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TAG Oil Ltd, through its subsidiary company TAG Oil (NZ) Ltd, is offering up to 40% interest in the exploration permit PEP 51153, located in the Taranaki Basin. TAG currently operates the permit with 70% interest along with joint venture partner Melbana Energy. Melbana will maintain its position with 30% interest in the permit, but was open to offers to reduce its funding requirements prior to drilling a planned exploration well. The joint venture had already agreed to drill the Pukatea Prospect in the case of not attracting a partner in time. The well was completed in February 2018. The Pukatea 1 deviated oil exploration well spudded on 24 January 2018. On 26 February 2018 TAG reported that the well had reached a total depth of 3,100 m having failed to encounter the Tikorangi Limestone primary target, instead intersecting a thickened interval of basement rock. However, the well flowed fluids at a rate of 600 b/d during clean-up operations following the perforation of a 12.9 m interval of the secondary target Miocene Mount Messenger Formation.  The well demonstrated a stabilised flow rate of approximately 276 boe/d (74% oil) on a 24/64” choke during a 12-hour test. Testing subsequently continued using differing choke sizes, with all recovered oil being sold to the market at Brent pricing. TAG had until 23 February 2018 to drill the Pukatea 1 exploration well, which was estimated to cost USD 7.5 million. TAG was seeking to farm out around 40% to an interested party to share the costs in drilling and acquiring gravity data within the permit area. However, the well was drilled on schedule after Melbana provided full joint venture approval. PEP 51153 was awarded on 23 September 2008 to Kea Petroleum. Since, the area has been reduced by 60% to focus more on the two discoveries: Wingrove and Puka, and the Pukatea Prospect which lies updip from the Douglas 1 well and around 1,000 m below the Puka 1 discovery well. TAG entered the permit in 2016 by acquiring Kea Petroleum’s complete interest. After Kea entered liquidation, Melbana (then MEO) had pre-emptive rights over the interest but opted not to increase its holding. The permit is scheduled to expire on 23 September 2018. Pukatea (previously known as the Shannon Prospect), is an Oligocene play prospect adjacent to the Taranaki Fault. The trap is considered to be a plunging compressional fold at the leading edge of the fault caused by graben inversion.  Melbana reports that, pre-drill, the joint venture calculated the prospective resources attributable to the prospect to range from 1.07 to 34.33 MMboe, with a best case of 12.4 MMboe. The potential reservoir was considered conventional and lies directly below the Puka 1 well which made an oil discovery in 2012 in the Mt. Messenger Formation. The target was also updip from the Douglas 1 well (located in the north of the Wingrove field), which recorded oil shows within 145 m of the reservoir interval, within the Tikorangi section. Drilling was terminated at around 3,000 m depth after large fractures were encountered resulting in lost circulation. Pukatea was planned to be drilled to approximately 2,400 mTVD in the Tikorangi Limestone within a 4-way dip closure. TAG considered the main risks to be the fractured nature of the reservoir (as found in Douglas 1) and an effective seal. The geological chance of success was set at 19%. Pukatea 1 was drilled from the existing Puka production pad to minimize costs and provide a vertical path to target. In the case of success, a number of low development opportunities and routes to market exist from existing infrastructure, including the TAG operated Cheal production complex. TAG Oil is seeking for a second partner to join in the exploration programme for PEP 51153. Joint venture partner could also be interested in divesting its interest providing an attractive offer. Participants in the permit are: TAG Oil (NZ) Ltd (70% + operator) and MEO New Zealand Pty Ltd, a Melbana Energy subsidiary (30%).

New Zealand (Eastern Taranaki Mobile Belt (Taranaki B.)) Puka 1

Petro-Victory Energy in late November 2019 announced that the company had acquired a 50% working interest in three onshore oil fields in the Espirito Santo Basin for a total cost of US$ 4,686,223. Petrobras on 14 October 2019 announced the signing of a US$ 9.3 million contract with Imetame to divest the Lagoa Parda field complex which consists of the Lagoa Parda, Lagoa Parda Norte and Lagoa Piabanha fields. Petro-Victory paid 7.5% of this total now with the remaining balance due when the agreement is approved by the ANP which is expected in the first half of 2020.Petro-Victory made the deal in partnership with Imetame Energia based on successful contract negotiations in the Petrobras divestment process. Upon final approval from the ANP, Imetame will be the operator of the Lagoa Parda fields. The Lagoa Parda Fields were discovered by Petrobras in 1978. 139 wells have been drilled with a cumulative production totaling 19 MMbo to date. Production in 2019 is expected to average about 200 bo/d in the fields from just four producing wells. Petro-Victory and Imetame will execute a work program to increase production to 580 bo/d in the first year of operations. The initial work program includes bringing online 29 wells which have been suspended for mechanical reasons and no new drilling will be required to achieve that goal in the first year. However, based on existing seismic data and Petrobras operational data, Petro-Victory believes the Lagoa Parda fields contain significant high-impact low-risk exploration and development drilling opportunities.Petrobras is the current operator of the fields with 100% in each of them. In early March 2019, Petrobras entered the binding offer phase for the divestment of the Lagoa Parda cluster. Petrobras, on 9 October 2018, launched the first stage seeking non-binding offers for the cluster. The sale was the first to be launched after an ANP ruling giving Petrobras a deadline to report Round Zero concessions that are close to expiry and that Petrobras wants to keep with existing development plans. The sale of Petrobras assets is essential to resume onshore investments in Brazil and to diversify companies in the sector. Over the last decade onshore production has dropped 50% in Brazil. The fields have seen little activity in recent years. Petrobras drilled an exploration well there in 2013 filing and oil and gas show report with the ANP for the 6BRSA1167ES deeper pool wildcat in the southwestern part of Lagoa Parda Block. The well had a planned total depth of 2,438m and was believed to be targeting the Sao Mateus Formation. The Lagoa Parda Field is productive from the Urucutuca Formation.

Petro-Victory Energy in late November 2019 announced that the company had acquired a 50% working interest in three onshore oil fields in the Espirito Santo Basin for a total cost of US$4,6 MM.

By mid-February 2018, US-based operator Hess Corp (Hess) reportedly entered into an agreement with Aker Energy AS (Aker Energy), a 50-50 joint venture between Aker ASA (Aker) and TRG AS (TRG), to sell its interests in the company’s last operated permit in Sub-Saharan Africa, namely Deepwater Tano / Cape Three Points (DWT/CTP) Block. Indeed, on 5 February, Hess revealed that it decided not to develop its Ghanaian oil assets, in order to concentrate on its participation in the ExxonMobil-operated Stabroek block offshore Guyana and its US-based projects. The 2,024 sq km DWT/CTP Block is believed to hold 285 MMbbl of oil and 918 Bcf of gas. The main field (Pecan) is an elongated Turonian channel system, N-S oriented. Pecan is expected to be the main production hub of the permit, with several satellites to be tied in at later stages (Pecan North, Almond, Cob, Paradise). Aker Energy reported that the total cash consideration for the transaction was USD 100 million, consisting of USD 25 million payable upon closing of the transaction and a further USD 75 million payable upon approval of the Plan for Development and Operation (PDO) on the DWT/CTP block. The acquisition is subject to approval from relevant Ghanaian authorities and other customary closing conditions. The PDO is expected to be submitted in 2018 with anticipated first oil in 2021. So far, Hess operated the DWT/CTP Block with 40%, since it farmed out 38% working interest to Lukoil and 2% to local company FuelTrade in early 2015. State-run Ghana National Petroleum Corp (GNPC) held the remaining 20%.  

Ghana (Cote d'Ivoire B.) Cape Three Points

On 14 February 2020, KrisEnergy has entered a farm out agreement with a major international oil company for the transfer of its 100% interest in Block 115/09, situated in the northern Song Hong Basin, for a nominal cash consideration. The transfer of interest is subjected to a number of conditions including approvals from the relevant government authorities before 30 June 2020. The deal includes the mandatory work commitments comprising of acquisition and processing of at least 850 sq km 3D seismic and drilling of one exploration well. The main targets in the area are the Oligocene to Pliocene sandstones, ranging from deltaic and marginal marine to turbidite fan setting. An additional objective could be provided by the Miocene carbonates of the Tri Ton Group, which was targeted by 115-A 1X. Trapping mechanisms are expected to be tilted fault blocks, faulted anticlines, and stratigraphic trapping in the turbidite fans. Potential seals are present at various levels from Oligocene to Pliocene, with both regional and intraformational shales. High pressure conditions remain to be a key risk in this area. The nearest discovery is Ken Bau gas and condensate discovery in Block 114. The discovery encountered net thickness of more than 100 m in the Miocene Phu Chu sandstones. Kris Energy was awarded the sole operator of the block on 20 March 2014. Work commitment for the initial four-years term value of US$ 22.75 million includes reprocessing of 3,000 km of 2D seismic (completed), acquisition and processing of 850 sq km of 3D seismic and one exploration well. A two year extension period, if requested, effectively extends the well drilling until 20 March 2020. Farm-in opportunity was offered since December 2015. Background Information The work commitment for the initial four-year term value at US$22.75 million includes reprocessing of 3,000 km of 2D seismic (completed), acquisition and processing of at least 850 sq km of 3D seismic and one exploration well. A two year extension period, if requested, effectively extends the well drilling until 20 March 2020. KrisEnergy announced the award of Block 115/09 on 20 March 2014. The company was awarded 100% working interest and operatorship following negotiations between Vietnam Oil and Gas Group and KrisEnergy (Asia) ltd. Block 115/09 covers most of the area that used to be Block 115, awarded to International Petroleum Vietnam Ltd in May 1990. The operator drilled the first wildcat in the block in 1991, 115-A 1X. The well was drilled to basement, TD at 3,536 m. The main target for this well was the NW-SE trending Miocene carbonate of the Tri Ton Group. The well encountered a 310 m gas column in a large Miocene build-up with gas accumulation of 10-20 Tscfg in place, of which 90% is CO2. The primary target was not tested because analysis proved its high CO2 content. A DST was conducted from the Pliocene clastics that had gas indications, but no significant hydrocarbons were thought to have been recovered on the surface. International Petroleum Vietnam Ltd relinquished the block in 1995. The block lies just 25 km south of Ledong 28-1 discovery. The Ledong gas fields are in an area of maritime border dispute between China and Vietnam. Both sides are however optimistic that the rights dispute will be resolved in the near future. The Ledong 28-1 discovery represents a Pliocene Yinggehai Formation anticlinal trap within the central mud diapir structural belt of the Song Hong/Yinggehai Basin. The exploration target in the southern part of Song Hong Basin includes the Ledong Anticline belt that covers the Southern Buried Hill Draped Anticlinal Belt located between the No.1 Fault and the Qiongdongnan Basin. Another potential target are Miocene carbonate build-ups, with Miocene shales as source rocks.

KrisEnergy has agreed to transfer its 100% in block 115/09 to a unidentified major IOC for a nominal cash consideration.

