +44 (0) 20 7659 51 38 Email: [email protected]   Background Information Recent licence history Genel Energy plc (Genel) was awarded an exploration licence for onshore blocks SL-10-B and SL-13 in Somaliland in August 2012 (with 75% working interest in both). Genel was further awarded a 50% participating interest in the Odewayne PSA in November 2012. The Odewayne PSA covered former blocks SL-6, SL-7, SL-10A. On 5 August 2016, partner Sterling Energy announced that the Somaliland government had awarded a further two-year extension to the current exploration period of the Odewayne production sharing agreement (PSA). The PSA will last until 2 November 2018, with an option to extend it by subsequent 18-month (fourth period), one-year (fifth period) and one-year (sixth period) extensions to a maximum of 2 May 2022. According to Sterling, minimum work obligations for the exploration periods remained unchanged - namely the acquisition of 500 km of 2D seismic during the third period and the acquisition of 1,000 km of 2D seismic and one exploration well during the fourth period. Recent exploratory works Genel completed a gravity and aeromagnetic campaign over its total 40,300 sq km acreage in Somaliland in early 2013. Genel has been planning a 1,500 km 2D seismic survey over the Odewayne block since May 2013, however it has been delayed a number of times. Seismic operations in Somaliland were temporarily suspended due to deterioration in the security environment in 2014. Back then, Genel and other companies were waiting for the announced Oil Protection Unit (OPU) to become operational. OPU is a trained and equipped security force implemented by the government of Somaliland to support international oil companies in their exploration campaigns. Odewayne geology The Odewayne block (which was formerly known as Block 26) is located in the Nogal Uplift (Somali Basin). It was informally referred as the “Habra Garhajis Block” and it was held by Japan-based Petrosoma (an affiliate company of Prime Resources) until November 2012.The Odewayne block reportedly contains nine independently verified oil seeps typed to light oil-condensate hence a working hydrocarbon system may exist. The geology of the Nogal Uplift basin (also reported as Habra-Garhajis) is expected to be very similar to the producing basins of Yemen. A few kilometers north of the Odewayne licence, within the contiguous Guban Basin, the Dagah Shabel exploration/appraisal wells (DS 1, DS 2 and DS 3) found heavy oil in the late 50’s.

Genel has increased its participation in the SL10B / SL13 block to 100% through the acquisition of East Africa Resource Group's 25%.

16 June 2020, as reported by local media, Uzbekneftegaz (UNG) has made a gas discovery with well Urtakum (Ortakum) 1. The well has tested gas at a rate of 202,000 cu m/d (6.9 MMscf/d) through a 14 mm choke. No further details of the discovery have been reported so far.  The Urtakum discovery is located in the Amu-Darya Basin, close to the Shorkum, Andakli, Parsankul and Hoja Garbiy fields. The well was spudded in November 2019. UNG has now mobilised a rig to drill a second well at Urtakum.

(Amu-Darya) Urtakum (Ortakum) 1 nfw, (Uzbekneftegaz (UNG 100%) near the Shorkum, Andakli, Parsankul + Hoja Garbiy fields, gas discovery reported 16 Jun '20, tested 6.9 MMscf/d on a 14mm choke. A 2nd well is now planned at this location.

On 14 June 2020, the Canada-Newfoundland Offshore Petroleum Board (C-NLOPB) announced details on the Call for Bids NL20-CFB01 which contains 17 parcels located in the deepwater area of the Orphan Basin. The 17 parcels included in the call consist of a combined 41,705 sq km. The parcels are located from the shelf-slope break to deep water in water depths ranging from ~500 m in the west to ~3,000 m in the east. The parcels are sparsely populated with vintage 2D seismic but a large number of 3D seismic has been acquired in the area between existing exploration licenses EL 1148 and EL 1142. The deadline for the call for bids is at 12:00 p.m. Newfoundland Standard time, on 4 November 2020. Sealed bids are to be submitted prior to the closing date to the Canada-Newfoundland and Labrador Offshore Petroleum Board, Suite 100, TD Place, 140 Water Street, St. John's, NL A1C 6H6. Attention: The Chair. The following is a list of tracts included in the NL20-CFB01: Call for Bids NL20-CFB01       Tract Size sq km Issuance Fee CAD 2D 3D NL20-CFB01-01 2162.98 $2,500.00 yes   NL20-CFB01-02 2576.46 $3,250.00 yes   NL20-CFB01-03 1748.55 $2,750.00 yes   NL20-CFB01-04 2115.18 $3,000.00 yes   NL20-CFB01-05 2635.71 $3,750.00 yes   NL20-CFB01-06 2565.43 $3,500.00 yes yes NL20-CFB01-07 2451.4 $4,000.00 yes yes NL20-CFB01-08 2660.79 $3,750.00 yes yes NL20-CFB01-09 2645 $4,000.00 yes yes NL20-CFB01-10 2652.23 $3,500.00 yes yes NL20-CFB01-11 2586.22 $4,250.00 yes yes NL20-CFB01-12 2717.88 $3,500.00 yes   NL20-CFB01-13 2716.49 $4,000.00 yes   NL20-CFB01-14 2569.28 $3,000.00 yes yes NL20-CFB01-15 2020.87 $2,250.00 yes yes NL20-CFB01-16 2727.92 $3,500.00 yes   NL20-CFB01-17 2152.7 $2,500.00 yes yes Total 41705.09       Source: IHS Markit       © 2020 IHS Markit Three wells have been previously drilled in the area outlined in the Call area. The Chevron Great Barasway F-66 (TD 6,751 m) drilled in 2007, the ExxonMobil Lona O-55 (TD 5,580 m) drilled in 2010, and the Statoil (now Equinor Canada) Cupids A-33 (TD 2,900 m) drilled in 2015. All three wells recovered water from sampling test conducted in the Late Jurassic age formations. According to the C-NLOPB good sandstone reservoirs were encountered in the existing wells, but no shows or source rock were intersected. Exploration has focused on Cretaceous and Jurassic reservoirs, located in structural traps formed by rifting events and salt movement, stratigraphic traps are also present. Current understanding indicates that there is increased hydrocarbon potential in the deeper part of this complex basin. Any sector, parcel or license beyond 200 nautical miles off the coast of Newfoundland and Labrador is not represented by the Board to reflect the full extent of Canada's continental shelf beyond 200 nautical miles. Canada has filed a submission regarding the limits of the Outer Continental Shelf in the Atlantic Ocean with the Commission on the Limits of the Continental Shelf, the review of which is pending. Any call for bids based on a sector or parcel identified in this map and any licenses issued in those areas will be subject to approval as a Fundamental Decision under applicable legislation. The boundaries of sectors, parcels or licenses in areas beyond 200 nautical miles may be revised to reflect the limits of the Outer Continental Shelf established by Canada. All interest holders of production licenses containing areas beyond 200 nautical miles may be required, through legislation, regulation, license terms and conditions, or otherwise, to make payments or contributions for Canada to satisfy obligations under Article 82 of the United Nations Convention on the Law of the Sea. The following is included in the Call for Bids announcement. "A number of the parcels in this 2020 Call for Bids overlap in part with areas of fish harvesting activity. The C-NLOPB fully appreciates the importance of both the fisheries and petroleum sectors and will continue to engage with fisheries stakeholders and Fisheries and Oceans Canada (DFO) throughout the land tenure process. Any companies acquiring Exploration Licences pursuant to this Call for Bids will be required to engage with fishing interests before any oil and gas activities are authorized. Some of the parcels in this 2020 Call for Bids also overlap the Northeast Newfoundland Slope Marine Refuge. The C-NLOPB is focused on the protection of environmentally significant and sensitive areas and will also continue to work closely with DFO and others in this regard." Sole criterion for selecting the winning bids on all parcels in the call was the total amount of money committed to spending on exploration of the parcel during the initial 6-year term (Period 1). The winning bidder is required to post a Security Deposit in the amount of 25% of the total bid placed on the block within 15 days of the notification of a successful bid. The minimum bid for all parcels is CAD 10,000,000.00. Period 1 may also be extended to seven years by posting a drilling deposit of CAD 5-million for the first year, CAD 10-million for the second year and CAD 15-million for the third year. In order to extend the contract into Period 2, consisting of three additional years, a well must be drilled in the contract prior to the end of Period 1. Rentals do not apply to the contract until such time as the contract enters into Period 2 with the drilling of a validation well. Upon entering Period 2, a rental fee of CAD 5.00 per hectare is required for the first year followed by CAD 10.00 per hectare for year two and CAD 15.00 per hectare per year for years three and four. Rentals will be refunded dollar for dollar for each qualifying dollar spent on exploration in the contract for that year. The winning bidder is also required to pay a fee (yet to be determined) per hectare towards the Environmental Studies Research Fund (ESRF) which is applied to the two previous calendar years and for each year of the term of the exploration license thereafter. Geology (taken from the Basin Monitor product published by IHS Markit) The Orphan Basin lies offshore Canada on the eastern margin of North America, in water depths ranging from 200 m in the west to over 3,000 m in the east. The basin covers an area of some 157,159 sq km. The geologic evolution of the Orphan Basin is similar to the adjacent Grand Banks and Flemish Pass Basin, but also to the Porcupine Trough on the Western European margin. Prior to the opening of the North Atlantic Ocean, the Orphan Basin was located immediately to the west of the Porcupine Trough. The basins including the Orphan Basin originated as a result of successive extensional episodes related to the break-up of a) Africa and North America in the Late Triassic - Early Jurassic, b) Iberia and the Grand Banks in the Late Jurassic - Early Cretaceous, and c) Europe and northern North America in the Middle Cretaceous. No source rocks have yet been identified in the Orphan Basin. Potential source rocks include Lower Tertiary and Upper Cretaceous shales, Cretaceous shales equivalent to the Grand Banks Basin's Markland Formation, Upper Jurassic shales of the Egret Member as well as possible Carboniferous shales. Good reservoir quality sandstones were encountered within the Lower and Upper Cretaceous section in wells. Potential reservoirs may be found in the Lower Tertiary section and, if at all present, in the Upper Jurassic syn-rift succession. The Upper Cretaceous to Tertiary sedimentary cover should provide efficient seal to underlying reservoirs. The structures in the Orphan Basin are related to a succession of rifting and sag episodes. According to Tankard & Welsink (1989), dip-slip process dominated the structural development of the basin and the direction of extensional transport was towards the northeast. The main structural episode took place in Middle Cretaceous times, when renewed rifting led to the opening of the Labrador Sea and to the separation of Orphan Knoll-Flemish Cap from northwest Europe. The Orphan Basin has a promising potential. The area suffers harsh environmental conditions, but technological advances such as floating production storage and offloading vessels, have reduced most of the dangers. The biggest risk to exploration in the Orphan Basin is whether active petroleum systems exist. In the adjacent Grand Banks Basin, the most prolific reservoirs belong to the Late Jurassic - Early Cretaceous syn-rift sequence, i.e. the thick Jeanne d'Arc and Hibernia formations, with some 1,260 MMbo of recoverable reserves (December 2004).

C-NLOPB has issued a Call for Bids for Exploration Licences in the Eastern Newfoundland Region. Call for Bids NL20-CFB01 (Exploration Licences, Eastern Newfoundland Region) consists of 17 parcels and a total of 4,170,509 hectares.

In line with its rumoured UKCS divestiture, Exxon is disposing of its US Gulf assets, with Ineos and Repsol possible suitors. This would be UK’s Ineos first foray in the Gulf. The assets, which include 15 deepwater fields carry an estimated price tag of USD 1.5 bn :

In line with its rumoured UKCS divestiture, Exxon is disposing of its US Gulf assets, with Ineos and Repsol possible suitors. This would be UK’s Ineos first foray in the Gulf. The assets, which include 15 deepwater fields carry an estimated price tag of USD 1.5 bn :

On 30 July 2020, PEMEX concluded evaluation of the Yaxjut 1SON new-field wildcat (NFW) stratigraphic test with results unreported. The well is in the AE-0047-3M-Agua Dulce-06 (AE-0133-Cuichapa) exploration entitlement, onshore Sureste Basin, in the north-western area of the block. It was previously named the Lacab 1EXP prospect, approximately 1.2 km south-west of the Tolouque 1A NFW plugged and abandoned dry by PEMEX in 1962 at a final total depth (TD) of 5,665 m. The NFW was spudded on 20 August 2019 and is assumed the well reached the proposed total depth (PTD) of 6,630 m. The NFW was targeting the Cretaceous from 4,555 m to 4,605 m and Upper Jurassic Kimmeridgian from 5,530 m to 5,580 m on a complex salt related and faulted anticlinal structure. The well had estimated unrisked prospective resources of 91 MMboe. Pemex estimated the drilling cost at USD 29.2 million, and completion cost at USD 8.53 million. On 27 August 2014, the 1,053.63 sq km AE-0047-3M-Agua Dulce-06 exploration entitlement block was granted to PEMEX and was relinquished on 27 August 2019. It has been superseded by the AE-0133-Cuichapa entitlement granted on 28 August 2019 and covers an official area of 1,057.49 sq km. On 12 April 2019, the CNH approved a PEMEX request to modify the exploration plan for the AE-0047-3M-Agua Dulce-06 exploration entitlement block. This represents the second modification, the previous one was approved on 7 December 2017. PEMEX has updated and changed some previous prospect names and added one prospect. The modified plan includes the base case plan of re-processing 866 sq km of 3D seismic and the drilling of two new-field wildcats (NFWs). The contingent commitment includes the drilling of one additional NFW. PEMEX will attempt to drill the two commitment wells prior to the 27 August 2019 expiry of the two-year exploration period extension. The firm commitments will have PEMEX drill two NFWs, the Vinik 1EXP and the Yaxjut 1EXP. The contingent incremental commitment is the drilling of the Andarani 1EXP NFW. The total budget for the base case exploration program is USD 76.22 million with USD 73.01 million allocated to drilling the two firm commitment wells. The incremental contingent activity has a total budget of USD 102.4 million with USD 98.65 million allocated to drilling three wells. On 9 May 2019, the CNH approved a PEMEX drilling permit request to drill the Yaxjut 1SON new-field wildcat (NFW) stratigraphic test.