Petrobras suspended with oil and gas shows the 3-SES-192 (3-BRSA-1367-SES) outpost in the BM-SEAL-004 block during mid-April 2019 at a yet unreported final total depth (TD).   The operator filed an oil show report with the ANP for the well on 17 April 2019.   Petrobras also issued a press release on 18 April indicating it concluded drilling operations on the well and confirms it was a successful confirmation of the Moita Bonita discovery.   Petrobras indicated it had 39 m of gas at approximately 5,227 m and oil in an unspecified deeper zone with a gross thickness of 24 m. The outpost was spudded on 13 March 2019.   The well had a proposed total depth (PTD) of 5,490 m.   The Late Cretaceous to Tertiary Calumbi Formation was the main objective. Petrobras utilized the “Petrobras 10000” D/S to drill the well in a water depth of 2,625 m.   The outpost is located in the south-eastern area of the block approximately 5.3 km north-west of the 1-BRSA-1088-SES discovery well for the Moita Bonita prospect located in the south-easterly adjoining SEAL-M-499 block.   Petrobras is operator of the BM-SEAL-004 contract with a 75% working interest and ONGC is the lone partner with 25% working interest.

Petrobras suspended with oil and gas shows the 3-SES-192 (3-BRSA-1367-SES) outpost in the BM-SEAL-004 block

Rosgeologiya (leader) and Uzbekgeofizika have signed a deal under which geological services will be available to refine the geological models, evaluate petroleum prospectivity and hydrocarbon potential in the Aral Sea and adjacent onshore using vintage G&G, geochemical data + basin modelling. Rosgeologiya has established Rosgeo Uzbekistan to implement the above.

Rosgeologiya (leader) and Uzbekgeofizika have signed a deal under which geological services will be available to refine the geological models, evaluate petroleum prospectivity and hydrocarbon potential in the Aral Sea and adjacent onshore using vintage G&G, geochemical data + basin modelling.

Midas block, Mid Mag, TD 3,261m, tested 100-600 b/d of 19 API oil from the target La Luna fm Galembo mb for 323 hours, further perfs + stimulation under consideration.

Colombia, Midas

Chevron Indonesia has sold its 25% participating interest in the South Natuna Sea Block ‘B’ PSC, located offshore West Natuna Basin, to a Singapore registered company, Prime Natuna Energy Pte Ltd (PNE), around mid-August 2017. SKK Migas also announced that Chevron’s crude cargo from the Belanak and Belida fields has been assigned to PNE effectively on 17 August 2017. Local media reported in early August 2017 that Indonesian company PT Bumi Hasta Mukti (BHM) was rumoured to be the potential buyer of Chevron’s 25% stake and the deal was expected to close in H2 2017. The company via its subsidiary PT Pertalahan Arnebatara Natuna (PAN) was awarded the Udang Natuna TAC, located in the offshore West Natuna Basin, on 7 August 2002. In late September 2016, Chevron was reported to continue the divestment process for its 25% interest in the PSC. Several companies, including PT Medco and Premier Oil, expressed interest. This opportunity was initially reported in early November 2015. The remaining 75% interest in the South Natuna Sea Block ‘B’ PSC is controlled by Medco which is also operator of the block. On 19 September 2016, Medco announced an agreement to acquire 40% operating interest in the block from ConocoPhillips. The agreement between Medco and ConocoPhillips also included the sale of operating interests in the West Natuna Transportation System (WNTS) and an onshore gas receiving facility in Singapore. The deal was completed in November 2016. Earlier reports also cited Saka Energi as one of the preferred bidders for ConocoPhillips’ interest. In March 2017, Medco also acquired an additional 35% interest from Inpex, for an estimated value of to be approximately USD 167 million. The block produced approximately 20,000 b/d of crude oil, 197 MMcf/d of sales gas and 6,000 b/d of LPG in 2016. Eight fields are currently producing in the block, with the latest field onstream being Belut South, in 2014. Medco commenced a new development drilling campaign in the block in mid-March 2017. Gas produced from the block is sold to Singapore through the West Natuna Transportation System, following a 22-year sales contract started in 2001, and to Petronas' Duyong gas facilities, under a 20-year contract since 2002. LPG is likewise sold to Indonesia through a contract with Pertamina. The block was initially awarded on 16 October 1968 and is set to expire on 16 October 2028.

Chevron has sold its 25% participating interest in the South Natuna Sea Block ‘B’ PSC, to a Singapore registered company, PNE (Prime Natuna Energy Pte Ltd) and no to Indonesian company PT Bumi Hasta Mukti (BHM).

The authorities have reportedly approved the guidelines to be implemented for the planned marginal fields round, still expected shortly. The DPR will issue the application form for the round which would run for a max. 6 months. 56 fields will be up for release, including 11 from revoked licences in early April. Application + processing fees will be due to the Treasury Single Account and signature bonuses to the Federation Account. Fees for data leasing, data evaluation, competent persons reports and field-specific reports will be due to the National Data Repository. The DPR-managed process will be standard, including the call for applications followed by pre-qualifications initially.

The authorities have reportedly approved the guidelines to be implemented for the planned marginal fields round, still expected shortly. The DPR will issue the application form for the round which would run for a max. 6 months. 56 fields will be up for release, including 11 from revoked licences in early April. Application + processing fees will be due to the Treasury Single Account and signature bonuses to the Federation Account. Fees for data leasing, data evaluation, competent persons reports and field-specific reports will be due to the National Data Repository. The DPR-managed process will be standard, including the call for applications followed by pre-qualifications initially.

Orlen secured sole rights to the 1/2020/L Koszalin – Polanów contract , 1,111 sq km SW of Gdansk in the Danish-Polish Marginal Trough in N. Poland in Feb '20. The award emanates from the country’s 2018 tender call (round 2).

ORLEN was awarded the 1/2020/L Koszalin – Polanów (1111km²) and 2/2020/L Dębrzno – Człuchów contract SW of Gdansk in the Danish-Polish Marginal Trough.

On 21 October 2019, Panoro Energy ASA (Panoro) announced it has reached an agreement with PetroNor E&P Ltd (PetroNor) to sell its 12.19% in the OML 113 with effect as of 30 June 2019. The transaction includes the payment of US$ 10 million (fixed value) in PetroNor shares and a contingent consideration of up to US$ 25 million based on future gas production. The OML 113 contains the Aje field that currently produces around 3,000 bo/d from Turonian and Cenomanian levels. It was discovered in 1996 and brought on stream twenty years later in May 2016. The Aje field holds primarily gas and condensate in Turonian sands overlying a thin oil rim, oil is also present in deeper Cenomanian reservoirs. Partners agreed to develop the field under a multiphases approach with the Cenomanian oil to be produced first and the Turonian gas in a second time. But shortly after the first oil a production decline was experienced in the Cenomanian oil reservoirs. It forced the partners to draw up a field development plan (FDP) to accelerate the development of the Turonian gas level. The FDP was submitted to the Nigerian authorities during 2018 while in the meantime the partners completed a Turonian oil well to maintain a substantial production rate of the field. Yinka Folawiyo Petroleum Co. Ltd operates OML 113 with a 41.88% interest. Partners are NewAge with 24.06%, Energy Equity Resources (EER) with 16.88%, PetroNor E&P Ltd (PetroNor) with 12.19%, and ADM Energy with 5%.  The block OML 113 is located in shallow to deep waters of the Benin Embayment, western offshore Nigeria. The block covers an area of 911 sq km and water depths range from less than 100 m to approximately 1,500 m.

Pan-Petroleum (Panoro) has reportedly agreed to sell its 12,2% WI in OML 113 (1593²km) licence to PetroNor for US$10 MM.

On 12 March 2019, the Ministry for Natural Resources published a list of exploratory licenses available for investors without auctions. The list includes four blocks covering 8,645 sq km in Irkutsk Oblast (Eastern Siberia). Applications must be submitted by 22 April 2019. If any block receives more than one valid application, the block will be withdrawn from the list and could be offered through an auction. Applications must be sent to Irkutsknedra, 664025, Irkutsk, Rossiyskaya Str., 17. The Biryusinskiy block covers 2,524 sq km in the Angara-Yenisey Basin. Its hydrocarbon resources are estimated at 37 MMbbl of oil and 411 Bcf of gas. The Baykalskiy Severnyy block covers 1,172 sq km in the Nepa-Botuoba Basin. Its hydrocarbon resources are estimated at 24 MMbbl of oil and 342 Bcf of gas. The Tareyskiy block covers 2,416 sq km in the Angara-Yenisey Basin. Its hydrocarbon resources are estimated at 31 MMbbl of oil and 377 Bcf of gas. The Udinskiy block covers 2,533 sq km in the Angara-Yenisey Basin. Its hydrocarbon resources are estimated at 685 Bcf of gas and 15 MMbbl of condensate.

On 12 March 2019, the Ministry for Natural Resources published a list of exploratory licenses available for investors without auctions. The list includes four blocks covering 8,645 sq km in Irkutsk Oblast (Eastern Siberia). Applications must be submitted by 22 April 2019.

In late January 2020 industry sources indicated that the Guinea authorities are currently working on delimiting 14 new exploration acreage blocks onshore. The block limits will be finalized using an aeromagnetic survey. It is assumed that the authorities decided to create new acreage blocks following the relinquishment of blocks 1 and 2 by Simba Energy who was the only onshore right-holder. The Bove Basin is a high-risk frontier area, with no seismic and drilling exploration activity undertaken so far. The objectives are possibly limited to the Paleozoic sequence. Possible source rock are present in the Silurian series with the main risk being overmature. There are no proven reservoirs. Potential reservoirs are present in clastic sequences of Cambrian-Ordovician and Devonian ages. According to Simba Energy, highlights of the potential of the Bove Basin include the presence of oil seeps, large accumulations of bio-degraded heavy oil at surface, along with light oil staining in historical core and samples. A detailed laboratory analysis of samples from two wells carried out in 1989 by Beicip (France) reportedly indicated a level of maturity as mature to over mature and a source that is likely oil prone. Simba Energy states that the Bove Basin has three possible reservoir systems with fair to good reservoir parameters in both clastic sediments and carbonates. Texas Geophysical Company carried out a gravity and magnetometer survey over the entire basin in 1972. Results of the survey suggest that sediments are present up to a depth of 4,000m and numerous anomalies were identified. In addition to the Bove Basin which is the largest, there are four other onshore basins in Guinea: Youkounkoun, Komba, Kolente and Madina-Kouta. They are believed to be Paleozoic intra-cratonic basins like the Bove Basin but they are located more inland and are even less explored.

In late January 2020 industry sources indicated that the Guinea authorities are currently working on delimiting 14 new exploration acreage blocks onshore. The block limits will be finalized using an aeromagnetic survey.

The DOE has announced plans to award acreage in 2020 via a competitive system via a new PSA template, which will vary with differing conditions, both geological (deep water vs. near shore) and financial. The legislation overhaul with the new PSAs should be in place by March ’19. More from GEPS.

The DOE has announced plans to award acreage in 2020 via a competitive system via a new PSA template, which will vary with differing conditions, both geological (deep water vs. near shore) and financial. The legislation overhaul with the new PSAs should be in place by March ’19.

Vintage Energy Ltd reported on 3 August 2018 that it had signed a sale and purchase agreement (SPA) with Beach Energy Ltd, to acquire interest in exploration permit EP 126, located in the Bonaparte Basin.  Vintage Energy will be acquiring 100% interest and operatorship in the permit. The deal remains subject to a number of relevant authority approvals, which were reported to remain pending as of late November 2018. The companies entered a heads of agreement for the deal in June 2018.  Under the terms of the SPA Vintage Energy will take on all permit obligations, including the requirement to abandon the Cullen 1 well, which was drilled in the permit. The permit was awarded to Territory Oil and Gas Pty Ltd in June 2011.  Beach first acquired interest in October 2011, taking 90% interest. After a number of additional interest changes, Beach acquired full interest in the permit in July 2015. During the permit’s validity the Cullen 1 well was drilled, in 2014. It was targeting both conventional and unconventional gas potential.  Target units included the shale and tight sands of the Carboniferous Milligans Formation, Carboniferous Bonaparte Formation and Upper Devonian Langfield Group.  Beach reported that 1,000 m of limestone and interbedded shales had been encountered, with elevated gas readings and natural fractures observed.  In addition, 1,600 m of dark marine shale was encountered. The well was suspended pending testing. Beach had been offering a farm-in opportunity in the permit. Beach was offering a negotiable farm-in opportunity, with the potential farminee to participate in part of the work programme associated with the evaluation of the Cullen 1 well.  A staged farm-in opportunity was available, with a partner to initially carry Beach through an extended production test of the Cullen 1 carbonate play for permit entry.  Future testing would then be undertaken on the shale gas interval of the well. EP 126, which covers an area of 6,740 sq km, was awarded on 15 June 2011. Once the deal is complete, Vintage Energy Pty Ltd will hold 100% interest and operatorship of the permit.

Vintage Energy had signed a SPA with Beach Energy, to acquire interest in exploration permit EP 126.

On 7 November 2018, the consortium of Chevron with 40% working interest, Repsol with 40%, and Wintershall with 20%, was granted an official award for the S-M-764 block in the offshore Santos Basin through the ANP Round 15. On 29 March 2018, the consortium was granted a preliminary award for the block. For the S-M-764 block the consortium offered a bonus of USD 39.86 million and 225 work units.   There were no other bids for the block.

Consortium of Chevron with 40% working interest, Repsol with 40%, and Wintershall with 20%, was granted an official award for the S-M-764 block in the offshore Santos Basin through the ANP Round 15.

The Kabakovskiy block will be up for grabs on 19 Jun ’18 in the Bashkortostan Republic, Volga-Ural. The 1,489-sq km tract is in the Kamsko-Belskaya Depression and encompasses 14 prospects. Starting price USD 0.94 MM. Applications by 15 May ’18. Contact: Bashnedra, email [email protected].

The Kabakovskiy block will be up for grabs on 19 Jun ’18 in the Bashkortostan Republic, Volga-Ural. The 1,489-sq km tract is in the Kamsko-Belskaya Depression and encompasses 14 prospects. Starting price USD 0.94 MM. Applications by 15 May ’18.

UKOG has agreed to acquire Gunsynd and Primorus Investments’ combined 7% in Horse Hill Devts Ltd, who operates the Horse Hill-1 discovery in PEDL137 + 246 in Sussex. UKOG will hold a majority 56.9% in HHDL, equating to a 36.985% licence interest, now the largest single holder. The well is currently undergoing a LT test.

UKOG has agreed to acquire Gunsynd and Primorus Investments’ combined 7% in Horse Hill Devts Ltd, who operates the Horse Hill-1 discovery in PEDL137 + 246. UKOG will hold a majority 56,9% in HHDL, equating to a 36,985% licence interest, now the largest single holder.

N. sector of the Abana Complex in C-23 (Mokoko-Abana) block, plugged late Nov ’18 on tech. probs at 2,789m in sidetrack.  4 oil-bearing intvs nonetheless encountered (S9A, S1A, S5C + S5D between 2,090-3,570m – pilot hole TD 3,650m), COSL Seeker JU.

Cameroon (Niger Delta) Abana Complex

Red Sky Energy has a farmout agreement with Santos for the latter to acquire an 80% operating stake in the Innamincka Dome assets in the Cooper-Eromanga.  Involved are PRL 14, 17, 18, 180, 181 + 182, total 382 sq km.  This is subject to relevant authority approvals.

Red Sky Energy has a farmout agreement with Santos for the latter to acquire an 80% operating stake in the Innamincka Dome assets. Involved are PRL 14, 17, 18, 180, 181 + 182, total 382km².

MOL used the “Deepsea Bergen” S/S to drill an exploration well on its Evra and Iving prospects in PL 820 S located between the Jette and Ringhorne fields. 25/8-19 S was spudded on 2 November 2019 and was drilled to TD at 2,760 m. Pre-drill potential recoverable reserves are 181 MMboe (source: Lundin, October 2019). Evra is an injectite prospect, with remobilised Paleocene Hermod Sandstones expected in the Eocene Hordaland Group. Two sand bodies were expected – one at 1,783 m and the other at 2,023 m. The main objective for the Iving prospect (four-way closure at the BCU) was the Lower Jurassic Statfjord Formation at 2,207 m. There were also further targets in the Paleocene Ty Formation, the Triassic Skagerrak Formation and the Basement. The drilling plan called for a sidetrack (targeting Evra only with a planned TD of 2,104 m / 2,000 m TVD) if the well made a discovery at Evra and on 31 December 2019 MOL kicked off 25/8-19 A which is designated as an appraisal, indicating that a discovery has, indeed, been made. PL 820 S contains the 2001 dry hole 25/8-13 which was drilled by Esso. Good reservoir sands were present in both the Ty Formation and the Statfjord Formation, although both were water-bearing. MOL Norge AS operates PL 820 S with a 40% interest. It is partnered by Lundin Norway AS (40%), Pandion Energy AS (10%) and Wintershall Dea Norge AS (10%).

025/08-19 S (Evra/Ivring) expl. (MOL 40% op, Lundin 40%, Pandion 10%, Wintershall Dea10%),1st well in PL 820 S, location between Jette + Ringhorne fields, WD=125m, industry rumours suggest a positive outcome.

As of 19 October 2018, GeoPark Ltd is currently seeking partners on Block 64 located in northern Peru in the Maranon Basin along the border with Ecuador. According to the operator two wells, the Situche Central 2X and 3XST, tested a combined rate of 7,500 bo/d of light oil. GeoPark has submitted an environmental Impact study (EIS) on a field development plan for the Situche Central Field to the Senace for evaluation and approval and a public hearing is scheduled for the Q4 2018. The company is said to be looking for capitol to begin development once approvals have been granted. GeoPark won’t start recuperating cost from its partner Petroperu until the field begins producing when back cost will be deducted from its share of production. According to the company the Situche Field contains 80 MMbo (36 deg API) with an upside potential of 211 MMbo gross. There has been 2,700 km of 2D seismic along with 460 sq km of 3D seismic acquired on the block. A regional pipeline also is accedable on the block allowing for transportation of the crude to markit. The 7,634.54 sq km Block 64 was originally awarded to Arco in April 1996. At the time of award, the block carried a minimum work expenditure requirement of USD 44,300,000. The blocks original size was 9,537.90 sq km but was reduced to the current size of 7,634.54 sq km in May 2006. Arco and Occidental were originally 50/50 partners in the block in 1996. Arco sold a 25% working interest to Repsol in June 19999, later that same year Arco sold its remaining 25% interest to Burlington Resources. The partnership remained in this configuration until April 2004 when Amerada Hess and Talisman Energy acquired the interest of Repsol and Burlington. In 2007 Occidental sold its 50% interest to Hess and Talisman creating a 50/50 partnership with Talisman as operator. In May 2013 the block on the verge of being relinquished was turned over to Petroperu who then brought in GeoPark Ltd in December 2016 creating a new partnership of GeoPark 75% and Petroperu 25 %. The contract has had several periods of being placed in Force Majeure in which the most recent time of entering that stage was January 2014.

Peru, Block 64

Cayar Profond block, MSGBC deepwaters, northern offshore, location 9km south of the discovery, 30m net gas pay in the Cenomanian target, partner Kosmos comments the Yakaar-Teranga resource base is world-scale and has the potential to support an LNG project. Devt will be phased, Phase 1 providing domestic gas and data. Valaris DS-12. Kosmos-BP Senegal (op), partners BP + Petrosen.

Senegal, not found

Further to DEA 7 Dec ’18 : PRL 146, Cooper Eromanga, P&A oil shows at TD 2,252m on 3 Dec ’18. Senex (op), partner Beach.

Voodoo 1 (Senex 60% + Op. Beach Energy 40%) in PRL 146 block, P&A oil shows.

South Alam El Shawish block. Abu Gharadiq Basin, W. Desert, compl. o&g at TD 2,179m (Kharita) in late Aug ’18, ST 10 rig. Targets Abu Roash G + Bahariya.

Egypt, Abu Gharadiq (Dev)

KP has transferred a 35% interest to PEL in the 2,213-sq km Paharpur 3170-5 EL, Indus onshore, retaining 60.07% in the process effective 29 Nov ‘18.  Partnership now KP (op), PPL, Govt Holdngs + Khyber Pakhtunkhwa O&G.

KP has transferred a 35% (->60,07% op, GHPL 2,5% + KPOGCL O&G 2,43%) interest to PEL in Paharpur 3170-5 EL block.