(Sureste B.) Yaxjut 1SON nfw, operated by PEMEX (100%) in AE-0047-3M-Agua Dulce-06 (AE-0133-Cuichapa) block, onshore Sureste Basin, evaluation + ops terminated, results n/a. PTD was 6,630m, target Cret. + U. Kimmeridgian.

APLNG secured sole rights to PL 407,  139 sq km in the Taroom Trough, Bowen-Surat Basin, on 9 Jul ’19 for 30 years around the Ramyard CBM find. Of note, the licence was applied for in 2011.

APLNG secured sole rights to PL 407, 139 sq km in the Taroom Trough.

Equinor has acquired Shell’s 30% interest in PL 878 which covers an area of 361 sq km over parts of blocks 30/2 and 30/3. The deal was announced by the NPD on 5 September 2019 and is effective from 8 February 2019. The licence area includes the abandoned Huldra gas condensate field. Huldra was discovered in 1982 by well 30/2-1 and it came onstream in November 2001. It is a rotated fault block structure with a Middle Jurassic Brent Group reservoir lying between 3,500-3,900 m. The reservoir was initially HPHT but compression was required to aid production from 2007. From the Huldra platform wet gas was transported to Heimdal for further processing and export and condensate was exported through Veslefrikk. Permanent plugging of the production wells is now complete with the facility due to be removed in 2019. Following completion of the deal Equinor Energy AS (100% + operator) is the sole remaining participant in the licence.

Norway (Heimdal Terrace (Viking Graben Province)) Heimdal

On 18 October 2018, the ANP granted approval for Parnaiba Gas Natural and Parnaiba Participacoes SA to transfer their combined 100% working interest in the PN-T-084 block to parent company Eneva SA.  Parnaiba Gas Natural was the operator of the ANP Round 13 block and held 70% working interest and subsidiary company Parnaiba Participacoes SA held 30% working interest.  Two working interest transfers between the subsidiary companies took place in 2017. On 10 May 2017, the ANP granted Parnaiba Gas Natural approval to acquire 70% working interest from subsidiary company Parnaiba Participacoes SA in the PN-T-084 block who will retain a 30% non-operated working interest.  Parnaiba Gas Natural and Parnaiba Participacoes SA are subsidiaries of Eneva.  Eneva re-structured most of its contracts under the Parnaiba Gas Natural subsidiary in May 2017. On 10 May 2017, the ANP granted Parnaiba Gas Natural approval to acquire all of the working interest in eight contracts in the Parnaiba Basin from Eneva subsidiary partner BPMB Parnaiba.   BPMB was a 30% working interest non-operating partner in all of the blocks and production concessions with the exception of the ANP Round 13 PN-T-084 block where it had 70% working interest and was the operator.  The operations have been transferred to Parnaiba Gas Natural with the 70% working interest.

Brazil, PN-T-084

By Q3 2019, Khalda Petroleum had successfully completed its Barakat Deep 1X NFW as a gas and condensate producer. The well reached 1,438m TD with operations carried out utilising the Egyptian Drilling Company #17 rig. Well costs are estimated at ~US$1.7 million. The well is understood to have been targeting a Palaeozoic prospect. The discovery lies on the under-explored Khalda Offset New Area I (A) exploration lease, which forms part of the Khalda Offset PSC located in the Matruh Basin. The well is located 1km SE of the 1973 Barakat 1 NFW, which was P&A with gas shows after reaching 3,649m TD. Barakat Deep 1X is the first well to have been drilled on the block during 2019. In 2018 the company drilled its Nebtu 1X NFW, which was P&A dry after reaching 3,921m TD in the Paleozoic. Equity in the Khalda Petroleum consortium is split between Apache (33.5%), Sinopec (16.5%) and EGPC (50%, carried).

Barakat Deep 1X nfw. (Khalda Petroleum = Apache 33,5%, Sinopec 16,5%, EGPC 50%, carried) in Khalda Offset (New) A-West, successfully completed as a gas and condensate producer, have been targeting a Palaeozoic prospect.

Touchstone agreed earlier this year to take over ops and 80% from GOC* in the 133-sq km Remboué permit + field  for some USD 23 MM. Plans are to produce 1,000 bo/d by Jan ’19.  The deal follows on from an initial announcement in 2017, but when the purchaser was not revealed. Touchstone (op), Govt partner. *GOC = Gabon Oil Co. (not govt).

Touchstone O&G (80%,op.), and GOC (20%) have signed an agreement to allow Touchstone to take control of Remboue permit.

Dana Gas announces an oil discovery in Kurdistan (no details), along with the supposedly largest gas reserves in Iraq, according to press. The company states that 2P reserves at the Khor Mor + Chemchemal fields have progressed 10% following a recent independent certification of reserves.

Iraq (Zagros Province) ? op. by PEARL PT (100.0%) in Chemchemal block

Exxon has been cleared to transfer a 50% interest to partner Azibras in the CE-M-603 contract, 769 sq km in the Ceará Basin, and for Azibras to move on a 30% stake to new optr OP Energia (Ouro Preto). Exxon thus withdraws from the offshore permit, now held by OP Energia (op), partner Azibras. Likewise for POT-M-475, 768 sq km offshore in the Potiguar Basin:

Exxon has been cleared to transfer a 50% interest to partner Azibras in the CE-M-603 contract, 769 sq km in the Ceará Basin, and for Azibras to move on a 30% stake to new optr OP Energia (Ouro Preto).

According to press, up to  5  E&P contracts may be awarded in the coming months to domestic oil co’s as a result of IOC’s suspending work on US sanctions. Negin Afagh Kish Energy Devt Co. (TENCO) may secure the 8,611-sq km Tudej (Toudej) block in Fars towards the summer, for which it recently signed a study MoU with NIOC (DEA 11 Apr ’19). It includes the partly-developed Sarvestan oilfield.

Iran (Iran Zagros Fold Belt (Zagros Prov.)) Kish

On 3 October 2018 Union Jack Oil Plc announced that it along with Humber Oil and Gas Ltd have agreed a deal 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. 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 have agreed a deal 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. The licence is located in East Yorkshire and contains the West Newton A-1 gas discovery.

Add. DEA 4 Oct ’17: AD-7, deepwater Rakhine Basin, WD 1,485m, P&A now reported dry at TD 3,693m in late Sep ‘17, tested. Target Pliocene turbidites found water-wet, Dhirubhai Deepwater KG2 DS.  Posco Daewoo (blk op), Woodside (well op).

Khayang Swal 1 op. by Posco Daewoo (blk op. 60%), Woodside (well op. 40%) in AD-7 block, P&A, dry after encountering water-wet sandstones in the Pliocene turbidite target.

W. part of block A-7, S. Rakhine Basin, WD 2,060m, P&A results n/a 18 Jul ’18. PTD was 4,526m, target gas in Pliocene turbidites, Dhirubhai Deepwater KG2 DS.  Woodside (op), partners Shell + local MPRL.

Dhana Hlaing 1 in Block A-7, P&A, results have not been reported, as further assessment is underway. Dry well most probably

Add. DEA 24 Mar '20: 1st well in PL 1008 (part-blocks 6506/2, 3, 5, 6 + 8, 6507/1 + 4), Skarv area near Ærfugl, WD 409m, TP&A'd at TMD 3,225m (3,166m TVD, Lange fm), minor discovery, 15m gas column in the target Lysing fm, 1-2.4 Bcum recoverable. Sidetrack T2 TD'd at 3,077m (3,050m TVD), drilled 10-12 Mar '20. Deepsea Norkapp SS. Aker BP (op), partner Wellesley.

6506/05-01 S (Nidhogg) nfw. (Aker BP 60% op, Wellesley 40% ) in PL 1008 block, Skarv area near Ærfugl, WD=442m, P&A at TMD=3225 m (3198m TVD), minor gas discovery , Target Lysing Fm gas-cond. A total gas column of about 15m in the Lysing Fm, of which 10m of sst are of “very good reservoir quality”,

SE part of POT-T-699 block, onshore Potiguar, assumed P+A dry 17 Dec ’17, as no shows report. PTD was 1,700m, target Açu + Pendência fm’s, co. rig 1.

1-IMET-22-RN op. by Petrobras (100%) in POT-T-699 Block, P&A,dry.

In May 2019 Telpico continues to offer interest in its LLA-42 Block of the northern Llanos Basin near the Venezuelan border. The Cano Limon field is located some 40 km west and has produced over 1.3 Bbo from Cretaceous and Tertiary reservoirs. The Eocene Mirador Formation is also a producer with sands averaging 25% porosity from depths of some 7,500 ft. Telpico has identified several Carbonera, Mirador, and Cretaceous prospects from high quality 3D seismic acquired in 2014. The Zapata prospect has multiple objectives with a reserve potential estimated at 217 MMbo. Telpico is offering a 49% working interest with a potential partner to pay a USD 3.5 million buy-in cost. The deal also includes the partner to pay 100% of the initial well test costs, to include drilling and testing operations. Interested parties should visit the website at www.telpico.com.

Telpico continues to offer interest in its LLA-42 Block of the northern Llanos Basin near the Venezuelan border. The Cano Limon field is located some 40 km west and has produced over 1.3 Bbo from Cretaceous and Tertiary reservoirs.

Siccar Point has agreed to sell its 26% interest in the Jackdaw discovery area (P098, P111 + P672 / part-blocks 30/2a [Shell op], 30/3a [Shell op] + 30/2d – [Chrysaor op]) to Dyas.  Completion of the deal is subject to usual approvals. www.siccarpointenergy.co.uk .

Siccar Point Energy is selling its 26% stake in P098 (Jackdaw field) to Dyas (Shell 74%+op).

CNOOC announced on 18 December 2018 that it has signed Strategic Cooperation Agreements with 9 international oil companies including: Chevron, ConocoPhillips, Equinor, Husky, KUFPEC, Roc Oil, Shell, SK Innovation and TOTAL, respectively, on two blocks in the South China Sea. According to the agreements, the Strategic Cooperation Areas are located in the Pearl River Mouth Basin offshore China, including Area A and Area B (existing mining license areas and the contract areas are not included). Area A is approximately 15,300 sq km, with a water depth of 80-120 meters and only open for the deep layers below Enping Formation of Paleogene. Area B is approximately 48,700 sq km, with a water depth of 500-3,000 meters and open for all the layers. The agreements will facilitate the establishment of a long term and stable cooperation and share the development opportunities to a certain extent in the Strategic Cooperation Areas, creating conditions for the final signing of contracts. CNOOC Limited, as an independent oil and gas exploration and production company, is the only vehicle through which CNOOC engages in exploration, development, production and sale of crude oil and natural gas. Background Information In May 2018 CNOOC, during 2018 bidding round announcement, introduced Strategic Cooperative Agreement (SCA) to set up a long term and stable partnership relations with cooperation partners. Two blocks, Block A and Block B, have been opened with area of 20,000 sq km and 52,000 sq km respectively for an in-house study during the agreement. CNOOC will sign SCA with each alliance member and it is non-exclusive. SCA is 3 years term. To be the SCA member, US$ 100,000 membership dues is obligation plus a commitment of an annual exchange of the technical research result. During/after the agreement members have priority to propose cooperation opportunity according to the members interests, including procure data and information, signing PSC with CNOOC. Block A, covering 20,120 sq km, is located in the north shelf of the Pearl River Mouth Basin. It is a relatively mature exploration area in which there are Xijiang, Panyu, Huizhou and Lufeng fields on producing. The fields have the main reservoir in the Miocene Zhujiang Formation. The Block A is opened focusing on deep formations – Eocene Enping and Wenchang formations. Block B, covering 52,845 sq km, is located in deep water (500 – 3,500 m) area of the Pearl River Mouth Basin. Currently only LW 3-1/LH 34/LH 29 gas fields have been found in the block, and large area of the block remains undrilled.

CNOOC announced on 18 December 2018 that it has signed Strategic Cooperation Agreements with 9 international oil companies including: Chevron, ConocoPhillips, Equinor, Husky, KUFPEC, Roc Oil, Shell, SK Innovation and TOTAL, respectively, on two blocks in the South China Sea. According to the agreements, the Strategic Cooperation Areas are located in the Pearl River Mouth Basin offshore China, including Area A and Area B (existing mining license areas and the contract areas are not included).