The state company ONHYM published a list of 30 open blocks located in various geological domains including explored areas with proven hydrocarbon potential and prospective areas still under-explored: Morocco - Open blocks Block Name Location Area (sq km) Asilah Tanger-Tetouan 2275.31 Boudenib Meknes-Tafilalet 27633.59 Boujdour Maritime North Atlantic Ocean 33354.63 Boujdour Offshore I North Atlantic Ocean 11094.2 Boujdour Offshore II North Atlantic Ocean 17474.61 Casablanca Offshore North Atlantic Ocean 3038.24 Dakhla Atlantique North Atlantic Ocean 104063.6 El Jadidad Offshore North Atlantic Ocean 6665.75 El Kansera Rabat-Sale-Zemmour-Zaer 2586.17 Foum Ognit Offshore North Atlantic Ocean 7954.8 Gharb Offshore Nord North Atlantic Ocean 9761.45 Gharb Offshore Sud North Atlantic Ocean 4470.17 Hassi Berkane Oriental 5120.75 Ifni Deep Offshore North Atlantic Ocean 14119.67 Lemsid Laayoune-Boujdour-Sakia El Hamra 57015.12 Loukos Offshore North Atlantic Ocean 1888.58 Mazagan Offshore North Atlantic Ocean 11101.42 Mir Left Offshore North Atlantic Ocean 3476.07 Moulay Bouchta Taza-Al Hoceima-Taounate 4228.68 Ouarzazate Souss-Massa-Draa 4109.44 Ouezzane Tanger-Tetouan 4342.22 Rabat Deep Offshore North Atlantic Ocean 9382.17 Safi Deep Offshore North Atlantic Ocean 9767.94 Safi Offshore Nord North Atlantic Ocean 6250.44 Safi Offshore Sud North Atlantic Ocean 5943.69 Sakia El Hamra Laayoune-Boujdour-Sakia El Hamra 13061.46 Souss Souss-Massa-Draa 6250.11 Tadla-Haouz Tadla-Azilal 21935.16 Taounate Taza-Al Hoceima-Taounate 6771.62 Zag Guelmim-Es Semara 65448.12   The Boujdour Offshore and Boujdour Onshore blocks are under negotiation. Interested parties may contact: ONHYM, 5 Avenue Moulay Hassan, 10050 Rabat - Morocco - Tel 00 212 537 23 9898 - Fax: 00 212 537 70 94 email: [email protected]

Morocco (Aaiun-Tarfaya B.) Boujdour Offshore op. by OTHERS (100%)

Qadirpur D&PL, Middle Indus onshore, TD 1,454m, P&A late Apr ‘19 after inconclusive testing (understood dry), Hilong rig 17. Note: a Qadirpur Deep-1 nfw was drilled in mid-2006 to TD ca. 4,900m, also by OGDC.

Qadirpur Deep X 1 (OGDCL 75% op. KUFPEC 13,25%, PPL 7%, Premier Oil 4,75%) in Qadirpur D&PL block, P&A, the well was targeting Cretaceous exploratory targets under the producing Eocene Qadirpur gas field and after carrying out testing. It is understood that the well was unsuccessful in finding the hydrocarbons..

In late April 2018, it was reported that Lebanon’s Minister of Energy & Water has requested that the Lebanese Petroleum Administration (LPA) commence preparations for a potential second offshore licensing round. The Council of Ministers subsequently approved the recommendations of the LPA on 17 May 2018. This second offshore licensing round is expected to be launched in early 2019 and will extend over a twelve month period. A pre-qualification round will be held in the first quarter of 2019 with submission of bids expected in May to October 2019. Lebanon’s First Offshore Licensing Round closed on 12 October 2017. A consortium of Total S.A., Eni International BV and JSC Novatek were awarded two blocks, Block 4 and Block 9. No other bids were made. The Lebanese Government was offering five offshore blocks (1,4,8,9 and 10) for exploration and production. The 10 designated offshore Lebanese blocks cover the entire offshore area with areas ranging from approximately 1,260 sq km to 2,380 sq km.   Tentative Second Licensing Round Timeline     Dates Official Launching of Licensing Round and Announcement of Open Blocks Early 2019 Submission of Prequalification Applications Jan 2019  -  End April 2019 Declaration of Prequalification Results May 2019 Submission of Bids May 2019  -  End Oct 2019 Evaluation of Bids and CoM approval Nov 2019 Signature of EPAs Dec 2019   Meeting the LPA     Event Location Dates ONS Stavanger – Norway 27-31 Aug 2018 Gastech Barcelona – Spain 17-20 Sept 2018 Adipec Abu Dhabi – UAE 12-15 Nov 2018 Petex London – UK 27-29 Nov 2018

Lebanon, Block 9

Hellenic and partner Edison are each looking to farmout the Gulf of Patraikos (West) block ahead of committed explo drilling in late 2019 on the Echo prospect. Gulf of Patraikos (West) covers 1,892 sq km NW of the Peloponnese in WD 100-300m. Contact Yannis Grigoriou, [email protected], or Georgianna Petrolia, [email protected].

Hellenic and partner Edison are each looking to farmout the Gulf of Patraikos (West) block ahead of committed explo drilling in late 2019 on the Echo prospect. Gulf of Patraikos (West) covers 1,892 sq km NW of the Peloponnese in WD 100-300m.

ENEVA SA suspended with gas shows the 1-ENV-BL69E-MA (1-ENV-004-MA) new-field wildcat (NFW) in the PN-T-069 block during mid-June 2019 at an as yet unreported final total depth (TD).  The operator filed a gas show report with the ANP for the well on 11 June 2019. The NFW was spudded on 18 May 2019.   The NFW had a proposed total depth (PTD) of 1,698 m. The Devonian Cabecas Formation and the Mississippian Poti Formation were the primary targets.    The NFW is located in the north-central area of the block approximately 42.4 north-east of the 1-OGX-101-MA plugged and abandoned in 2012 by operator OGX. ENEVA SA has 100% working interest in the ANP Round 13, 3,066.97 sq km, PN-T-069 contract awarded on 23 December 2015.

1-ENV-BL69E-MA (1-ENV-004-MA) NFW (Eneva 100%) in the PN-T-069 block, suspended with gas shows.

Noble Energy Inc. has agreed to sell its deepwater U.S. Gulf of Mexico assets to Fieldwood Energy LLC for USD 710 million. This deal gives Fieldwood a position in the deepwater Gulf of Mexico. The company’s current holdings are primarily found on the shallow water (<400 m) shelf areas of the Gulf. Under the terms of the deal, which is expected to close during the Q2 2018, Noble will receive cash proceeds of USD 480 million from Fieldwood who will also assume Noble’s USD 230 million abandonment obligations associated with the sold assets. A cumulative contingent sum of up to USD 100 million is payable to Noble upon closing the transaction, which has an effective date of 1 January 2018. As part of the 15 February 2018 press release, David L. Stover, Noble Energy's Chairman, President and CEO, remarked, "The sale of our Gulf of Mexico business represents the last major step in our portfolio transformation. This has been done to focus our go-forward efforts on those assets that will rapidly grow our cash flows and margins, primarily the U.S. onshore business and the Eastern Mediterranean.” He added, “Going forward, we are concentrating the Company's exploration capabilities on higher-impact opportunities that can drive substantial long-term value creation." According to the release, the divestment includes Noble’s interest in six producing fields and all undeveloped leases. Below are two tables, one listing Noble’s 10 producing properties and two discoveries while the other compiles the 60 valid leases in the deepwater Gulf of Mexico in which Noble holds a working interest either as the operator or as a participant. Half of these leases are found in the Mississippi Canyon area. Noble groups some of their producing properties under collective field area names such as Galapagos for three Mississippi Canyon fields. Noble DWGOM Assets       Field Area/Block Operator Status W.I. (%) Katmai GC-40 Noble Discovery 50 Ticonderoga GC-768 Anadarko Producing 50 Santa Cruz* MC-519 Noble Producing 23 Santiago* MC-519 Noble Producing 23 Isabela* MC-562 BP Producing 33 Big Bend MC-698 Noble Producing 54 Troubadour MC-699 Noble Discovery 60 Dantzler MC-782 Noble Producing 45 Gunflint MC-948 Noble Producing 31 Neptune/Thor VK-826 Noble Shut-in 100 VK-917 VK-917 Noble Producing 85 Swordfish VK-962 Noble Producing 85 * Galapagos complex Source: IHS Markit © 2018 IHS Markit   Noble DWGOM Leases     Lease Area/Block Lease Area/Block G32586 AT 450   G31485 MC 294 G32587 AT 451 G34434 MC 297 G35024 AT 845 G31490 MC 338 G35025 AT 846 G32316 MC 339 G33873 AT 847 G35825 MC 474 G33874 AT 848 G35828 MC 518 G35364 DC 661 G27278 MC 519 G34878 EW 1009 G19966 MC 562 G34879 EW 1010 G28021 MC 697 G34880 EW 1011 G28022 MC 698 G34966 GC 39 G33169 MC 699 G34536 GC 40 G33753 MC 700 G34537 GC 41 G35344 MC 701 G32484 GC 245 G33755 MC 738 G21811 GC 679 G32343 MC 742 G21817 GC 768 G33757 MC 782 G33260 GC 774 G33758 MC 788 G35488 HE 96 G32347 MC 789 G35489 HE 278 G33759 MC 832 G35490 HE 0279 G32351 MC 833 G35476 LL 896 G33182 MC 904 G35477 LL 897 G28030 MC 948 G35478 LL 898 G32363 MC 949 G35479 LL 940 G24133 MC 992 G35480 LL 941 G24134 MC 993 G35311 MC 80 G06888 VK 826 G34425 MC 123 G33133 VK 873 G34427 MC 163 G15441 VK 917 G34428 MC 171 G15445 VK 962 G34429 MC 172 G32664 WR 113 Source: IHS Markit © 2018 IHS Markit  

United States (Sigsbee Sub-basin (DWGoM B.)) Ticonderoga

On 14 February 2020, the consortium of ExxonMobil, Enauta, and Murphy were granted final awards for the SEAL-M-505, SEAL-M-575, and SEAL-M-637 blocks in the deep-water offshore Sergipe-Alagoas Basin. On 10 September 2019, the consortium of ExxonMobil, Enauta, and Murphy bid on and were granted preliminary awards for the SEAL-M-505, SEAL-M-575, and SEAL-M-637 blocks in the deep-water offshore Sergipe-Alagoas Basin. There were no other bids for the blocks. The consortium now has a total of nine contiguous blocks in the deep-water play in this area of the basin. 1st Open Door Bid Round - Preliminary Results - ExxonMobil - 9-10-2019 Basin Block Area sq km Royalties % Minimum Work Units Bid_Work Units Tot_WU_Bid_Value USD Min Bonus USD Bonus Bid USD Win_Consort-Comp Sergipe-Alagoas SEAL-M-505 754.60 10 176 207 7,866,000 562,916.25 675,131 ExxonMobil (50%), Enauta (30%), Murphy (20%) Sergipe-Alagoas SEAL-M-575 753.95 10 215 200 7,600,000 647,339.07 777,649 ExxonMobil (50%), Enauta (30%), Murphy (20%) Sergipe-Alagoas SEAL-M-637 753.28 10 182 237 9,006,000 424,526.17 510,164 ExxonMobil (50%), Enauta (30%), Murphy (20%) Totals Offshore 2,262 24,472,000 1,962,944 Source: IHS Markit                 © 2019 IHS Markit

Exxon Mobil Corp - Sergipe-Alagoas Basin - SEAL-M-505, SEAL-M-575, and SEAL-M-637 blocks - final awards from 1st Open Door Bid Round

RockRose Energy announced on 3 August 2017 that it had agreed a sale and purchase agreement to acquire the entire issued share capital of Sojitz Energy Project Limited for a consideration of USD 2.5 million. The company will receive USD 1.7 million at completion of the deal to reflect an effective economic date for the transaction of 1 January 2016. The deal completed on 22 December 2017. The assets involved in the deal include a 15% interest in the Tors field unit area which includes the Kilmar (P683) and Garrow (P1034) fields which are linked to the Trent field. A 7.5% interest in the Grove field unit area (P083 and P901) and a 10% interest in the Seven Seas field (P1354). Sojitz Energy Project Limited also held a 13.5% interest in the Gryphon field but this is understood to not be part of the deal and will likely be awarded to a different Sojitz subsidiary. RockRose’s strategy is to build a portfolio of mature producing assets with a view to extend the field life giving the company access to significant tax losses. The recently established company has undertaken deals with Egerton Energy, announced in March 2017, to acquire Egerton’s interest in the Galahad and Mordred fields in the Southern North Sea and also agreed a deal with Maersk in December 2016 to acquire its interest in the Scott and Telford fields.

RockRose Energy has agreed to acquire entire issued share capital of Sojitz Energy. The assets involved in the deal include a 15% interest in the Tors field unit area which includes the Kilmar (P683) and Garrow (P1034) fields which are linked to the Trent field. A 7,5% interest in the Grove field unit area (P083 and P901) and a 10% interest in the Seven Seas field (P1354).

PL 931, WD 392m, PTD 944m, target gas, abandoned 11 Feb ’19, results expected shortly, Transocean Arctic SS. To be followed by 25/1-13 (Balcom) around 20 Feb ’19 in PL 871. Wellesley (op), partner DNO.

035/04-02 (Songesand) (Wellesley Petr. 60% op. DNO 40%) in PL 931 block, WD=392m, PTD=944m, target gas, P&A results expected shortly.

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

030/06-31 S (Helleneset) expl E. flank of Oseberg in PL 053, TMD=2,852m. Target M. Jurassic, Equinor 49,3% (op), Petoro 33,6%, Total 14,7%+ COP 2,4%). Results n/a yet.

N-C part of AE-0052-2M-Mezcalapa-02 entitlement, Comalcalco (Sureste) Basin in Tabasco, P&A dry at TD 2,580m mid-Jan ’19. Target Miocene.

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

Bass Oil is looking to expand in South Sumatra, looking at near-production assets, particularly near existing production facilities. So far 3 such opportunities have been identified for due diligence. Bass Oil has been involved until now in the Tangai Sukananti KSO.

Bass Oil is looking to expand in South Sumatra, looking at near-production assets, particularly near existing production facilities. So far 3 such opportunities have been identified for due diligence. Bass Oil has been involved until now in the Tangai Sukananti KSO.

PEMEX plugged and abandoned dry the Ketsin 1EXP new-field wildcat (NFW) in the AE-0079 block in the Deep Water Gulf of Mexico Basin on 14 August 2018 after reaching a total depth (TD) of 7,430 m.  The NFW was spudded on 24 May 2018.   The NFW had a proposed total depth (PTD) of 7,430 m and the Eocene Wilcox Formation was the primary objective.   PEMEX utilized the “La Muralla IV” S/S to drill the well in a water depth of 2,425 m. The well is located in the north central part of the most westerly area of the block about 17.8 km west of the Melanocetus 1 that was plugged and abandoned dry by PEMEX in January 2016.  PEMEX had its modified exploration plans approved on 10 October 2017 for the block which included the drilling of one firm commitment well. The Ketsin prospect had estimated prospective resources of 248 MMboe.  The drilling cost for the well was estimated to be USD 99.29 million at 1USD = 18.3 MXN and the completion cost was estimated to be USD 8.47 million. The CNH issued a permit to drill the well on 27 February 2018. PEMEX plugged and abandoned with oil and gas shows the Melanocetus 1 new-field wildcat (NFW) in the AE-0079 block in the Deep Water Gulf of Mexico Basin on 31 January 2016 at a final total depth (TD) of 4,920 m.  The CNH reported the well as a non-commercial oil producer after some type of testing took place in the interval 4,485 m to 4,530 m.  It is assumed that some oil and gas shows were encountered for testing to take place.  The NFW was spudded on 1 November 2015. The well had a proposed total depth (PTD) of 5,030 m. The Oligocene Formation was the primary objective in a northwest southeast oriented structural objective. The “Centenario” S/S drilled the well in a water depth of 2,830 m. SENER granted the AE-0079-2M-Cinturon Plegado Perdido-05 Entitlement to PEMEX 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 634.32 sq km.

PEMEX plugged and abandoned dry the Ketsin 1EXP new-field wildcat (NFW) in the AE-0079 block in the Deep Water Gulf of Mexico Basin

Gazpromneft has won an auction for 6 blocks in the Khanty-Mansiysk AO, W. Siberia, namely Karabashsky 17, 18, 19, 25, 26 + 27 for USD 10.3 MM. Lukoil was the competing applicant, but secured rights to the North-Yagunsky unit for USD 3.2 MM.

Gazpromneft has won an auction for 6 blocks in the Khanty-Mansiysk AO, W. Siberia, namely Karabashsky 17, 18, 19, 25, 26 + 27 for USD 10.3 MM. Lukoil was the competing applicant, but secured rights to the North-Yagunsky unit for USD 3.2 MM

Angus has signed for the purchase of Doriemus's 20% interest in the Lidsey oilfield in PL 241, 5 sq km in Hampshire, deal to be approved by the OGA. Partnership to become Angus (op), Terrain Egy, Brockham Capital + UKOG.

Angus has signed for the purchase of Doriemus's 20% interest in the Lidsey oilfield in PL 241, 5 sq km in Hampshire, deal to be approved by the OGA. Partnership to become Angus (op), Terrain Egy, Brockham Capital + UKOG.

On November 22, Hocol Petroleum signed an agreement with Chevron Corp. for a 43% interest and operatorship of the Chuchupa-Ballenas gas fields located in the Guajira area of northern Colombia. Details of the transaction were not disclosed, and the deal is subject to Agencia Nacional de Hidrocarburos (ANH) approvals. Fields operations are currently run under the Guajira Association Contract split Ecopetrol and Chevron at 57% and 43% interest, respectively.

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

On 13 November 2017 Hague and London Oil (HALO) reported that the takeover of non-operated offshore licences from Tullow was completed. Consequently HALO is a producer of more than 2,500 boe/d, having 2P reserves in excess of 12 MMboe and more than 19 MMboe in contingent resource The table below shows Tullow’s assets and its participation interest: Asset Operator Tullow’s participation E10 ENGIE 30% E11 ENGIE 30% E14 ENGIE 30% E15c ENGIE 25% E15a Wintershall 4.69% E15b Wintershall 21.12% E18a Wintershall 17.6% F13a Wintershall 4.69% J9 NAM 9.95% K8 NAM 9.95% K11 NAM 9.95% K7 NAM 9.95% K14 NAM 9.95% K15 NAM 9.95% L13 NAM 9.95%   HALO was formed in 2012 and combined with Wessex Oil in 2014. The company’s portfolio is so far comprised of assets in the United Kingdom, Western Sahara, French Guyana and the Scattered Islands.  

Netherlands, J9

Angus Energy Plc announced on 22 January 2018 that it has agreed to acquire a 25% interest in PEDL 244 which contains the Balcombe discovery from Cuadrilla subsidiary Cuadrilla Balcombe Limited. Under the terms of the deal Angus has assumed operatorship of the licence and the company will take forward the fully approved well test programme of the Balcombe-2Z horizontal well. On 9 May 2018 it was announced that following OGA approval from late April 2018, Angus has paid GBP 2 million for the deal. If a successful well test programme is completed, Angus will assume the associated costs of a Field Development Plan (FDP) submission to the OGA. On 9 January 2018 Cuadrilla announced that it had received approval from West Sussex County Council’s Planning Committee for the company to flow test and monitor its Balcombe-2Z well in PEDL 244. The company initially submitted an application to undertake this work in 2014. The well requires no hydraulic fracturing due to the rock being naturally fractured. The planning permission runs out in 2021 where Cuadrilla will have needed to had tested, plugged and abandoned the well and restored the site to a suitable condition. Cuadrilla spudded the appraisal well, Balcombe-2 on 2 August 2013 after several delays on the site due to protesters. The well had a planned vertical depth of 3,000 ft (914 m) with potential to kick-off a 2,500 ft (762 m) horizontal sidetrack. Cuadrilla used the same site that Conoco used in 1986 to drill the Balcombe-1 well. Cuadrilla had no plans to frack the well but initially it was understood that it will use hydrochloric acid to stimulate the reservoir which is Middle Jurassic (Great Oolite) Limestone. On 16 August 2013 operations were temporarily suspended at the site following police advice regarding potential disruptions from protesters (resumed 22 August). On 5 September 2013 the company kicked-off sidetrack Balcombe-2Z. On 23 September 2013 Cuadrilla announced that operations had been completed at the well which encountered oil and gas. The well reached a TD of 2,700 ft (823 m) collecting 294 ft (90 m) of core. The horizontal leg of the well (Balcombe-2Z) was drilled through the Middle Kimmeridge Micrite Limestone for a distance of 1,700 ft (518 m). Cuadrilla was awarded PEDL 244 in 2008 following the 13th Onshore Licensing Round. The licence covers an area of 153 sq km. Conoco’s Balcombe-1 encountered oil shows in the upper of two Middle Kimmeridge micrite units. An open hole DST resulted in no fluids back to surface however, a post acid wash cased hole DST resulted in flow rates of 50 bo/d. Interest in PEDL 244 following completion of the deal will be held by Angus Energy Plc (25% + operator) Cuadrilla subsidiary Cuadrilla Balcombe Limited (56.25%) and AJ Lucas subsidiary Lucas Bolney Limited (18.75%).

United Kingdom, PEDL 244

YPF plugged and abandoned in September 2018 the Caldenes Central x-2, a possible new field wildcat on the Los Caldenes license in the Rio Negro province of the Neuquen Basin. Formation water and oil shows were tested over the 2,310-2,661m interval. The well was spud on 21 May 2018 and finished drilling on 19 June 2018 with 2,890m PTD by the drilling rig PTV-203. The Quintuco and Sierras Blancas formations were the geological targets. YPF had plugged and abandoned in 2016 the Caldenes Central x-1 new field wildcat on the south central part of this block.

Argentina, Los Caldenes

Deepwater block 10, ab. 15km N. of Delphynus-1, spudded 9 Jan ’19, Stena IceMAX DS over from Delphynus (status n/a). Local reports suggest gas has been encountered at Glafkos, some formal announcement is expected towards mid-month. ExxonMobil (op), partner Qatar Petr.

Glaukos 1 (ExxonMobil 60% op, Qatar Petr 40%) DW block 10, ab. 15km N. of Delphynus 1, (status n/a). Local reports suggest gas has been encountered at Glaukos, some formal announcement is expected towards mid-month.