Zimniy Zapadnyy licence, S. Ural-Frolov Basin, Khanty-Mansiyskiy AO, W. Siberia, drilled Apr-Jul ’18, TD 3,004m, tested 43 bo/d from the M. Jurassic Tyumen Yu5 reservoir between 2,832-2,846m, ops continue.

Zimniy Zapadnyy licence, S. Ural-Frolov Basin, Khanty-Mansiyskiy AO, W. Siberia, drilled Apr-Jul ’18, TD 3,004m, tested 43 bo/d from the M. Jurassic Tyumen Yu5 reservoir between 2,832-2,846m,

Providence and Lansdowne have signed a joint farmout agreement with a Chinese group led by Apec Energy Enterprise for a 50% interest in the Barryroe oilfield in SEL 1/11, North Celtic Sea Basin, in exchange for funding 3 wells and sidetracks. So far EXOLA (Providence) (op) 80%, partner Lansdowne 20% (San Leon carried for 4.5%). After completion of drilling, Apec will have the right to operatorship in the devt/prod. phase. Apec is a strategic partner with COSL and JIC Capital Management for focusing on offshore opportunities using Chinese rigs and equipment, and would provide the rig for the above. In addition to its 50% financial obligation, it will provide, by way of a non-recourse loan facility, the remaining 50% of drilling costs. www.providenceresources.com , www.apecenergy.com.

Providence (->50%) and Lansdowne (->0%) farm out a 50% WI in EL 01/11 (Barryroe) to a Chinese consortium led by APEC.

PetroChina – Xinjiang has achieved several exploration successes in 2018 in the Junggar Basin. Da 18, drilled in the east of Mahu field, tested oil in the Lower Wurhe Formation, confirming a third reservoir in the Mahu field after Triassic Baikouquan and Upper Wurhe formation. Chepai 18, located in the Hongche fault belt in the northwest section of the basin, tested oil in the Permian Jiamuhe and demonstrated a new exploration prospective in mid-shallow horizon in this area. Fu 32, drilled in the Fudong slope, tested 625 b/d of oil and 318 Mcf/d of gas from the Jurassic channel sands in the Toutunhe formation, indicated exploration prospective in this play in the area. Kemei 002, drilled in the south of Kelameili gas field, tested 3.9 MMcf/d of gas in the Carboniferous reservoir. The well is to test upside reserve potential in the lower part of the structure and during drilling the well penetrated two sets of gas pay with overall 100 m thick. Background Information PetroChina has been operating in the Junggar Basin for more than 60 years. The company has found more than 30 fields with a total of 2.6 bn tons of oil in place in the basin and produced cumulative of 360 million tons of oil by 2017.  Peak oil output used to be 244,000 b/d n 2008. For the last five years PetroChina maintained oil production at a rate of over 220,000 b/d. In 2017 PetroChina produced at 226,000 b/d of oil in 2017, it plans to produce 229,000 b/d of oil in 2018.The company has a target to increase production up to 260,000 b/d by 2020

Da 18, drilled in the east of Mahu field, tested oil in the Lower Wurhe Formation, confirming a third reservoir in the Mahu field after Triassic Baikouquan and Upper Wurhe formation. Chepai 18, located in the Hongche fault belt in the northwest section of the basin, tested oil in the Permian Jiamuhe and demonstrated a new exploration prospective in mid-shallow horizon in this area. Fu 32, drilled in the Fudong slope, tested 625 b/d of oil and 318 Mcf/d of gas from the Jurassic channel sands in the Toutunhe formation, indicated exploration prospective in this play in the area. Kemei 002, drilled in the south of Kelameili gas field, tested 3.9 MMcf/d of gas in the Carboniferous reservoir.

As of late February 2018, Sinopec successfully flow tested commercial amount of shale gas from Dingye 5 after having commenced testing operations in late 2017. Dingye 5 was drilled to a TD of 5,685m MD and was suspended for fracture stimulation and testing in September 2017. The vertical section of Dingye 5 was drilled to a 3,848m in April 2017 after having been spudded on 20 December 2016. Convention cores were collected from 3,740-3,821.6m with one core measuring 16.32m. The shale gas exploration well had a PTVD of 3,700m and a 1,500m horizontal section to a PTD of 5,396m, targeting the Longmaxi Formation with the objective of collecting shale gas data in the Dingshan area. The success of Dingye 5 followed that the previous successful shale gas wells, Dingye 1, Dingye 2, Dingye 3 and Dingye 4, on the Dingshan Structure, allowing Sinopec to further explore and build the shale gas potential of the Dingshan shale gas discovery. Dingye 5 is in the Sinopec operated Qijiang Block in the Sichuan Basin and geographically located in Guizhou Province, Xishui County, Zhaiba Town. <P /><P />

Sinopec successfully flow tested commercial amount of shale gas from Dingye 5 after having commenced testing operations

S. part of BM-SEAL-004 block, Sergipe Alagoas offshore, WD 2,647m, PTD 5,609m, target Calumbi fm, spudded 20 Jun ’19, oil shows report to ANP 22 August.  Petrobras 10000 DS. Petrobras (op), partner ONGC Videsh.

3-SES-193 (3-BRSA-1368-SES) (Petrobras 75%, ONGC 25%) in the BM-SEAL-004 block P&A with oil shows.

Latif 2669 EL, Lower Indus onshore, TD 3,613m, MDT yielded 28.6 MMcfg/d, WHP 3,116 psi, from the Lower Goru, SLR-215 rig. UE (op), partners Eni + PPL.

Bitro 1 nfw. (Eni 18,42%, KPC 15,79%, Al-Haj Group 15,79%, OGDCL 50%) in the Kadanwari D&PL onshore concession, gas disc. MDT was carried out and the well is reported to have flowed gas at a rate of 28.6 MMcfg/d [44/64"choke] from the 'B-Sand' unit of Cretaceous Lower Goru Fm.

W-C part of AE-0007-2M-Amoca-Yaxche-05 block, offshore Sureste Basin, WD 94m, P&A dry at TD 2,374m mid-Jan ‘19, West Titania JU. PTD was 6,540m, target Cretaceous + Jurassic, a sidetrack is planned.

Pox 101EXP (NFW) (Pemex 100%) in AE-0007-2M-Amoca-Yaxche-05 entitlement block, The well had a proposed total depth (PTD) of 6540 m and the primary targets were the Cretaceous and Jurassic formations. P&A dry.

On 15 October 2019, the Federal Agency for Subsoil Use held an auction for four blocks in Krasnoyarsk Kray (Eastern Siberia). Irkutsk Oil Company (INK) submitted winning bids for all blocks. The winner of the auction will obtain 27-year E&P licenses including a 7-year exploratory stage. Details of the offer are as follows: The Madashenskiy block covers 1,626 sq km in the Angara-Lena Structural Terrace (Baykit Basin). Seismic coverage amounts to 585 km. No wells have been drilled in the block. Reservoirs of the Riphean-Vendian section are the main exploratory target. Hydrocarbon resources (categories D1+D2) of the block are estimated at 19 MMbbl of oil and 2,531 Bcf of gas. The starting price amounted to RUB 13.5 million (USD 0.2 million). INK offered RUB 14.85 million (USD 0.23 million). The Muntulskiy block covers 1,949 sq km in the Angara-Lena Structural Terrace. Seismic coverage amounts to about 200 km. No wells have been drilled in the block. Reservoirs of the Riphean-Vendian section are the main exploratory target. Hydrocarbon resources (category D1) of the block are estimated at 53 MMbbl of oil and 932 Bcf of gas. The starting price amounted to RUB 17.6 million (USD 0.27 million). INK offered RUB 19.36 million (USD 0.3 million). The Chadobetskiy Vostochnyy block covers 1,846 sq km in the Prisayan-Yenisey Syneclise (Baykit and Angara-Yenisey basins) and encompasses several leads. No wells have been drilled in the block. Reservoirs of the Riphean-Vendian section are the main exploratory target. Hydrocarbon resources (categories D1+D2) of the block are estimated at 153 MMbbl of oil and 1,028 Bcf of gas. The starting price amounted to RUB 27.2 million (USD 0.4 million). INK offered RUB 29.92 million (USD 0.47 million). The Ischukhskiy block covers 1,473 sq km in the Baykit Basin. No wells have been drilled in the block. Reservoirs of the Riphean-Vendian section are the main exploratory target. Hydrocarbon resources (categories D1+D2) of the block are estimated at 110 MMbbl of oil and 1,336 Bcf of gas. The starting price amounted to RUB 22.2 million (USD 0.35 million). INK offered RUB 24.42 million (USD 0.38 million).

Russia, not found

AUREP is the Department responsible for the promotion of petroleum exploration under the Ministère des Mines of Mali. As of March 2016, AUREP had finalized a new division of the country in exploration acreage blocks. The old open block limits and denominations are not valid any more. The release of the new block limits was contingent on the new petroleum bill to be passed into law. The list of new acreage blocks became available in late-November 2016, it is presented below. In the west of the country, the new blocks are smaller than the previous ones. In fact the old blocks were divided in two in this area. The amount of available seismic data has doubled between 2004 and 2014, this has translated into a better understanding of the geology of the various sedimentary basins in the country. Therefore it was possible to design new block limits that take into account the improved basin definition. A new block, N° 29, was added in the far south of the country. AUREP stands for AUtorite pour la REcherche Petroliere. Interested parties should contact: Ahmed Ag Mohamed Directeur, AUREP Tel: +223 788 046 67 Email: [email protected]    The available blocks as of September 2018 are understood to be as listed below. There are thirty-eight open blocks. There were no changes from the previous list. Total open acreage amounts to 823,822 sq km all onshore.   Open blocks       Block Name Total (SQKM) Situation Block Basin Block 1A1 21,156 onshore Hank Sub-basin (Taoudeni Basin) Block 1A2 34,279 onshore Hank Sub-basin (Taoudeni Basin) Block 1B1 14,876 onshore Hank Sub-basin (Taoudeni Basin) Block 1B2 14,938 onshore Hank Sub-basin (Taoudeni Basin) Block 2A 10,842 onshore Hank Sub-basin (Taoudeni Basin) Block 2B 10,890 onshore Hank Sub-basin (Taoudeni Basin) Block 3A 10,509 onshore Taoudeni Basin Block 3B 12,860 onshore Hank Sub-basin (Taoudeni Basin) Block 4A 10,733 onshore Taoudeni Basin Block 4B 10,797 onshore Taoudeni Basin Block 5A 29,965 onshore Taoudeni Basin Block 5B 29,782 onshore Taoudeni Basin Block 6 23,600 onshore Taoudeni Basin Block 7 39,991 onshore Taoudeni Basin Block 8A 16,556 onshore Taoudeni Basin Block 8B 19,267 onshore Taoudeni Basin Block 9A 19,120 onshore Taoudeni Basin Block 9B 24,234 onshore Taoudeni Basin Block 10 37,566 onshore Taoudeni Basin Block 11 33,141 onshore Iullemmeden Basin Block 12A 32,557 onshore Taoudeni Basin Block 12B 21,074 onshore Nara Graben (Taoudeni Basin) Block 13A 42,863 onshore Taoudeni Basin Block 13B 27,763 onshore Taoudeni Basin Block 14 19,702 onshore Iullemmeden Basin Block 15 16,405 onshore Iullemmeden Basin Block 16A 16,972 onshore Taoudeni Basin Block 16B 15,553 onshore Taoudeni Basin Block 18 19,793 onshore Nara Graben (Taoudeni Basin) Block 19 13,812 onshore Taoudeni Basin Block 21 22,244 onshore Taoudeni Basin Block 22 22,145 onshore Taoudeni Basin Block 23 14,529 onshore Taoudeni Basin Block 24A 29,068 onshore Taoudeni Basin Block 24B 31,022 onshore Taoudeni Basin Block 26 24,036 onshore Pharusian Fold Belt Block 27 20,155 onshore Mantass Depression (Iullemmeden Basin) Block 28 9,024 onshore Pharusian Fold Belt

AUREP is the Department responsible for the promotion of petroleum exploration under the Ministère des Mines of Mali. As of March 2016, AUREP had finalized a new division of the country in exploration acreage blocks. The old open block limits and denominations are not valid any more. The release of the new block limits was contingent on the new petroleum bill to be passed into law. The list of new acreage blocks became available in late-November 2016, it is presented below. In the west of the country, the new blocks are smaller than the previous ones. In fact the old blocks were divided in two in this area.

ConocoPhillips spudded exploration/appraisal well, 30/7a-S15, from its Jasmine platform targeting the Merida prospect (licence P32) on 24 June 2019. As of 4 July 2019 ConocoPhillips confirmed it was drilling ahead and as of 10 July 2019 it is understood that operations are continuing. ConocoPhillips drilled an appraisal well, 30/7a-S12, in the second half of 2018 on the Jasmine field. If the well was successful the plan was to bring the well on as a producer. However, it was confirmed in late 2018 that the well was not going to be brought onto production. The Jasmine field comprises several fault blocks and was developed in three phases. Phase 1 comprised the development of the West Limb Core Area and part of the North Terrace. The Phase 2 wells (30/7a-S8 spudded on 28 October 2014) targeted the North Terrace and the West Limb Southeast Lobe areas. To the north of the initial Phase 1 and Phase 2 areas are the Jasmine North areas (Jasmine North A and Jasmine North B). Jasmine is a high pressure, high temperature (HP/HT) gas-condensate field that was discovered in 2006 by ConocoPhillips with well 30/6-6. The reservoir for Jasmine is the Triassic Joanne Sandstone, which has an initial reservoir pressure of 822 bar and a temperature up to 178° C. Interest in block 30/7a is held by ConocoPhillips Petroleum Co (UK) Ltd (36.5% + operator), with partners Eni UK Ltd (33%) and Chrysaor Ltd (30.5%).

United Kingdom, not found

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

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

Suryaraopeta field area in Malleswaram ML, onshore Krishna-Godavari Basin, TD 3,620m, tested 497 bo/d + 1.5 MMcfg/d from the U. Cretaceous Raghavapuram fm, discovery on stream.

Bantumilli North 2 (ONGC 100%) in Malleswaram ML onshore block. Late Cretaceous Raghavapuram Fm. flowed oil at 497 b/d, along with 1,5 MMscf/d of gas.

Metgasco has been formally granted ATP 2020 + 2021 in the Cooper Basin, QLD, having already performed a technical work programme in recent months. Awards are the result of a tender in 2015 and conclusion of Native Title Negotiations in early 2018. ATP 2020 covers 535 sq km on the Thargomindah Shelf, SW QLD. ATP 2021 is 369 sq km in the S. Cooper Basin, SW QLD. www.metgasco.com.au.

Metgasco (100%) has been awarded two permits: ATP 2021 and ATP 2020.

Press of 7 September 2018, reported that the Uganda National Oil Company (UNOC) and China National Offshore Oil Corp (CNOOC) signed a Memorandum of Understanding (MoU) to jointly explore for oil and gas in the Albertine Graben. The block outline has not been disclosed but is located on the southern part of the Lake Albert. CNOOC already has interests in Uganda. It operates the PL01/2012 (Kingfisher) licence and has interest in production licenses (former Exploration Areas 1, 1A, 2 and 3A) : Kasamene-Wahrindi (PL01/2016), Kigogole-Ngara (PL02/2016), Nsoga (PL03/2016), Ngege (PL04/2016), Mputa-Nzizi-Waraga (PL06/2016), Ngiri (PL06/2016), Jobi-Rii (PL07/2016), Gunya (PL08/2016). Following Tullow farm-out deal to Total and CNOOC pre-emption rights, interests in the licences should be shared as follow: Total 44.12%, CNOOC 44.12% and Tullow with 11.76%. However, the companies have not yet received the governmental approval the complete the deal. The Lake Albert Development Project aims to develop 1.4 Bbbl of oil equivalent recoverable resources from the Albertine Graben for a cost of USD 5.2 billion with first production starting in 2021 at plateau rates of 230k b/d. The project’s Final Investment Decision (FID) is expected in the second half of 2018, with first oil expected 36-months after the FID. The oil production will be exported through the so-called East African Crude Oil Pipeline which is expected to be completed by 2021. Uganda is also planning to construct a refinery at Hoima with a capacity of refining 30,000 b/d to cater for demand of petroleum products in East Africa.

Press of 7 September 2018, reported that the Uganda National Oil Company (UNOC) and China National Offshore Oil Corp (CNOOC) signed a Memorandum of Understanding (MoU) to jointly explore for oil and gas in the Albertine Graben. The block outline has not been disclosed but is located on the southern part of the Lake Albert. )

Vermilion has acquired interests held by partner Tulip Oil (in Marknesse) and Tulip + Petrogas (in Schagen) effective 9 Jul '20. Marknesse lies over 77 sq km in Flevoland, central Holland, Schagen 356 sq km on/offshore Noord Holland. Partnership now Vermilion & EBN.

(Anglo-Dutch b.) in Schagen operated by EBN (40%), TULIP OIL (30%), Petrogas (30%) and Marknesse operated by TULIP OIL (60%), EBN (40%), Vermilion has acquired interests held by partner Tulip Oil (in Marknesse) and Tulip + Petrogas (in Schagen) effective 9 Jul '20. Marknesse lies over 77 sq km in Flevoland, central Holland, Schagen 356 sq km on/offshore Noord Holland. Partnership now Vermilion & EBN.

In October 2017, Surgutneftegaz completed testing of a new exploratory well in the Tundrinskoye license in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Verkhnesolkinskaya 50, spudded in August 2017, reached 2,980 m in September. Oil flows were tested from the Sortym (Neocomian) and Tyumen Formations. Reservoir BS10 perforated at 2,436-2,443 m flowed with oil at a rate of 28 b/d. The interval 2,865-2,892 m (Yu2-3) tested oil at a rate of 16 b/d. Based on primary data, 2P reserves of the discovery were estimated by IHS Markit at 3 MMbbl. Tundrinskoye license (KhMN00422NE) covers 973 sq km in the southwestern part of the Middle Ob Province and encompasses the Tundrinskoye field and the Malo-Komaryinskaya prospect.  

Verkhnesolkinskaya 50,Surgutneftegaz completed testing of a new exploratory well in the Tundrinskoye license Oil flows were tested from the Sortym (Neocomian) and Tyumen Formations. Reservoir BS10 perforated at 2,436-2,443 m flowed with oil at a rate of 28 b/d. The interval 2,865-2,892 m (Yu2-3) tested oil at a rate of 16 b/d.

Egdon is offering equity in PL 090, 201 sq km in coastal Dorset (excluding the Waddock Cross oilfield) in return for a promoted share cost of a future well on the seismically-defined Broadmayne prospect, target Sherwood sand. Egdon (op, 42.5%), partners Corfe, UKOG + Aurora Egy. Contact: Martin Durham, [email protected].

Egdon is offering equity in PL 090, 201 sq km in coastal Dorset (excluding the Waddock Cross oilfield) in return for a promoted share cost of a future well on the seismically-defined Broadmayne prospect, target Sherwood sand. Egdon (op, 42.5%), partners Corfe, UKOG + Aurora Egy.

ExxonMobil has acquired a 50% stake from Petronas in block 52, 4,861 sq km in WD 50-1,100m, Guyana-Suriname Basin. Sloanea-1 nfw is planned here, target U. Cretaceous, 2-3 month well, semi sought. So far Petronas (op), partner Wintershall Dea. Staatsolie has a 20% back-in right in the event of a commercial find.

ExxonMobil has acquired a 50% stake from Petronas in block 52, 4,861 sq km in WD 50-1,100m, Guyana-Suriname Basin. Sloanea-1 nfw is planned here, target U. Cretaceous, 2-3 month well, semi sought. So far Petronas (op), partner Wintershall Dea. Staatsolie has a 20% back-in right in the event of a commercial find.

On 23 December 2019, the Federal Agency for Subsoil Use held an auction for the Kamskiy Zapadnyy block in Udmurtia Republic (Volga-Ural Province). Competing against Dalpromsintez, company Flagman Engineering won the contest with the offer of RUB 1.012 million (USD 0.02 million). Details of the offer are as follows: The Kamskiy Zapadnyy block covers 57.4 sq km. Oil resources (category D1) of the block are estimated at 4 MMbbl. The starting price amounted to RUB 0.92 million (USD 0.01 million). The winner of the auction will obtain a 25-year E&P license.

Flagman Engineering won Kamskiy Zapadnyy block (55km²) in Udmurtia Republic.

Add. DEA 20 Apr ’18 (content) : PEL 630, Cooper Eromanga, P&A gas shows at TD 3,133m, Saxon rig 183 to Ulladulla-1.  Main target Patchawarra. Beach (op), partner Bridgeport.

Australia, PEL 630

Sampang block off E. Java, S. of Madura Island in WD 48m, TMD 710m, gas in the target Mundu fm, tested 11.2 MMcfg/d for 5 hrs from between 576-605m (MD) on a 64/64" choke, 525 psi WHP. A subsequent 9-day pressure buildup led to 13.8 MMcfd on a 120/64” choke for 55 minutes. Well P&A’d as planned, HYSY 937 JU. Ophir (op), partners Singapore Petr. + Cue Egy.

Indonesia, not found

The authorities have reportedly approved Ancap’s plan to offer Uruguayan acreage under an open-door process, following the failure of a bid round in April 2018 for offshore acreage (17 blocks). The latest is a shift to a new biannual process, with awards at the end of May and November every year. Contact: Santiago Ferro, Ancap, [email protected].

The authorities have reportedly approved Ancap’s plan to offer Uruguayan acreage under an open-door process, following the failure of a bid round in April 2018 for offshore acreage (17 blocks).

Pengtan 1 flow tested approximately 43 MMcfg/d from the Sinian Second Member of the Dengying Formation after acidization on 4 May 2020. Pengtan 1 was spudded on 24 June 2019 and was drilled to a TD of 6,373m MD on 19 January 2020. The success of Pengtan 1 confirms the hydrocarbon potential of the eastern Deyang-Anyue Fault Zone in the central Sichuan Basin, northeast of the Gaoshiti-Moxi Gas Field. PetroChina estimated that the reservoir area covers approximately 2,000 sq km and contains resources-in-place of greater than 35 Tcfg. Pengtan 1 is in the PetroChina operated Yanting-Daying Block in the Sichuan Basin and is geographically located within Sichuan Province, Daying County, Tianbao Town, Daowan Village.

Pengtan 1 nfw. (PetroChina – Sichuan 100%) Anyue gasfield area, E. Deyang-Anyue fault zone, tested 43 MMcfg/d from the Dengying 2 fm, 127m pay encountered, potential > 35Tcf in place. TD=6 376m. The Pengtan structure, which covers 1200 km² in the central part of the basin, has the potential to hold more than “a trillion cubic metres” of gas in place, the company said.

Further to DEA 16 Dec '19 (disc.): Commitment well in Ortoire block, Mayaro province, TD 1,935m, 316m prospective net oil pay in 419m gross sand in the Cruse, U, M & L Herrera fm's, 36 hrs of testing started 4 Feb '20, lowermost 49m of 239m pay in the Herrera yielded 26.9 MMcfg/d + 694 bc/d (54 API), peak 30.2 MMcf/d + 710 bbl, no H2S nor water, under 2-week pressure buildup prior to testing addit. 137m of identified pay above. Touchstone (op), partner Heritage Petr.

Cascadura 1ST nfw. (Touchstone 80% op, Heritage Petr. 20%) in Ortoire block, significant oil find, 316m prospective net oil pay in 419m gross sand in the U, M & L Miocene Herrera Fm. 36 hrs of testing started 4 Feb '20, lowermost 49m of 239m pay in the Herrera yielded 27 MMcfg/d + 694 bc/d (54° API), peak 30 MMcf/d + 710 bbl, no H2S, no water.

During early April 2020, Amal Petroleum Company (Amapetco) was understood to have successfully completed its Amal 18 ST A appraisal/development well as an oil producer. The well was brought onstream at an average rate of 1,500 bo/d. Cost have been estimated at ~US$ 6 million. The well reached 3,122m TD with operations carried out utilising the ADES Group “Admarine VI” jack-up, in a WD of ~50m.The Amal oil & gas field is located on the Amal PSC. It was discovered in the Miocene Rudeis and Kareem sandstones by Total in 1968, but not brought onstream until 1988. Amapetco is a 50/50 JV between Cheiron and EGPC.

Amal Petroleum Company (Amapetco) was understood to have successfully completed its Amal 18 ST A appraisal/development well as an oil producer. The well was brought onstream at an average rate of 1,500 bo/d.

PN-T-114 block, TD’d 8 Oct ’18, gas shows + now under evaluation. PTD was 2,436m, target Cabeças + Poti fm’s.

Gas shows: 1-OPEO-SERRANEGRA-MA (1-OPEO-002-MA) nfw

PentaNova has agreed to farmout a 40% stake to Panacol in the Sinú 9 block, 1,270 sq km in the Lower Magdalena, for USD 22.29 MM  + funding Pentanova’s phase 1 commitments. Once completed the deal will result in AOG (op) 50%, Panacol 40%, Pentanova 10%.

PentaNova has agreed to farmout a 40% stake to Panacol in the Sinú 9 block, 1,270 sq km in the Lower Magdalena, for USD 22.29 MM + funding Pentanova’s phase 1 commitments. Once completed the deal will result in AOG (op) 50%, Panacol 40%, Pentanova 10%.

The Indonesian Medco Enerji Internasional Tbk (Medco) reported in January 2019 that it got the approval from the National Oil Corporation (NOC) to start a sales process for its interest in the Libyan Area 47 contract. Medco is a partner of NOC (51%) and the Libyan Investment Authority (LIA, 24.5%) with the 24.5% of interest through the Nafusah Oil Operations BV, which operates the contract. Area 47 comprises four blocks (Block 1, Block 2, Block 3 and Block 4) located in the Ghadames Basin, next to the border with Tunisia. Hamada North, a key field part of NOC's plan to boost production to 2.1 MMbbl/d by 2024 is located in Block 2 (see map below). Medco has reported Gross Working Interest 2P reserves of 57 Mscf of gas and 61 MMbbl of oil in Area 47 contract as of 30 September 2019. Medco was awarded the 6,182 sq km Area 47 EPSA IV in 2005 becoming part of the Nafusah Oil group. The contract included five and 25 years of exploration and production permit, respectively.