On 26 November 2019, Kosmos Energy announced it had completed operations at the Resolution prospect at Garden Banks block 491 (G35918) in the Western Gulf of Mexico. Well GB 492 1S0B1 (API 608074083101) encountered reservoir quality sands, but the main objective failed to find hydrocarbons. On 11 October 2019, the Bureau of Ocean Energy Management (BOEM) approved a revised application for bypass submitted by Kosmos for well GB 492 1S0B1. The well is being drilled by the Seadrill "West Capricorn", which began operations on 2 October 2019. The bottom hole location for the well is located in GB 492. The water depth at the surface location is 6194 ft (1888 m). On 4 September 2019, the Bureau of Ocean Energy Management (BOEM) approved the exploration plan filed by Kosmos listing 3 wells and 2 mirror locations to be drilled in the Garden Banks (GB) protraction area of the Western Gulf of Mexico at the Resolution prospect covering blocks GB 491 (G35918) and GB 492 (G35919). Kosmos submitted plan N-10070 on 10 June 2019. Of the three non-mirror wells, two have a surface location in GB 492 and one has a surface location in GB 491.Each well is estimated to take 140 days to drill. On 17 September, the BOEM approved the permit to drill location SL3 in a water depth of 1,888 ft (575 m) using the Seadrill “West Capricorn” drillship. The well has a surface location in the southeast corner of GB 491 and a bottom hole location in GB 492. The prospect area is located in the northwestern quadrant of the Garden Banks protraction area, about 233 mi (375 km) southwest from the onshore support base at Port Fourchon, Louisiana. It is about 12 mi (19 km) north of the Occidental-operated Gunnison field which has produced over 66 MMboe by year-end 2018 from Pleistocene to Pliocene age sands. Water depths at the proposed locations vary from 1,884 – 2,073 ft (574 – 632 m). In a 5 August 2019 investor presentation, Kosmos estimated the gross resource potential at Resolution to be 100 – 200 MMboe. The planned spud date for the well is sometime in October 2019. Kosmos operates the leases with 50% working interest, with the remaining 50% owned by BP. Bidding alone and without competition, BP picked up GB 491 and GB 492 at Sale 248 in August 2016 with bonus bids of USD 643,726 and USD 619,726, respectively. Kosmos farmed into the blocks effective 1 February 2019 as part of a farm-in package of 18 BP-owned blocks in Garden Banks.

GB 492 001S0B0 (Resolution) nfw. (Kosmos 50% op, BP 50%) in GB 491, lease G35918, was designed to test an amplitude-supported sub-salt prospect in the underexplored western GB area, reservoir quality sands encountered but found water-bearing, well to P&A, WD=600m, TD=7700m.

Chevron secured retention lease WA-83-R, 482 sq km S. of the Scarborough field in the Investigator sub-basin, N. Carnarvon Basin, on 12 Oct ’17 for 5 years. It surrounds the 2012 Pinhoe gas discovery in WA-383-P which was correspondingly reduced prior to expiry next May. Chevron (op) 50%, Shell 50%.

Chevron (50%, Shell 50%) was awarded WA-83-R retention lease (482km²).

Reobald Resources plc announced on the 26 May 2020 that is has 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. Consideration for the deal comprises GBP 1.4 million and the issue of 350,000,000 ordinary shares of 0.01p in the capital of Reobald. The acquirer's effective economic interest in the licence will increase from 39% to 56% where the interest will comprise 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. The deal is subject to regulatory approval. Rathlin is planning on drilling two wells at its West Newton B site in PEDL 183 in 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 a horizontal well. On 15 April 2020 it was reported that Rathlin has 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 completion of the deal interest in the licence will be held by Rathlin Energy (UK) Limited (66.67% + operator), Reobald Resources plc (16.665%) and Union Jack Oil Plc (16.665%).

United Kingdom (Gainsborough Trough (Anglo-Dutch B.)) Cadeby Humber Oil & Gas Ltd Reobald Resources - PEDL 183 - Deal agreed

Block 3 (Afar), Huqf Arch of the Oman Basin, E. Oman, drilled 4Q ’17, believed P+A dry at TD 2,530m. Target Amin fm. CCED (op), partners Tethys Oil + Mitsui.

V-1 expl Block 3 (Afar), Huqf Arch of the Oman Basin, E. Oman, believed P+A dry at TD 2,530m. Target Amin fm. CCED (op), partners Tethys Oil + Mitsui.

Pertamina EP has probably plugged and abandoned Akasia Besar 3 (ASB-3), located in the Jawa Bagian Barat (JBB) PPC, in April 2020, as dry well. ASB-3 was spudded in late August 2019 to appraise the Akasia Besar 1 discovery. The well has a PTD of 2,700m, targeting the volcaniclastics zone of the Jatibarang Formation. Operations for the well were initially planned for approximately 130 days. IHS Markit understands that the previous appraisal well Akasia Besar 2 (ASB-2) was plugged and abandoned as dry hole in January 2020. ASB-2 was spudded in mid-November 2019, had PTD of 1,900 m and likely targeted the Jatibarang Formation. In December 2019, the operator drilled core section in the attempt to determine the quality of the reservoir. The previous exploration activity in the Akasia Besar area was a 3D seismic survey acquired in 2016. The survey was designed to cover an area 1,120 sq km, of which approximately 99% was acquired. Elnusa was the contractor for this survey. The seismic data was acquired to improve the definition of reservoir distribution in the area. ASB-3 is the first appraisal well drilled in the Akasia Besar field which was discovered in 2012. The discovery well Akasia Besar 1 reportedly flowed over 2,200 bo/d and 0.8 MMcfg/d from two DSTs conducted on a carbonate reservoir of the Middle-Upper Miocene Upper Cibulakan Group. It is understood that the first two tests conducted on the Jatibarang Formation did not flow. The Akasia Besar 1 well was brought onstream through a put on production (POP) scheme in 2013. Pertamina is operator and sole interest holder in the JBB PPC. Background Information Wildcat Akasia Besar 1 was suspended on 28 August 2012 with at least 2,250 b/d of oil and 0.8 MMcf/d of gas flowed during the test. The well had PTD of 2,700 m and was possibly targeting Upper Oligocene to Lower Miocene sandstones of the Talang Akar Formation/Cibulakan Group and Lower Miocene carbonate build-up of the Batu Raja Formation. Akasia Besar 1 was one of eight exploration wells drilled in the block 2012. Seven of these wells (Bambu Besar 2, Akasia Besar 1, Jati Keling 2, Bambu Gunung 1, Tegal Pacing 2, Jati Besar A and Tambun Deep 1ST1) were concluded as successful while one well (Cikarang 2) was unsuccessful. Aside from the drilling, a 1,012 sq km 3D survey was completed by Elnusa over the block on 25 June 2012. The survey covered the Akasia Bagus structure, wherein a discovery was drilled in early 2010. Data acquisition commenced in early July 2011. Advance party for the survey started in early May 2011.

Pertamina EP has probably plugged and abandoned Akasia Besar 3 (ASB-3), located in the Jawa Bagian Barat (JBB) PPC, in April 2020, as dry well. ASB-3

NZOG has agreed to offload its remaining 25% in the Bohorok PSC in N. Sumatra to optr Bow Energy. Conditions include a cash payment of USD 2 MM to NZOG if/when a 1st well* comes on stream, USD 1 MM more for a 2nd well.  Bow is now sole holder of the 5,022-sq km block. *Bow Kaya-1 is planned in 2019, target gas + cond in the Belumai + Keutapang fm’s.

NZOG has agreed to offload its remaining 25% in the Bohorok PSC in N. Sumatra to optr Bow Energy. Conditions include a cash payment of USD 2 MM to NZOG if/when a 1st well* comes on stream, USD 1 MM more for a 2nd well. Bow is now sole holder of the 5,022-sq km block. *Bow Kaya-1 is planned in 2019, target gas + cond in the Belumai + Keutapang fm’s.

BOFF ML, Bombay shallow waters, N. of D-12 1 field, TD 2,951m, ops terminated (tested, assumed susp) mid-Sep ’18, Sagar Uday JU.

D 12 C nfw in BOFF ML, Bombay shallow waters, N. of D-12 1 field, TD 2,951m, ops terminated (tested, assumed susp)

On 18 May 2020 Equinor exited licence P2345 with Ithaca picking up its 50% interest in the licence. The licence was initially awarded to Chevron and Equinor, both with a 50% interest prior to Ithaca's acquisition of Chevron's UK assets. Phase A of the licence commitment required the licensee to obtain 450 sq km of reprocessed 3D data and to complete a charge modelling and reservoir study along with undertaking a seal and trap integrity assessment. Phase C of the licence, as there was no Phase B, had a drill or drop commitment for the licensee to drill a well to 2,000 m depth or 50 m into the pre-Upper Jurassic. Licence P2345 was awarded in the 30th Offshore Mature licensing round and comprises four blocks – 14/23, 14/24, 14/28 and 14/29b. The end date of the initial term is the 30 September 2023. Ithaca Energy (UK) Limited now holds 100% interest in the licence.

Equinor exited licence P2345 with Ithaca picking up its 50% interest in the licence.

W. Bohai Gulf Basin, WD 25m, ops terminated 7 Jul ’19, results n/a. Target Tertiary, HYSY 921 JU.

Caofeidian 17-1-1 (CFD 17-1-1) nfw, W. Bohai Gulf Basin, WD 25m, ops terminated 7 Jul ’19, results n/a. Target Tertiary,

On 20 December 2018, Ecopetrol issued a press release indicating it concluded a farm-in for 10% working interest with the consortium of Shell and Chevron in the Saturno block. The transaction is pending formal governmental approvals.  Previously Shell was operator and had 50% working interest and partner Chevron had 50% working interest in the PSC contract.  Upon formal governmental approvals Shell will continue as operator with 45% working interest and partners are Chevron with 45% and Ecopetrol with 10%. On 17 December 2018, the consortium of Shell and Chevron was granted an official award for the 1,100.19 sq km Saturno block through the 5th PSC Pre-Salt Bid Round after contract signature with the government. On 28 September 2018, the Shell led consortium was granted a preliminary award for the Saturno block through the 5th PSC Pre-Salt Bid Round after being the high bidder for the block.   The consortium paid a fixed bonus of USD 781.25 million at USD 1.00 to BRL 4.00 exchange rate and has a first exploration period financial guarantee of USD 62.50 million to cover the cost of the one well drilling commitment.   The consortium offered a state take of 70.20% and won the block over the one other bid for the block by ExxonMobil with 64% and QPI with 36% who bid 42.49% state take.   The PSC contract has a seven year exploration period.   The local content is 18% for the exploration phase and 25% to 40% for the development and production phases.

Ecopetrol has acquired a 10% stake in the recently-awarded Saturno block, 1,100 sq km in the central Santos pre-salt and so far Shell-Chevron 50:50 and to become 45:45.

Timor Resources is looking to attract potential partners to its East Timor onshore acreage involving blocks A & C and application B.   In block A drilling is tentatively planned in 2019. Block C targets are yet to be refined. In block B (1,004 sq km) a 40% stake is believed available. Contact: [email protected].

Timor Resources is looking to attract potential partners to its East Timor onshore acreage involving blocks A & C and application B. In block A drilling is tentatively planned in 2019. Block C targets are yet to be refined. In block B (1,004 sq km) a 40% stake is believed available.

Further to DEA 22 Sep ’17 (adds content) : NW part of AE-0060-M-Mezcalapa-10 block, onshore Sureste Basin, TVD 5,892m, susp. o&g discovery on 23 Nov ’17 after testing  4,292 bo/d + 9.9 MMcfg/d from 4,670-4,770m in the target Cretaceous.