The Indonesian Medco Enerji Internasional Tbk (Medco) reported in January 2019 that it got the approval from the National Oil Corporation (NOC) to start a sales process for its interest in the Libyan Area 47 contract. Medco is a partner of NOC (51%) and the Libyan Investment Authority (LIA, 24.5%) with the 24.5% of interest through the Nafusah Oil Operations BV, which operates the contract. Area 47 comprises four blocks (Block 1, Block 2, Block 3 and Block 4) located in the Ghadames Basin, next to the border with Tunisia. Hamada North, a key field part of NOC's plan to boost production to 2.1 MMbbl/d by 2024 is located in Block 2 (see map below). Medco has reported Gross Working Interest 2P reserves of 57 Mscf of gas and 61 MMbbl of oil in Area 47 contract as of 30 September 2019.

Ref. DEA 12 Dec '17 + 5 Nov '19, upon response deadline 4 Dec '19, Santos has exercised an 80% farmin option from Melbana in the latter's WA-488-P (Beehive prospect), 4,100 sq km offshore Bonaparte Basin. Total, who had a similar arrangement for 40%, had declined. which brings Santos to 80% in exchange for funding planned Beehive-1. Resulting partnership-to-be Santos + Melbana. Meanwhile Santos is already looking to farm-down, some discussions reportedly already underway.

Australia, WA-488-P

Ref, DEA 27 Jan '20, Jersey has completed the acquisition of 70% + operatorship in P2170 / blocks 20/5b + 21/1d from Equinor in exchange for payment (USD 3 & 5 MM linked to Verbier clearance + production) + royalty based on oil production from the Verbier U. Jurassic reservoir. Jersey (op) 70%, Equinor 18%, CIECO 12%.

Jersey has completed the acquisition of 70% + operatorship in P2170 / blocks 20/5b + 21/1d from Equinor in exchange for payment (USD 3 & 5 MM linked to Verbier clearance + production) + royalty based on oil production from the Verbier U. Jurassic reservoir. Jersey (op) 70%, Equinor 18%, CIECO 12%

Naftogaz is seeking a partner to explore its unconventional acreage in the Dnieper-Donets Basin of Eastern Ukraine. Naftogaz directly holds three shale gas permits, Stelmahivska (434 sq km), Sukhodilska (502 sq km) and South Yampolsky-Dronivska (223 sq km) in the basin all valid to 2032. Its wholly owned subsidiary Ukrgazvydobuvannya (UGV) has further tight gas acreage, including Hersevanivska (350 sq km) and Shebelynske (223 sq km). Naftogaz has compiled a list of 13 potential tight gas fields in the area. with combined prospective resources of nearly 9 Tcfg in mid to late Carboniferous and early Permian reservoirs.

Naftogaz is seeking a partner to explore its unconventional acreage in the Dnieper-Donets Basin of Eastern Ukraine. Naftogaz directly holds three shale gas permits, Stelmahivska (434 sq km), Sukhodilska (502 sq km) and South Yampolsky-Dronivska (223 sq km) in the basin all valid to 2032. Its wholly owned subsidiary Ukrgazvydobuvannya (UGV) has further tight gas acreage, including Hersevanivska (350 sq km) and Shebelynske (223 sq km). Naftogaz has compiled a list of 13 potential tight gas fields in the area. with combined prospective resources of nearly 9 Tcfg in mid to late Carboniferous and early Permian reservoirs.

Messoyakhskoye Vostochnoye field area, Yamal-Nenets AO, W. Siberia, spudded May ‘17, TD 3,190m (L. Cretaceous), tested up to 11.1 MMcfg/d + 698 bc/d on 14mm choke in reservoir BU21/0 between 2,904-2,909m and likewise from the upper part of BU21/0 between 2,893-2,903m. Meanwhile in July Messoyakhskaya Zapadnaya-203 (spudded Apr ’17) TD’d at 2,600m (M. Jurassic), tested 3.3 MMcfg/d + 15 bc/d, followed by Messoyakhskaya Vostochnaya-309, spudded Jun ’17, PTD 3,200m, currently suspended.  

Russia (West Siberian B.) Messoyakhskaya Vostochnaya 309 op. by MESSOYA (100.0%) in Messoyakhskoye Vost. block

On 3 July 2018, the General Directorate of Petroleum Affairs (GDPA) awarded Turkish Petroleum Corp (TPAO) a new and exclusive exploration licence for onshore area F19-b2. The licence (145.1 sq km) is located in the NW Turkish province of Tekirdag (District I) and will be valid for an initial five-year term. It adjoins TPAO's existing F19-b3 exploration licence and lies within the Thrace Basin.<P />The Thrace Basin has received a lot of attention recently, following Valeura and Equinor's successful Yamalik 1 NFW. Over four production tests within the Eocene Kesan formation, the well tested an aggregate 24-hour rate of around 2.9 MMcfg/d, thereby validating the JV's basin-centred gas play concept. Area F19-b3 lies along the eastern edge of this play fairway.<P />Traoil Dogal Enerji Kaynaklari Arastirma ve Uretim San Tic AS submitted the original application for the same area on 11 December 2017, with TPAO submitting a rival application a week later.

TPAO (100%) was awarded exploration licences, E18-C1,C2,C3, E18-D1,D2 and F19-A1,A2,A3

On 25 September 2019, the Nigerian National Petroleum Company (NNPC) has signed a novation agreement with partners Nigerian Agip Oil Company (NAOC) and Oando Energy Resources Inc (Oando) regarding the OML 60, OML 61, OML 62 and OML 63. The deal signifies the transfer of the NNPC interest to Nigerian Petroleum Development Company (NPDC) which is the upstream branch of the NNPC. The general manager director of NNPC, Mallam Mele Kyari, said on 25 September 2019 in NNPC headquarters in Abuja: "the agreement marked a significant milestone, with the promise to bring about an amicable end to all litigations, and arbitrations that have over the years inhibited the growth of those assets." and added that the agreement "would open up the company to contribute to cash calls and further progress the growth of the partnership." Eni, via its Nigerian subsidiary, NAOC, is the operator and holds 20% interest in the OML 60, 61, 62, 63, partners are NPDC (60%) and Oando (20%).

Nigeria, not found

Kenli 10-1N-1 (KL 10-1N-1) was plugged and abandoned in early March 2016, having encountered oil shows in the target reservoirs. The oil and gas exploration well was spudded on or around 29 December 2015 using the “Bohai 12” jack-up. Kenli 10-1N-1 was likely targeting the Mesozoic volcanic reservoir. Kenli 10-1N-1 is located in the CNOOC operated Bonan Block in the Bohai Gulf Basin.<P />

Kenli 10-1N-1 (KL 10-1N-1) was plugged and abandoned in early March 2016, having encountered oil shows in the target reservoirs. The oil and gas exploration well was spudded on or around 29 December 2015 using the “Bohai 12” jack-up. Kenli 10-1N-1 was likely targeting the Mesozoic volcanic reservoir. Kenli 10-1N-1 is located in the CNOOC operated Bonan Block in the Bohai Gulf Basin

In March 2020, Oil Search Ltd reported that it has received, and accepted, an offer of award for exploration licence application APPL 608. The formal award is now pending Ministerial grant. APPL 608 covers an area of 3,408 sq km to the east of Hides and Angore gas fields and is thought to be prospective in Lower Cretaceous to Upper Jurassic clastic reservoirs, such as the Toro and Digimu sands. Esso Highlands drilled the Trapia 1ST1 well in 2012 on the western edge of the area, in which, Oil Search participated. The well was drilled to a depth of approximately 3,800 m but initial petrophysical evaluations indicated that a prospective reservoir interval was not encountered. The majority of the application area was last held by Toro Oil Ltd, through licence PPL 194, which expired in 2003. BP has also been a major player over the acreage. Upon the initial submission, APPL 608 covered an area of over 8,500 sq km. Oil Search has since been reduced the application area to 3,408 sq km. Registered on 21 February 2017 and quickly gazetted on 26 May 2017, APPL 608 has been offered to Oil Search (PNG) Ltd by the Department of Petroleum and Energy. The formal award remains subject to Ministerial grant.

Oil Search Ltd APPL 608, Papuan Fold Belt - award offer accepted Papua New Guinea In March 2020, Oil Search Ltd reported that it has received, and accepted, an offer of award for exploration licence application APPL 608. The formal award is now pending Ministerial grant. APPL 608 covers an area of 3,408 sq km to the east of Hides and Angore gas fields and is thought to be prospective in Lower Cretaceous to Upper Jurassic clastic reservoirs, such as the Toro and Digimu sands. Esso Highlands drilled the Trapia 1ST1 well in 2012 on the western edge of the area, in which, Oil Search participated. The well was drilled to a depth of approximately 3,800 m but initial petrophysical evaluations indicated that a prospective reservoir interval was not encountered. The majority of the application area was last held by Toro Oil Ltd,

In mid-January 2018, Perenco was completing the Vanneau Marine 3 deviated appraisal well in the Vanneau production licence, North Gabon Sub-basin. The well was spudded on 3 December 2017 with the Petrofor’s “Dagda” J/U and reached a TD of 3,021 m on 1 January 2018. Perenco Gabon SA operates the licence with an 87.75% interest, while Government of Gabon holds the remaining 12.25% interest. The Vanneau Marine field was discovered in September 1985 with the Eyena Vanneau Marine 1 well and production started in November 1993. The oil production reached its top level in 1994 with an average of 1,700 b/d before dropping to 500 b/d in 2016.

Vanneau Marine-3 appr Gabon (Gabon Coastal B.) ? op. by PERENCO (87.75%, GOVT GA 12.25%) in Vanneau block deviated well, TD 3,021m, w.o. results

Stone Energy Offshore has completed acquisition of 100% working interest from Shell Offshore in Viosca Knoll blocks VK 911 (G06892) and VK 912 (G06893), situated in the Louisiana Coastal Basin, according to reports in early June 2018. VK 911 and VK 912 comprise part of the Ram Powell Unit, which sited in 975m of water and capable of processing 60,000 bo/d and 200 MMcfg/d. In late April 2018, Stone Energy indicated that it had agreed to purchase the Ram Powell Unit from Shell Offshore, ExxonMobil and Anadarko US Offshore. The Ram Powell assets comprise six lease blocks and the Ram Powell TLP. Production for the Ram Powell Field averaged ~6,100 bbl/d during 2017. Following completion of the transaction, Stone Energy Offshore is now the operator and sole interest-holder (100% WI + Op) in VK 911 and VK 912.

Stone Energy Offshore has completed acquisition of 100% working interest from Shell Offshore in Viosca Knoll blocks VK 911 (G06892) and VK 912 (G06893), situated in the Louisiana Coastal Basin

ConocoPhillips has transferred a 4.9352% interest in the Point Thomson Unit to Hilcorp, a result of COP's decision to exit the unit in 2017. Point Thompson lies east of Prudhoe Bay.

ConocoPhillips has transferred a 4,9% interest in the Point Thomson Unit (lies east of Prudhoe Bay, to Hilcorp.

Reabold Resources plc announced on the 26 May 2020 that it signed a Sale and Purchase Agreement with Humber Oil and Gas to acquire Humber's 16.665% interest in PEDL 183 which contains the West Newton field. The deal completed on 29 July 2020. Consideration for the deal comprised GBP 1.4 million and the issue of 350,000,000 ordinary shares of 0.01p in the capital of Reabold. The acquirer's effective economic interest in the licence increased from 39% to 56% where the interest comprises a 16.665% direct interest and a 39.66% indirect interest via the company's 59.48% shareholding in operator of West Newton, Rathlin Energy which holds 66.67% interest in the licence. Rathlin is planning on drilling two wells at its West Newton B site in PEDL 183, the first is planned to spud in August 2020. Operations are planned to appraise the Kirkham Abbey Formation and also test the deeper Cadeby Formation. One well is planned to be vertical whilst the other will be horizontal. On 15 April 2020 it was reported that Rathlin had commenced preparatory work at its site in compliance with the landowner and regulatory agreements and keeping with the government guidance regarding COVID-19. Operations involve the completion of the access track and site along with tasks in line with the pre-operational conditions set out by Rathlin's Environment Agency and East Riding of Yorkshire Council permissions. On 4 May 2020 it was confirmed that construction of the access track has begun and will five to six weeks to complete. In April 2019 Rathlin drilled appraisal well L46/05-4 (West Newton A-2). The well was successful encountering hydrocarbons (including a significant liquids component) across a 65 m (net) interval in the Kirkham Abbey Formation along with shows in the Cadeby Reef Formation. Drilling operations were concluded after reaching a TD of 2,061 m and a total of 28 m of core was cut and recovered from the Kirkham Abbey reservoir. In an update on 29 August 2019 it was confirmed that testing operations which had kicked-off had been suspended in order to review the well test to investigate an oil column that has been identified through petrophysical evaluations. It is understood that a gross oil column of 45 m had been encountered underlying a 20 m gross gas column in the Kirkham Abbey interval. The Petrophysical studies on core and information from the logs indicates encouraging porosities seen in the oil zone, the core also exhibited natural fracturing. The Extended Well Test was paused to allow for the equipment to be reconfigured to implement a revised production test which will better reflect the oil zone. In 2013 Rathlin 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. It 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 Cadeby 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. Following the completion of the deal interest in the licence is held by Rathlin Energy (UK) Limited (66.67% + operator), Reabold Resources plc (16.665%) and Union Jack Oil Plc (16.665%).

(Anglo-Dutch B.) Reabold Resources plc announced on the 26 May 2020 that it signed a Sale and Purchase Agreement with Humber Oil and Gas to acquire Humber's 16.665% interest in PEDL 183 which contains the West Newton field. The deal completed on 29 July 2020. PEDL 183 op. by CONNAUGHT (42%), REABOLD (41%), UNION JACK (17%).

Aker BP spudded appraisal well 25/4-14 S at Alvheim in PL 036 C on 28 August 2019. The well was plugged on 9 September 2019 and appraisal sidetrack 25/4-14 A was kicked-off the following day. The “Deepsea Stavanger” S/S is being used for the work which is expected to take around 22 days. The wells are located approximately 1.5 km southwest of the East Kameleon (L) template. Aker BP has been busy exploring south of Alvheim in the last 18 months. In Q1 2018 it made a discovery with its Frosk well 24/9-12 S and it drilled a successful appraisal of Gekko in Q3 2018. In early 2019 the Froskelar well (24/9-14 S) also made a new discovery, as did the subsequent Froskelar Northeast well (24/9-15 S). In July 2019 Rumpetroll (24/9-13) was drilled, making a minor gas discovery. Aker BP ASA operates PL 036 C with a 65% interest. It is partnered by ConocoPhillips Skandinavia AS (20%) and Lundin Norway AS (15%).

orway (Viking Graben) 025/04-14 S (Alvheim) (Aker BP 65% op, ConocoPhillips 20%, Lundin 15%) in PL 036 C, P&A, results awaited.

On 12 June 2020, the Office National des Hydrocarbures et des Mines (ONHYM) officially announced the contract signature for the Mesorif reconnaissance licence with ConocoPhillips Morocco Ventures Ltd (ConocoPhillips), marking the Company's return to Morocco after more than fifteen years of absence in the country's E&P industry. The 23,000 sqkm block is located in the South Rifan Trough (Rharb-Prerif Basin) and will be operated by ConocoPhillips with 75% working interest, partnering ONHYM with carried 25%. The main commitments of the two years contract will consist of the achievement of geological and geophysical studies in the first year and the acquisition of 2D seismic data during the second year of the licence. The area is a prolific one comprising more than 6,000 m of Mesozoic and Cenozoic sediments, proven source rocks in the Lower Jurassic and Upper Cretaceous, and Middle – Upper Jurassic reservoirs considered as main in the Mesorif geological province. Additional potential is anticipated in plays similar to the producing ones (during the '30s – '50s) and in yet untested old salt structures, sub-thrust and over-thrust traps. Phillips drilled some onshore and offshore wells in the area back in the '80s.

Morocco, ConocoPhillips Company awarded Mesorif reconnaissance contract, onshore Morocco.

E. sector of Baykalovskoye discovery area, Yenisey-Khatanga Basin in Krasnoyarsk Kray, W. Siberia, 2016-2017 well to TD 3,600m, hc reportedly encountered, target L. Cret. Nizhnekhetskaya fm, Novourengoyskaya Burovaya crew. Results expected mid-2018, may determine whether a pipeline linking to the Vankor field is required.   Yermak Neftegaz = BP-Rosneft 49:51 JV.

Baykalovskaya-21,E. sector of Baykalovskoye discovery area, Yenisey-Khatanga Basin in Krasnoyarsk Kray, W. Siberia, 2016-2017 well to TD 3,600m, hc reportedly encountered, target L. Cret. Nizhnekhetskaya fm, Novourengoyskaya Burovaya crew. Results expected mid-2018, may determine whether a pipeline linking to the Vankor field is required. Yermak Neftegaz = BP-Rosneft 49:51 JV.

On 9 December 2019, PGNiG and Energy Resources of Ukraine (ERU) signed an Agreement on cooperation in exploration and production of hydrocarbons in the Byblivska license near in Lviv Oblst, near the border with Poland. Exploration activities including drilling of an exploratory well with a PTD of 2,500 m and a seismic survey will be started after obtaining all approvals and permits. The Byblivska license, covering 85 sq km in the Inner Carpathian Foredeep, is operated by Karpatska Industrialna Grupa 2014. In mid-December 2019, media reported that ERU acquired the license operator.

PGNiG and Energy Resources of Ukraine (ERU) signed an Agreement on cooperation in exploration and production of hydrocarbons in the Byblivska license near in Lviv Oblst, near the border with Poland.

China Offshore Oil Corporation's (CNOOC), on 22 November 2018, granted PETRONAS subsidiary, PC Carigali Mexico Operations SA de CV, 30% WI in the deepwater CNH-R01-L04-A4.CPP/2016 contract, according to the Comision Nacional de Hidrocarburos (CNH). The farm-out news emerged in a regulatory meeting on 31 January 2019, in which the CNH approved the transfer of WI to CNOOC's new partner. CNOOC will retain 70% and its role as operator. No other details about the transaction were available as this report went to press. CNOOC's 1,876 sq km block is in the Salina del Bravo Basin. Water depths in the contract area span 500-2,000m. The CNH, on behalf of the Mexican state, signed an agreement with CNOOC for the Round 1.4 block in 2017. CNOOC is understood to have a prospect identified for drilling, The well, the Xakpun 1 NFW, would target the Eocene sequence (Wilcox trend). With a PTD of around 5,500m, the well will transverse a 2,000m salt layer. Xakpun, may drill this year. The well's location is sited in water depth of 1,580m.

Not Found

Stuart secured sole rights on 25 Jun '20 to retention lease PRL 245, 93.2 sq km in the Cooper-Eromanga, for 5 years. Likewise adjacent PRL 246, 51.6 sq km.

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

During Q1 2018, Aladdin Middle East Ltd successfully completed the Sadak East 6 (Sadak Dogu-6) appraisal well as an oil producer and placed it on production with an ESP pump. The well started producing at a rate of 1,150 bo/d without water.<P />Sadak East 6 is located on the M48-a3-1 production lease in the SE Turkish province of Siirt (District X). The well was spudded on 28 November 2017 using the AME-101 (IDECO H-725) rig and reached a final TD of 2,552m in the Cretaceous Mardin formation. It was designed to appraise the Sadak East 1 oil discovery (final TD of 2,511m) which encountered and sampled moveable oil (API 35deg) with no water or hydrogen sulphide.<P />The discovery is understood to be on trend with the oil discoveries of Tawke in the Kurdistan Region of Iraq and Garzan in Turkey. Aladdin Middle East Ltd (AME) holds an 88% interest in the acreage and is partnered by local Turkish company Sonar Petrol AramaUretim Ltd (12%).

Aladdin Middle East Ltd successfully completed the Sadak East 6 (Sadak Dogu-6) appraisal well as an oil producer and placed it on production with an ESP pump. The well started producing at a rate of 1,150 bo/d without water.<P />Sadak East 6 is located on the M48-a3-1 production lease in the SE Turkish province of Siirt (District X).

Patagonia Oil Corp. has reportedly acquired Roch’s 10% interest in the Llancanelo block, boosting its stake to 39% after having done the same earlier with PentaNova’s 29%. YPF remains operator with 61% of the 27-sq km block in Mendoza (Neuquén Basin), with heavy oil plans. Patagonia’s actual farmin to the permit (11% in Apr ’17) is still pending Mendoza approval.

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

According to industry sources in June 1018, Pemex may try to secure JV partners to help develop a farm-out package of offshore heavy oil fields, including assets like the shallow water Utsil and Ayatsil-Tekel trend. First discovered in 2006, the Ayatsil-Tekel complex has total reserves of 1.62 million boe and 1P reserves of 544 million boe. The trend hosts oil with less than or equal to 11 degrees API gravity. The Bay of Campeche heavy oil trend known covers some 88.8 sq km. Pemex may also re-offer the Ayin-Batsil (CNH-A2-AYIN-BATSIL/2017) contract. No timeline is available, but a competitive bidding process for these heavy oil fields could be announced in H2 2018/H1 2019. A previous attempt to farm-out the Ayin-Batsil contract on 4 October 2017 failed to draw any bids. The competitive farm-out process was handled by the Comision Nacional de Hidrocarburos (CNH). First discovered by Pemex, the Ayin-Batsil cluster lies in the Bay of Campeche. Pemex has said the contract area holds 359 MMboe in 3P reserves (and 224 MMboe in prospective resources). The Ayin-Batsil play covers 1,096 sq km. Batsil is located in water depth of 82m and Ayin in 176m.

According to industry sources in June 1018, Pemex may try to secure JV partners to help develop a farm-out package of offshore heavy oil fields, including assets like the shallow water Utsil and Ayatsil-Tekel trend.

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

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

Abu Dhabi’s Supreme Petroleum Council expects the first licences issued from the 2018 round to be awarded in 1Q ’19 (delayed from 4Q ’18). A total of 39 companies intend to apply for rights, the round now closed.

Abu Dhabi’s Supreme Petroleum Council expects the first licences issued from the 2018 round to be awarded in 1Q ’19 (delayed from 4Q ’18). A total of 39 companies intend to apply for rights, the round now closed.

On 7 November 2018, the consortium of Shell with 40% working interest, Chevron with 40%, and Petrogal with 20%, was granted an official award for the C-M-791 block in the offshore Campos Basin through the ANP Round 15. On 29 March 2018, the consortium was granted a preliminary award for the block. For the C-M-791 block the consortium offered a bonus of USD 166.50 million and 1,203 work units.   There were two other bids for the block.   The consortium of BP, Statoil, and Total offered a bonus of USD 160.1 million and 204 work units while the third place bid was from the consortium of ExxonMobil, Petrobras, and QPI who offered a bonus of USD 124.62 million and 200 work units.

Consortium of Shell with 40% working interest, Chevron with 40%, and Petrogal with 20%, was granted an official award for the C-M-791 block in the offshore Campos Basin through the ANP Round 15.

On 16 September 2018, Kuwait Energy Company KSCC (Kuwait Energy) signed a new agreement with Egypt Oil Ministry for its Abu Sennan concession, Abu Gharadig basin. This USD 10 million agreement includes a USD 2 million signing bonus and the drilling of four wells. Kuwait Energy operates the concession with a 25% interest. The other partners are Global Connect Ltd with a 25% interest, Dover Investments with a 28% and Rockhopper Exploration plc. with a 22% interest.   Background information The concession is under a Production Sharing Contract (PSC) covering five 20-year development leases (containing mainly oil with associated gas) and one exploration licence. The company reported six oil prospects identified with two to four targets in each reservoir, mainly in the Abu Roash, Bahariya, and Kharita formations. There are also additional reserves upside associated with water flood projects post technical studies. Kuwait Energy completed the gas production facilities and commenced gas production sales in 2015. On 4 October 2017, Kuwait Energy had sold a 25% interest in Abu Sennan concession, Abu Gharadig basin to Global Connect Limited.

Kuwait Energy Company KSCC (Kuwait Energy) signed a new agreement with Egypt Oil Ministry for its Abu Sennan concession, Abu Gharadig basin. This USD 10 million agreement includes a USD 2 million signing bonus and the drilling of four wells.

The DGH has opened bids related to the 1st bidding round of Open Acreage Licensing (OAL1) upon the application deadline yesterday. Sign of the times, 110 e-bids were submitted by 9 companies (individually or as a group) for 55 blocks (92 bids for 46 onshore blocks, 18 for 9 offshore blocks). Awards are expected in June.           As could be expected, ONGC and Cairn India were the highest bidders, Cairn India even bidding for all 55 blocks on offer. The extensive list of applications in available through GEPS.

India, not found

Agreement to add interest in resource with approx. 2 billion barrels of high-quality oil ExxonMobil and partners high bidders in adjacent and other blocks in recent bid rounds ExxonMobil adds more than 1.25 million net acres to deepwater portfolio offshore Brazil ExxonMobil has completed an agreement to purchase half of Statoil’s interest in the BM-S-8 block offshore Brazil, which contains part of the pre-salt Carcara oil field. The Carcara field contains an estimated recoverable resource of 2 billion barrels of high-quality oil. The block is located approx. 200 miles offshore Rio de Janeiro. Statoil currently holds a 66 percent interest in the block, which contains about half the Carcara field. The other part of the field is in the adjacent North Carcara block, where ExxonMobil, Statoil and Petrogal Brasil were high bidders in a bid round held today. Statoil will continue to operate the Carcara development and hold 33 percent interest. Over the last month, through bid rounds and announced farm-in agreements, ExxonMobil has added 14 blocks comprising more than 1.25 million net acres offshore Brazil to its portfolio, bringing its total acreage in the country to more than 1.4 million net acres. 'These agreements and recent bid round results mark ExxonMobil’s entry into a world-class resource and prospective exploration acreage in Brazil,' said Darren Woods, chairman and chief executive officer of ExxonMobil. 'ExxonMobil has a long history in the country and we’re confident our deepwater technology and project expertise can help to further grow the value of Brazil’s energy resources. We look forward to working with Petrobras and all our partners to begin to explore and develop this high quality acreage.' Separately, ExxonMobil recently added highly prospective acreage to the company’s portfolio after completing a farm-in agreement with Queiroz Galvão Exploração e Produção (QGEP). ExxonMobil will make an upfront cash payment of approx. $800 million for the interest in BM-S-8 block, and an additional contingent cash payment for a potential total of approx. $1.3 billion. The transaction is subject to government approvals and is expected to close in 2018. Following the close of the transaction, partner interests in the BM-S-8 block will be 33 percent for Statoil, 33 percent for ExxonMobil, 14 percent for Petrogal Brasil, a subsidiary of Galp, and 10 percent each for QGEP and Barra. See related article: Statoil shapes and strengthens its position in the Carcará oil discovery in Brazil Original article link Source: ExxonMobil

ExxonMobil purchased half of Statoil’s interest (33%) in the BM-S-8 block and completed award of Norte de Carcará block during 2nd PSC Pre-Salt deepwater round.