Mexico, not found

KrisEnergy continued offering a farm-in opportunity in the Bala-Balakang PSC (formerly Tanjung Aru PSC), in April 2018. The 3,145 sq km block is located at the southern edge of the Kutei Basin, with water depths ranging between 20 and 1,000 m. The block is estimated to contain over 8 Tcf of in-place resources. KrisEnergy holds 85% operating interest in the block while Natuna Ventures Pte Ltd holds the remaining 15% participating interest. The operator is offering up to 42% interest in the block, in return for pro-rata share of back costs and for full carry on a discretionary exploration well to be drilled by 12 December 2019 (end of exploration year 8). All the firm commitments for the first exploration term in the PSC have been fulfilled, following the acquisition of a 500 sq km 3D Broadband seismic survey by KrisEnergy in 2014. The survey commenced on 24 March 2014 using Western Geco’s “Western Monarch” M/V, and was completed on 11 April 2014. The survey complemented the existing 3D seismic dataset and allowed the identification of multiple play types and bright spots at various depths. The Bala-Balakang PSC contains two gas discoveries, Halimun 1 and Papandayan 1. As of 31 December 2015, contingent resources in the block were estimated at approximately 110 Bcfg (on a 100% working interest basis). The block is expected to be primarily gas prone. Typical exploration targets in the block are Miocene to Pliocene channel/fan complexes with structural and stratigraphic traps, analogous to the Jangkrik, Merakes and Gendalo fields located to the north. Further exploration is also expected to yield biogenic gas in Plio-Pleistocene reservoirs. The block was awarded in 2011. Firm commitments for the first three years of exploration included G&G studies (USD 0.50 million) and 500 sq km 3D seismic acquisition (USD 5 million). The block was offered in late September 2011 as part of the Second Petroleum Bidding Round 2011 under the direct offer mechanism. The farm-in opportunity in the block was previously offered in November 2015. For further information, interested parties may contact: Mike Whibley Vice President, Technical [email protected]   Dr. Gadjah E. Pireno Vice President, Exploration and New Ventures [email protected] Background Information The Bala-Balakang PSC was previously known as Tanjung Aru PSC. The idea to change the block name was initiated by the government of West Sulawesi in late October 2014, based on the administration area which is essentially located in Western Sulawesi province. The name change was approved by Indonesian authorities in 2015. The block was officially awarded on 19 December 2011 to a consortium of KrisEnergy (43%, operator), Neon Energy (42%) and Natuna Ventures Pte Ltd (15%). In August 2015, KrisEnergy acquired the whole of Neon Energy’s interest, increasing its total stakes to 85%. The block straddles the Kutei Basin and the Pater Noster Shelf and originally covered an area of around 4,200 sq km, of which approximately half in shelf water and half in deep water, with maximum depths of 2,500m. The same acreage was previously operated by Hess between 2001 and 2009, under the Tanjung Aru PSC. Earlier, a portion of the block was covered by Mobil’s Makassar Strait Block A since 1973 until partial relinquishments in 1990. Tanjung Aru PSC history Hess (50%, operator) and Petronas Carigali (50%) were initially awarded the Tanjung Aru PSC on 7 December 2001. The effective date of the contract was on 22 November 2001. The 4,190 sq km block is located to the south of Chevron's Ganal PSC in water depths ranging from 150-1,700m. The block is under standard frontier PSC terms and signature bonus paid amount to USD 7.75 million. The total commitment for the 10 year exploration period would amount to USD 81.75 million. The firm three year work commitment included drilling of three exploratory wells and acquisition of 2,000 km of 2D seismic data and 400 sq km of 3D seismic coverage. Prior to the award, no drilling had previously been undertaken within the limits of the block. Hess commenced exploration in the block between 8-29 April 2002, when it acquired a 2,035km 2D seismic survey. Hess also purchased 1,477sq km of 3D data over the block from an extensive regional 3D "spec" survey over the deep water Makassar Strait acquired by PGS in 1999. Hess was the first company to carry out exploration drilling within the block boundaries. The company drilled three commitment wells which yielded two small gas discoveries (Halimun 1 and Papandayan 1, both in July 2002). For both wells, the Upper Miocene primary objective was interpreted as a basin floor fan but turned out to be mud-rich. The Lower Pliocene secondary objective, interpreted as canyon fill, contained multiple gas bearing sands. Halimun 1 has estimated 2P recoverable reserves of around 70 Bscfg while Papandayan 1 has around 50 Bscfg. The last well drilled, Rinjani 1, was plugged and abandoned in January 2005 with gas shows and was not tested. It targeted Middle Miocene turbidite sandstones and Upper Eocene sandstones in a stratigraphic trap. Hess may have received government approval for the total relinquishment of the Tanjung Aru PSC in November 2009. It was initially reported in May 2005 that Hess and partners indicated their intent to totally relinquish the block following the drilling of the committed three exploration wells. At the time of relinquishment, rightholders of the block were Hess (32.5%, operator), Petronas Carigali (42.5%), Pertamina (15%) and Chevron (10%). Prior to the first drilling campaign, Pertamina farmed-in for a 15% stake in the block, getting 7.5% each from Amerada Hess and Petronas Carigali. Hess' first well, Halimun 1, was spudded on 7 July 2002. On 20 July 2002, the well was plugged and abandoned as a non-commercial gas discovery after being drilled to TD at 2,401m. Halimun 1 was drilled in 1,061m of water and was targeting Upper Miocene and Pliocene sandstones with a PTD of 3,048m. The well lies some 34 km south of Mobil's 1994 Perintis 1 non-commercial gas/condensate discovery (6 MMcf/d plus 150 bc/d). Hess then relocated the "Sedco 601" S/S and on 21 July 2002 spudded wildcat Papandayan 1 as the second in a two well drilling programme. The well was drilled to TD at 2,463m and was plugged and abandoned as a non-commercial gas discovery without being tested on 30 July 2002. Papandayan 1 was drilled in 554m of water and was targeting Late Miocene and Pliocene sandstones with a PTD of 2,652m. The well lies in the north of the block and is located 13.5km west of Halimun 1. Wildcat Rinjani 1 was plugged and abandoned with gas shows on 15 January 2005 after being drilled to TD at 2,727m. The well was however not tested. The well was spudded on 3 January 2005 using the "Ocean Baroness" S/S in 1,159m of water. Rinjani 1 had a PTD of 2,758m and was targeting Middle Miocene turbidite sandstones and Upper Eocene clastics in a stratigraphic trap about 10km south of Halimun 1. Rinjani 1 was the operator's final commitment well in the block. Prior to the spud of Rinjani 1, Chevron farmed in to the PSC for a 10% stake from Hess.

Indonesia, Aru PSC

Santos Offshore Pty Ltd was awarded exploration permit WA-540-P, located in the Roebuck Basin, on 6 June 2019.  The permit has been awarded for a period of six years and will expire, or be eligible for renewal, on 5 June 2025. The block was awarded after being offered as block W17-4 in a re-release of acreage in the 2018 Offshore Federal Acreage Release. Work commitments have been assigned for the duration of the permit’s validity and include the acquisition or licencing of 965 km 2D and 1,000 sq km 3D seismic in years one to three, geological and geophysical studies, to include well planning, in year four, the drilling of an exploration well in year five (between June 2023 and June 2024) and further geological and geophysical studies in the final year, to include post-well studies. There are no existing wells with the permit area. It lies directly north, and adjacent to, Santos’ other four Roebuck permits that it acquired in its takeover of Quadrant Energy and in which the Dorado discovery lies. WA-540-P, which covers an area of 6,359 sq km, was awarded on 6 June 2019.  Santos Offshore Pty Ltd holds 100% interest and operatorship of the permit.

Santos was awarded WA-540-P, NE of Dorado field area (6359km²), awarded for 6 years, formely W17-4.

Zenith has entered into a JV agreement with a local partner for the potential acquisition of an undisclosed onshore oil production licence in the Kouilou area near Pointe-Noire. The 300 b/d field was shut-in last year pending the assignment of a new licence. Meanwhile Zenith continues negotiations with the relevant authorities for the assignment of a new 25-year licence on the Tilapia field/block.

Congo (Lower Congo B.), Zenith has entered into a JV agreement with a local partner for the potential acquisition of an undisclosed onshore oil production licence in the Kouilou area near Pointe-Noire. The 300 b/d field was shut-in last year pending the assignment of a new licence.

Larus Energy Ltd is looking for a joint venture partner in its wholly owned and operated exploration licence PPL 579, located in the south-east of Papua New Guinea in Larus’ newly defined Torres Basin.  Larus Energy reports it is offering significant equity in the permit, with a farminee to take part in an upcoming exploration programme. Larus has contracted Moyes & Co. to assist in the divesture process.  A data room is open for interested parties.  In August 2017 Larus reported that it was increasing its efforts in the farm-out process, with results of seismic now available and the discovery of an oil seep within the licence area. In Q4 2017 it was reported that discussions were ongoing with a number of potential partners, with new confidentiality agreements signed in November. Moyes & Co is being utilised in an advisory capacity during the process, in which interested parties have been outlined since 2015 and have been conducting geological, geophysical and commercial due diligence as is required for farminees. In August 2015 Larus reported that discussions and due diligence was continuing, with 14 companies interested in the asset.   In February 2017 Larus was awarded PPL 579 to replace PPL 326 which expired in September 2016. The newly awarded licence covers 9,257 sq km across both onshore and offshore Papuan Plateau/Aure Fold Belt. PPL 579 has been awarded for a period of 11 years and is scheduled to expire in February 2028. Larus also holds 100% interest in the neighbouring application APPL 580 which was submitted for approval consideration in December 2015. Larus is looking for a partner to assist with the ongoing work programme in the permit, although Larus has reported that the first two years was already fully funded. In the first two years, Larus undertook work to develop the shallow Miocene play potential which includes the Vekwala and Sunday prospects. In 2015 and 2016, the Haere and Hahonau 2D seismic surveys were completed from which the data will was processed to facilitate lead and prospect mapping. Further, smaller surveys have also been completed over the asset by Larus. In December 2018, Larus received approval to vary the work commitments for the third and fourth years. The requirement to dill an exploration well has bene replaced with the acquisition of a high resolution airborne magnetics and gravity survey. Larus plans to acquire around 7,250 sq km at a cost of USD 2.5 million. The survey is required by March 2021. Suitable partners will be asked to fund 3D seismic data acquisition to help further define Vekwala and Sunday prospects which is required prior to drilling. The first exploration well is currently due by March 2023. Larus reports that there is potential for both Mesozoic and Tertiary targets within the permit area.  Potential reservoirs include a Mesozoic Puri Limestone equivalent, the Tertiary Talama and Lavao units and also a potential Toro sandstone equivalent. The early – mid Jurassic Manil Shale and Miocene-Pliocene Aure Beds Shale are thought to form potential source rocks, with the Orubadi Shale and intraformational units possible as seals. The Vekwala prospect has been reported to potentially contain resources of 13 Tcfg and 180 MMb liquids within a Jurassic reservoir. Water depth at location is approximately 42 m and the main target is at a depth of approximately 3,600 m below seabed. Previously the Sunday Prospect was outlined as the main target in the licence. The Sunday Prospect lies in a water depth of approximately 600 m and the main target is at a depth of approximately 3,000 m below seabed in a Cretaceous reservoir. Sunday is considered to be a 40 km long anticline which could contain 13.5 Tcfg with 160 MMb liquids. There are also several other prospects and leads present. The prospects and leads in the licence are thought to be part of a Mesozoic petroleum system.   In August 2016 onshore oil seeps were invested by Larus. This was followed up by further sampling of light crude oil near the Imila village, north of Kapiano, within  APPL 580. Geochemical analysis has confirmed that the oil has been generated in the Torres Basin. Analysis will now be undertaken to understand the source rock and maturity to further validate the hydrocarbon system model being constructed by Larus. PPL 579 covers an area of 9,257 sq km and was awarded in February 2017. Larus Energy holds 100% interest and is looking to divest its interest. Parties interested in pursuing this opportunity should contact: Ian Cross, Managing Director Moyes & Co Tel: +1 281 501 7110 Email: [email protected]   Andy Melvin, Managing Director Moyes & Co Tel: + 44 7702 855895            Email: [email protected]