Jambi PPC in S. Sumatra, TD 3,120m, min. 5 DSTs performed since June, well believed completed mid-summer, results yet unreported. Targets TAF + pre-Tertiary Basement.

Indonesia (South Sumatra B.) Puspa 3 op. by PERTAMINA (100.0%) in Jambi block

Exxon sub. PNG Robin Ltd was awarded PPL 600,  1,360 sq km across the Papuan Fold Belt + Fly Platform on 26 Sep ’18 for 6 years:

ExxonMobil, was awarded exploration licence PPL 600, located across the Papuan Fold Belt and Fly Platform.

Ranipur / 2768-11 block, Middle Indus onshore, Sindh, TD 4,476m end Aug ’17, DST’d but dry, P+A late Nov ’17, TCPDC-1 rig. OGDC (op), partner Sindh Energy Holding Co.

Ranipur 1 op.by OGDCL (97,5%, GHPL 2,5%) in Ranipur / 2768-11 block, P&A, DST’d but dry.

NW Sitra block, Abu Gharadiq Basin, W. Desert, TD 1,814m, P&A dry, no details. Target Cretaceous.

NW Sitra-9 (TransGlobe Energy100%) in North West Sitra concession has come up dry, targeting a stacked Cretaceous prospect, but no hydrocarbons were found.

On 18 March 2018, Hungarian Horizon Energy Group (HHE) completed drilling wildcat Bürüs 1 in the Lakócsa concession in southwestern Hungary. The well encountered water-wet target horizon and was abandoned. HHE is the sole operator of the Lakócsa permit. Bürüs 1 was likely spudded in early March 2018. The 355 sq km Lakócsa block is located in the Baranya and Somogy political provinces, along the border with Croatia, within the Somogy-Drava Sub-basin, tectonic unit of the Pannonian Basin. The well had a planned final depth estimated at 1,800-2,000 m, targeting the Lower Pannonian and Miocene successions (details unavailable). Background Information The Lakócsa concession was granted to HHE by the Minister of National Development on 15 February 2016 (preliminary award was pronounced in late November 2015). The award followed the country’s 2015 bid round. The Lakócsa contract is valid for twenty years from the effective date, with possible one, 10-year extension. The latest activity in the tract dates back to February 2018, when HHE abandoned wildcat Bürüs 2.

Burus 1 (Aspect Energy 100%) in Lakocsa concession, P&A, encountered water wet sands in the Lower Pannonian and Miocene successions.

S. part of Junggar Basin, drilled 14 May – Jun '20, ops concluded. PTD was 7,280m, target deep Cretaceous.

(Junggar B.) Hutan (Ju) 1 op. by PETROCHINA (100%) in Southern Margin East I block S. part of Basin, ops concluded without result reported. PTD was 7,280m, target deep Cretaceous.

Petronas Carigali has plugged and abandoned new-field wildcat Lala 1, in block ND 2, situated in the ultra-deep water West Luconia Province, on or around 9 May 2020. Result has not been released. The well, re-entered on or around 2 March 2020, was drilled using the Seadrill "West Capella" D/S and targeted the stratigraphic play of the Late Miocene Cycle V turbidite fan. It was originally spudded on or around 3 January 2020, but drilling was temporary suspended around 14 January 2020. Lala 1 is located approximately 95 km northwest of the Paus 1 oil and gas discovery, drilled by Newfield in 2009. Recoverable resource for the Lala prospect could be around 240 MMbbl (oil case). Prior to Lala 1, Bukoh 1 (2011) is the only well drilled in the block. The well, spudded on 24 January 2011, was drilled to a TD of 4,514m by Transocean "Deepwater Expedition" D/S and it targeted the pre-MMU of the Lower Miocene Cycle II and Oligocene Cycle I clastics. The well was plugged and abandoned as a dry hole on 2 May 2011. Farm-in opportunity still exist for the block. Block ND-2 is 100% held and operated by Petronas Carigali. Background Information The block is covered with extensive 2D and 3D seismic data, electromagnetic and CSEM acquired by the current operators of the block. A 7,300 sq km 3D seismic survey was acquired Western Geco "Gego Eagle" S/V between September 2006 and March 2007. The survey was acquired over ND 1 and ND 2 and a separate survey over ND 3. Between December 2008 and January 2009, a Controlled Source Electromagnetic (CSEM) survey was acquired over ND 2 and ND 3. The survey was acquired by EMGS, using the 'Atlantic Guardian' M/V towing a 300 m long cable 30m above the seabed. Only one well was drilled in the block. Bukoh 1 (2011) targeted the synrift play of the pre-MMU Lower Miocene Cycle II and Oligocene Cycle I clastics. The well was plugged and abandoned as dry hole. Block ND 1, ND 2 and ND 3 were awarded to Petronas Carigali (100%) as the operator on 29 July 2005. Block ND 2 is approximately 5,732 sq km in size and located in water depth of 200 m to 2,000 m. The ultra-deep water areas of the North Luconia Province and West Luconia Province include an undrilled synrift play, carbonate buildup and the stratigraphic play of the post-MMU turbidite fans.

Lala 1 (Petronas 100%) in ND-2 block, P&A, tight hole, WD=1700m,TD about 4500m.

On 12 September 2018, Sapura Energy announced that it has entered into a Heads of Agreement with OMV Aktiengesellschaft (OMV AG) for a proposed sale of 50% stake in its wholly-owned subsidiary, Sapura Upstream. The proposed transaction is based on an enterprise value of US$ 1.6 billion (RM 6.5 billion). Negotiations between two parties are currently on-going. The deal is in line with OMV’s plan to expand its exploration business in Southeast Asia by end of 2018. Earlier this year, OMV expanded its operations in New Zealand through acquisition of Shell’s upstream assets, Pohokura and Maui fields and Great South Basin (GSB) exploration block. Sapura Energy operators in six PSCs and partner with Petronas Carigali in two PSCs in Malaysia. It also has assets in newly acquired acreages in New Zealand, Gulf of Mexico and Australia. The table below shows Sapura’s assets in Malaysia and its interest.   BLOCKS STATUS* SAPURA’S SHARE PARTNERS 1 Peninsular Malaysia PM-323 OP 60% Petronas Carigali 40% 2 PM-329 OP 70% Petronas Carigali 30% 3 PM-318   50% Petronas Carigali (OP) 50% 4 PNL/Abu Cluster   50% Petronas Carigali (OP) 50% 5 Sarawak SK-408 OP 40% Sarawak Shell Berhad Petronas Carigali 30% 30% 6 SK-310 OP 30% Petronas Carigali Diamond Energy Sarawak 40% 30% 7 Sabah SB-331 OP 70% Petronas Carigali Sabah International Petroleum (SIP) 20% 10% 8 SB-332 OP 70% Petronas Carigali Sabah International Petroleum (SIP) 20% 10% *         OP = Operator

On 12 September 2018, Sapura Energy announced that it has entered into a Heads of Agreement with OMV Aktiengesellschaft (OMV AG) for a proposed sale of 50% stake in its wholly-owned subsidiary, Sapura Upstream. The proposed transaction is based on an enterprise value of US$ 1.6 billion (RM 6.5 billion).

In early March 2018, industry sources indicated that the authorities may be offering former OK Energy-operated acreage for exploration rights (ER) off the south coast in the Outeniqua basin. In this area, OK operated the OK Energy 1 block over about 7,000 sq km in WD 0-300m. Should this be confirmed, the offer would entail blocks 3422 A, B + D. OK Energy relinquished the block around February 2019, the company otherwise retains acreage in the Algoas/Outeniqua Basin (ER 257) and in the Orange Basin. In January 2016, OK Energy was awarded Exploration Rights for block OK Energy 1. It is located northeast of Block 9. Eight wells were drilled in the area, the last by Soekor (Pty) Ltd in 1986, all of which were plugged and abandoned as dry. OK Energy operated the block with a 100% interest.

In early March 2018, industry sources indicated that the authorities may be offering former OK Energy-operated acreage for exploration rights (ER) off the south coast in the Outeniqua basin. In this area, OK operated the OK Energy 1 block over about 7,000 sq km in WD 0-300m. Should this be confirmed, the offer would entail blocks 3422 A, B + D. OK Energy relinquished the block around February 2019, the company otherwise retains acreage in the Algoas/Outeniqua Basin (ER 257) and in the Orange Basin. In January 2016, OK Energy was awarded Exploration Rights for block OK Energy 1. It is located northeast of Block 9. Eight wells were drilled in the area, the last by Soekor (Pty) Ltd in 1986, all of which were plugged and abandoned as dry. OK Energy operated the block with a 100% interest.

On 20 December 2017, the ANP approved the final step in a complex transaction whereby Statoil is now the operator and 100% working interest owner of the BM-ES-040 contract, ES-M-529 block and the BM-ES-041 contract, ES-M-531 block after acquiring a 50% working interest (WI) from former partner Perenco.   The deal was reported originally in early 2017 after a four step process led to Statoil being operator with 50% WI and Perenco the lone partner with 50% WI.  In July 2017 the operator was granted second extension of the PAD associated with the two contracts. On 16 December 2016, the ANP approved a complex transaction whereby Statoil is now the operator of the BM-ES-040 contract, ES-M-529 block and the BM-ES-041 contract, ES-M-531 block after acquiring a 50% working interest (WI) part of it from former operator and now 50% partner Perenco.  The transaction involved a four stage process for unknown reasons.  First Perenco farmed-out 30% WI and operations to Statoil, giving Statoil as operator 30% WI OGX with 50%, and Perenco and Sinochem each with 10% WI.  The second stage was Perenco assuming 40% WI of the OGX 50% WI and Sinochem assuming 10% with Statoil with 30%, Perenco with 50%, and Sinochem with 20%.  The third stage was Perenco assuming the 20% WI of Sinochem with Sinochem out and resulting in Statoil the operator with 30% WI and Perenco with 70% WI.  The final stage of the transaction was the acquisition by Statoil of 50% WI from Perenco resulting in the current approved working interest breakdown of Statoil as operator with 50% WI and Perenco with 50%.  There was no time-frame given by the ANP for when the separate transactions occurred nor has there been a report regarding the transaction value.  Both blocks are involved in the discovery evaluation plan (PAD) PA_1PERN4ESS_BM-ES-40, Dende prospect oil and gas discovery.  On 5 July 2017, the ANP approved a second request by Statoil, operator of the BM-ES-040 contract, ES-M-529 block and the BM-ES-041 contract, ES-M-531 block to modify the discovery evaluation plan (PAD) PA_1PERN4ESS_BM-ES-40, Dende prospect oil and gas discovery associated with the contracts.   The ANP modified the decision point date for stage 1 of the PAD from 16 March 2017 to 16 March 2018.  The PAD still has a final expiry date of 31 December 2019 if all commitments are met. On 15 February 2017, the ANP approved a request by Statoil, operator of the BM-ES-040 contract, ES-M-529 block and the BM-ES-041 contract, ES-M-531 block to modify the discovery evaluation plan (PAD) PA_1PERN4ESS_BM-ES-40, Dende prospect oil and gas discovery associated with the contracts.   The ANP modified the decision point date for stage 1 of the PAD from 31 December 2016 to 16 March 2017.  The PAD still has a final expiry date of 31 December 2019 if all commitments are met. On 8 July 2015, the ANP approved Perenco’s modified discovery evaluation plan (PAD) submitted for the PA_1PERN4ESS_ES-M-529 evaluation area that includes portions of the BM-ES-040 Contract, ES-M-529 block and BM-ES-041 Contract, ES-M-531 block. Both blocks were also partially relinquished.  The PAD approval is the result of the evaluation of the 1-DENDE-001-ESS (1-PERN-004-ESS) new-field wildcat (NFW) suspended with shows on 13 August 2013.  The partners have firm and contingent commitments for the PAD. They include acquiring new 3D Broadseis seismic, drilling up to two appraisal wells and conducting cased hole production tests.  If all of the firm and contingent commitments are carried out the PAD will have a final expiry of 31 December 2019.

Statoil is now the operator and 100% WI owner of the BM-ES-040 contract, ES-M-529 block and the BM-ES-041 contract, ES-M-531 block after acquiring a 50% WI from former partner Perenco.

Block 6, Ghaba Salt Basin, drilled + susp 18 Oct - 5 Nov ’18, TD 1,257m, no details. Likewise Wadi Umayri 6, N. part of block 6, Makarem-Mabrouk High, drilled + susp 16-26 Nov ’18, TD 2,027m. Target assumed Lekhwair fm.

Rasheeq-1 nfw Block 6, Ghaba Salt Basin, drilled + susp 18 Oct - 5 Nov ’18, TD 1,257m, no details. Likewise Wadi Umayri 6, N. part of block 6, Makarem-Mabrouk High, drilled + susp 16-26 Nov ’18, TD 2,027m. Target assumed Lekhwair fm.

On 28 February 2020, Petrobras published a modification to its teaser originally published on 3 February 2020, to sell between 40-50% non-operated working interest in the BM-PAMA-003 and BM-PAMA-008 contracts, denominating the asset the Para-Marannao Basin. The company has extended the dates for document submissions to 5 March 2020. Petrobras has 100% working interest in the discovery evaluation plan (PAD), PA_1BRSA903PAS_BM-PAMA-3 associated with the 833.28 sq km BM-PAMA-003 contract again since May 2016 when the ANP approved the operator assuming the 20% working interest previously held by Sinopec. The final expiry date of the PAD was extended from 6 April 2017 to 15 December 2020 and Petrobras is offering up to 50% working interest in the exploration concession. Petrobras has one prospect pending an environmental permit in the contract, the Gaviao prospect. Petrobras is operator of the BM-PAMA-008 Contract, 769.22 sq km PAMA-M-192 block and 769.22 sq km PAMA-M-194 block with an 80% working interest and lone partner is Sinopec with 20% working interest whom Petrobras indicated has the first right of refusal on the 40% working interest being offered. The latest ANP information indicates the contract still in the suspended stage, since 2014, until an environmental permit is granted by IBAMA. Petrobras has two prospects pending environmental permits in the PAMA-M-192 block, the Tambaqui and Pirarucu prospects. The customary qualification and manifestation of interest are required to enter the non-binding phase of the divestment process. The manifestation of interest must be sent to [email protected] by 16 February 2020. The qualification documents must be sent to [email protected] by 5 March 2020. On 28 September 2016, the ANP approved a revision to the discovery evaluation plan (PAD), PA_1BRSA903PAS_BM-PAMA-3 operated by Petrobras under the BM-PAMA-003 contract in the offshore Para-Maranhao Basin. The revised PAD has firm and contingent commitments with extensions to decision dates and final expiry. The firm commitments include the following. Petrobras has to PSDM re-process the entire 3D seismic database that exists over the block and conduct new geological and geophysical studies. The operator must also drill an appraisal well by 28 February 2020. The final expiry date of the PAD was extended from 6 April 2017 to 15 December 2020 if all commitments are met. The PAD was originally granted in 2012 and extended the first time in 2015. Petrobras had to commit to an appraisal well to be granted an extension for its PAD which was last extended in 2015 to 6 April 2017. On 11 April 2012 Petrobras had its discovery evaluation plan (PAD), PA_1BRSA903PAS_BM-PAMA-3 approved for the 1-PAS-027 (1-BRSA-903-PAS), Harpia prospect in the Para-Maranhao Basin BM-PAMA-003 contract and block by the ANP. The entire block area of 833.29 sq km is included in the PAD. Petrobras had PAD commitments to re-process the entire 3D seismic database that exists over the block and re-interpret the geology and geophysics with an end date of 6 October 2013. On 22 October 2014, the ANP granted formal approval for operator Petrobras to suspend the 2nd period of the BM-PAMA-008 Contract, PAMA-M-192 and PAMA-M-194 blocks in the offshore Para-Maranhao Basin until an environmental license is granted by IBAMA. The 2nd and final period expiry date of the contract was 24 September 2014 and the suspension has been granted retroactive to 9 July 2014. Once an environmental permit is issued Petrobras will have 107 days added to the contract and 87 days to its retroactive date which indicates the contract will actually have a term of 185 days once the environmental permit is issued.

On 28 February 2020, Petrobras published a modification to its teaser originally published on 3 February 2020, to sell between 40-50% non-operated working interest in the BM-PAMA-003 and BM-PAMA-008 contracts, denominating the asset the Para-Marannao Basin.

Zimniy Zapadnyy licence, S. Ural-Frolov Basin, Khanty-Mansiyskiy AO, W. Siberia, drilled Mar-Jul ’17, TD 3,050m, tested up to 332 bo/d from reservoir AS9 below 2,263m and smaller rates further down.    

Russia (West Siberian B.) Zimnyaya Zapadnaya 1 op. by GAZPROM (100.0%) in Zimniy Zap. block

Effective 1 October 2017 Hilcorp Alaska LLC was officially awarded 14 tracts covering about 76,682 acres (310 sq km) off Alaska’s south-central coast from the Cook Inlet Lease Sale 244 held by the Bureau of Ocean Energy Management (BOEM) on 21 June 2017. The company placed high bids in the amount of USD 3,034,815 and was the sale’s lone bidder. Sale 244 was the thirteenth and final OCS lease sale held under the 2012-2017 Five-Year Program. It offered some 1.09 million acres (4,410 sq km) for leasing and consisted of 224 blocks that stretched roughly from Kalgin Island in the north to Augustine Island in the south. Each bid went through a 90-day evaluation process to ensure the public received fair market value before a lease was awarded. All materials and statistics for Lease Sale 244 are available at: http://www.boem.gov/ak244. Hilcorp Official Awards               Contract Company Name WI Bonus USD Acre Sqkm Lease Sale Award Date Basin   Y02434 Hilcorp Alaska 100 $62,208.00 5,184.26 20.98 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02435 Hilcorp Alaska 100 $37,416.00 3,118.47 12.62 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02436 Hilcorp Alaska 100 $68,376.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02437 Hilcorp Alaska 100 $142,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02438 Hilcorp Alaska 100 $111,606.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02439 Hilcorp Alaska 100 $313,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02440 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02441 Hilcorp Alaska 100 $203,319.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02442 Hilcorp Alaska 100 $111,606.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02443 Hilcorp Alaska 100 $256,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02444 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02445 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02446 Hilcorp Alaska 100 $152,019.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02447 Hilcorp Alaska 100 $152,019.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet    Totals     $3,034,815.00 76,681.62 310.32         Source: IHS Markit               © 2017 IHS  

United States, Y02440

Heritageis offering equity in its 180-sq km deepwater South West Tano block in the Jubilee + TEN field areas. Two firm wells are planned 2 2H 2020. Heritage (op), partners Blue Star Expl. + GNPC. Contact [email protected].

Heritageis offering equity in its 180-sq km deepwater South West Tano block in the Jubilee + TEN field areas. Two firm wells are planned 2 2H 2020. Heritage (op), partners Blue Star Expl. + GNPC.

Finder Exploration is offering a farm-in opportunity in exploration permit WA-500-P, located in the Exmouth Sub-basin. Finder is offering up to 65% interest, and potentially operatorship, to a farm-in partner interested in taking part in the work programme over the permit.  Initially an option fee would be paid for access to data, with the farminee then having the option to acquire interest by reimbursing past costs and taking on work programme funding.  Finder reported that a data room opened in Q1 2018. Searcher Seismic undertook the 504 sq km “Dunnart MC3D” seismic in July 2015, with part of the data acquired over WA-500-P.  Finder reported that potential farm-in partners could pay the option fee to get access to the data and also to the data set from the previously acquired “Drop Bear” 3D seismic.  If the partner wished to continue, it would be required to pay some back costs and also to fully fund the remaining permit costs.  On 9 May 2019, Finder received approval to alter the final term six work programme by removing the commitment to drill an exploration well. The AUD 30 million well has been replaced with seismic reprocessing work. The new programme, which is estimated to cost AUD 220,000, will see Finder completing 200 km PSDM reprocessing of the Dunnart 2D seismic data set and WEB-AVO Inversion of 480 sq km Drop Bear3 3D seismic survey data. The original work programme already included interpretation and anomaly mapping from these seismic datasets. Finder was offering a farm-in opportunity with the attempt of being free carried for the exploration well. With this now removed, Finder will continue to fund the work programme and back payments would be sought after in return for any future farm in agreement. Finder reports that the permit is prospective for hydrocarbons within the Triassic Mungaroo, Jurassic Eliassen and Cretaceous fan units. In May 2017 Finder outlined the Kapteyn Prospect as the major target within the permit, identified from data over the permit area.   WA-500-P, which covers an area of 2,185 sq km, was awarded on 17 April 2014. Finder Exploration currently holds 100% interest and operatorship in the permit. Companies interested in pursuing this opportunity should contact: Shane Westlake, CEO Finder Exploration Pty Ltd, 9 Richardson Street, West Perth, WA 6005. Tel: +61 8 9327 0128 Email: [email protected]

Finder Exploration is offering a farm-in opportunity in exploration permit WA-500-P, located in the Exmouth Sub-basin. Finder is offering up to 65% interest, and potentially operatorship, to a farm-in partner interested in taking part in the work programme over the permit.

It was announced on 24 November 2019 that Turkiye Petrolleri A.O. (TPAO) has been awarded the N46-C exploration licence (Zagros Province) on 18 November 2019 for a period of five-year. The licence, covering an area of around 340 sq km, is located towards southeast of the country and TPAO will be 100% owner and operator of the licence. TPAO had filed the application on 23 May 2019.

TPAO has been awarded the N46-C exploration licence (Zagros Province) on 18 November 2019 for a period of five-year. The licence, covering an area of around 340 sq km, is located towards southeast of the country and TPAO will be 100% owner and operator of the licence.

Block 8, Diyala + Wasit provinces, ops terminated late Nov '19 (HPHT), TD 5,050m, no results, Zepec rig. Targets possibly Zubair, Khasib, Jeribe + Lower Fars fm’s,

Iraq (Dibdibah Sub-basin (Central Arabian Province)) Zubair

Press reports suggest Murphy has acquired a 5% stake from PetroVietnam in block 15-1/05, 3,075 sq km in the Cuu Long Basin. This is presumably an extra 5%, as Murphy already had 35% in the permit. Partnership therefore remains PetroVietnam (op), partners Murphy + SK Innovation.

Vietnam (Cuu Long B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Block 15-1/05 op. by PETROVIET (40.0%, MURPHY 35.0%, SK HOLD 25.0%) to be check.

On 7 February 2020, the Federal Agency for Subsoil Use announced an auction for the Vetosskiy block in Perm Kray (Volga-Ural Province). The auction will be held on 31 March 2020. Applications should be submitted by 6 March. Each participant must make a refundable deposit equal to the starting price for the block. The deposit will be non-refundable if the winner fails to pay its winning bid. Additional information regarding the auction may be requested from: Permnedra Perm Kamchatovskaya Str., 5 Details of the offer are as follows: The Vetosskiy block covers 16.7 sq km and encompasses the Vetosskoye field with 2P oil reserves estimated at 0.13 MMbbl. The starting price amounts to RUB 5.451 million (USD 0.09 million). The winner of the auction will obtain a 20-year license.

On 7 February 2020, the Federal Agency for Subsoil Use announced an auction for the Vetosskiy block in Perm Kray (Volga-Ural Province). The auction will be held on 31 March 2020. Applications should be submitted by 6 March.

KEC has agreed to farmout a 15% interest in block 9,  893 sq km in Basra, S. Iraq, to Dragon Oil. This comprises 8.57% for USD 100 MM cash and 6.43%in settlement of a dispute with Dragon, related to a non-controlling interest in the block. The deal is subject to govt + partner approvals. Resulting partnership will be KEC (op) 45%, Dragon 45%, EGPC 10%.

Dragon Oil (->45%) has taken a15% stake from Kuwait Energy (->45% op. EGPC 10%) in Block 9 for US$100 MM.

Hitherto unreported, on 25 February 2020, the Ministry for Innovation and Technology signed off the concession agreement pertaining to the Kadarkút area in southwestern Hungary, granted to Vermilion Energy Hungary Kft, subsidiary of Vermilion Exploration B.V. The contract has a four-year exploration term, with an option for a two-year extension, and the utimate validity of 20 years (includes production stage), until 25 February 2040. Vermilion is the sole operator of the contract. The 1,208 sq km Kadarkút area is located within the within the Zala Sub-basin, tectonic unit of the Pannonian Basin. The Ministry informed on 4 December 2019 that Vermilion Energy was pronounced the winner of the 2019 tender call for the Kadarkút area. Background Information The 2019 bidding round was opened by the Ministry for Innovation and Technology on 28 May 2019 through the announcements in the EU Official Journal. Eight areas were offered in the tender: Csongrad, Csorna, Erd, Kadarkut, Kisvarda, Nyirbator, Pusztaszer and Zala-Kelet. The closing date for the round, area-dependent, was set on 25/26 September 2019. On 25 September 2019, the Ministry for Innovation and Technology closed the tender procedure for the Kadarkút block.

Hungary (Pannonian B.) Kadarkut op. by VERMILION (100%)