Larus Energy Ltd is looking for a joint venture partner in its wholly owned and operated exploration licence PPL 579, located in the south-east of Papua New Guinea in Larus’ newly defined Torres Basin. Larus Energy reports it is offering significant equity in the permit, with a farminee to take part in an upcoming exploration programme.

Further to DEA 5 Nov ’18 (BHP pick-up), Serica has now signed up to acquire Marubeni’s 3.75% interest in Bruce and 8.33% in Keith and associated infrastructure. The latest deal calls for Serica to assume the decommissioning obligations of Marubeni in exchange for cash from the latter. It will also be retro-effective 1 Jan ’18, completion subject to that of the previous deals by BP and Total, inter alia. Serica will hold 98% in Bruce, 100% in Keith.

Serica Energy has acquired 16% interest in Bruce (->94,25% ) and 31,83% in Keith (->91,67%) fields from BHP Billiton, following acquisitions of interests in the two fields from BP and Total in the past year.

The award to Shell of the 2,265-sq km onshore block 4 was gazetted yesterday in the Fletorja Zyrtare gazette, thus rendering the award effective (see also DEA 14 Jun ’18). Commitments include 125km of 2D seismic reprocessing of 125km 2D in 2 yrs, 300km of 2D and reprocessing of 200km of 2D and an optional 3,000m well in the next 2 yrs, 1 explo well in last 2 yrs.

The award to Shell of the 2,265-sq km onshore block 4 was gazetted yesterday in the Fletorja Zyrtare gazette,

Bridgeport secured ATP 2023-P (434 sq km) and ATP 2024-P (421 sq km) in the Cooper-Eromanga Basin, on 8 Apr '20 for 6 years. New Era O&G and Leigh Creek Energy have agreed to farmin for 50% and 20%, between the application and the date of award. The acreage is prospective for CBM and conventional resources.

Bridgeport Energy was farming out interest in permits ATP 2023-P, ATP 2024-P, ATP 948-P and PL 256, to New Era.

GSPC has embarked on the formal sale process for its 55% stake in the 162-sq km Cambay PSC, partner Oilex (op) having right of 1st refusal.

GSPC has embarked on the formal sale process for its 55% stake in the 162-sq km Cambay PSC, partner Oilex (op) having right of 1st refusal.

Hibiscus Petroleum announced on 9 October 2018 that it has agreed a deal to acquire a 50% interest in licence P198 blocks – 15/13a and 15/13b from Caldera Petroleum (UK) Ltd.  Under the terms of the deal Hibiscus will pay a consideration of USD 37.5 million for the interest. This follows the acquisition of 100% in the blocks by Caldera Petroleum Ltd, a wholly owned subsidiary of Aban Offshore Limited, from the National Iranian Oil Company for USD 75 million. The deals are subject to approval from the Oil and Gas Authority and are planned to complete later in October 2018. It is likely that Anasuria Hibiscus will operate the acreage. Block 15/13a contains the 15/13a-10 (J4-P1) discovery. This was made in 2008. The well was drilled targeting the Jurassic Piper (J4) and Paleocene Balmoral Sandstones (P1). The well encountered the Balmoral Sands and tested at the interval of 5,435 – 5,527 ft where it flowed at 1,937 bo/d and 0.293 MMcf/g. Block 15/13b hosts the 15/13-2 (Hood) discovery made in 1975 where oil was encountered in the Piper Formation. The Hood structure consists of a combined structure dip closure to the west, north and south and a stratigraphic pinch-out of the Piper Sands to the east. The discovery was appraised in 1987 with well 15/13s-4 which was abandoned with shows and 15/13a-4Z which flowed at 2.8 bo/d from a thin Piper Sandstone unit. According to Anasuria Hibiscus, it believes the acreage to contain a total of 60 MMbo (STOIIP, 2C resources) and the companies will look to various future development opportunities across the blocks. Following completion of the deal interest in the blocks will be held by Anasuria Hibiscus UK Limited (50% + Operator) and Caldera Petroleum (UK) Limited (50%).

Hibiscus has signed a conditional sale and purchase agreement with Aban Offshore subsidiary Caldera (->50% op.) for a 50% share in production licence P198, which contains blocks 15/13a and 15/13b, for US$37.5 MM.

On 3 February 2020, Petrobras published a teaser to sell its 62.5% working interest in the 182.78 sq km BC-020 contract, Papa-Terra production concession block in the deep-water, offshore Campos Basin. It has denominated the asset as the E&P Campos Basin. Petrobras holds 62.5% operated working interest with non-operating partner Chevron holding 37.5%. Petrobras stated that the Chevron working interest was not included and it is unclear if Chevron will exercise its first right of refusal or also offer its working interest in a separate sales process. Petrobras indicated that it estimates original oil in place (OOIP) of 1.98 Bbls of 14° to 17° API oil with improved production results from the latest two development wells drilled. It also indicated there is upside through a prospect identified in the block. 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 28 February 2020. The qualification documents must be sent to [email protected] by 13 March 2020. On 7 August 2015, the ANP approved the first revision to the development plan for the Petrobras operated Campos Basin Papa-Terra Production Concession. The modifications to the development plan include the commencement of a polymer injection system by 31 December 2017 and the presentation of a second revision of the development plan by 31 July 2017. The second revision will update the geological and reservoir simulation models along with estimating production and reserves based on the updated models. The field began producing a high water cut in late 2014 with a decrease in oil production. In 2014 the field produced an average of 24,376 bo/d with peak production of 33,940 bo/d in July 2014. In December 2014 the water cut increased to about 30%. In 2015 the water cut has been steadily increasing to June 2015 where the water cut was about 69% of the 13,137 bo/d produced from four horizontal wells, three connected to the FPSO P-63 and one connected to the TLWP P-61. Petrobras was reported to have foreseen potential problems with the heavy and viscous oil and the Eocene and Cretaceous turbidite reservoirs. It is working on defining the best strategy for drilling additional production and injection wells with regards to implementing the polymer injection project that is intended to increase oil production and decrease water production. The original development plan included two production units, the FPSO P-63 that commenced production in the field in November 2013 and the TLWP P-61 production unit that commenced production in March 2015. They have a capacity of 140 Mbo/d and 35 MMcfg/d through 18 production wells and 11 injector wells. The TLWP P-61 production unit is also connected to the Tender Assisted Drilling Unit (TAD) for drilling and workover operations. The official discovery well for the Papa-Terra field was new-pool wildcat 4-RJS-610 (4-BRSA-218-RJS) on 24 June 2003. Petrobras drilled four final evaluation wells during the fourth quarter of 2005 and indicated in a press release it had estimated in place reserves of about 700 MMbo to 1 Bbo of 14° to 17° API with recoverable 2P reserves estimated to be 380 MMbo. Peak production was expected to be reached in 2016. Petrobras indicated this was one of the most complex projects it has developed to date as a result of the 1,200 m water depth and the heavy oil in the reservoir. The estimated cost for the entire project was reported to be USD 5.2 billion. On 16 March 2015, Petrobras reported production startup commenced on the tension leg platform, TLWP P-61 production unit, in the Campos Basin Papa-Terra Production Concession. The TLWP will be connected to 13 production wells and to the FPSO P-63. The first production well was connected to the TLWP and began producing into the FPSO P-63. Petrobras produced first oil through the FPSO P-63 production unit on 12 November 2013. The production capacity for both production units is 140 Mbo/d and 35 MMcfg/d through 18 production wells and 11 injector wells. The FPSO topsides facilities are designed to process and inject up to 340,000 b/d of water. The FPSO P-63 will be connected to five production wells and 11 injector wells. Petrobras will connect an additional five injector wells to the P-63 after six have been connected to date. The TLWP P-61 production unit is also connected to the Tender Assisted Drilling Unit (TAD) that is equipped to conduct drilling and workover operations.

Petrobras published a teaser to sell its 62.5% working interest in the 182.78 sq km BC-020 contract, Papa-Terra production concession block in the deep-water, offshore Campos Basin. It has denominated the asset as the E&P Campos Basin. Petrobras holds 62.5% operated working interest with non-operating partner Chevron holding 37.5%.

Zhuanghai 25d flow tested approximately 1,299 bo/d and 1.1 MMcfg/d (0% water and less than 0.01% sand) through a 10mm choke from the Oligocene Dongying Formation on 26 June 2020. The test flow rate is the highest that Sinopec has achieved from the deeper Paleogene interval in the Zhuanghai fault zone, Bohai Gulf Basin. Zhuanghai 25d was spudded on or around 5 April 2020 using the “Shengli 7” jack-up. The oil and gas exploration well was targeting the Guantao and Dongying formations. Zhuanghai 25d is in the Sinopec operated Binhai Block in the offshore Bohai Gulf Basin.

Not Found

Mari Petroleum Company Ltd (MPCL) has plugged and abandoned the Miraj 1 new field wildcat (NFW) well within the Ghauri 3273-3 EL (Potwar Basin) onshore concession during the last week of July 2020 after carrying out testing. The company had initiated testing in early July after drilling to a TD of 4,934 m in the second sidetrack hole – reached in June 2020. The well was spudded on 4 May 2019 using the Mari-3 land rig with a prognosed TD of 5,270 m in the Cambrian Khewra Formation. Miraj 1 was the third exploratory well in the block and it was mainly targeting the Eocene Sakesar formation and Cambrian Khewra formation. It is located on the Harno prospect. MPCL had reported on 30 April 2020 in its quarterly report (quarter ending 31 March 2020) that the well reached the TD of 4,976 m (assumed TVD, as TD elsewhere reported as 5,045 m) in the Cambrian Khewra Formation on 25 March 2020. After reaching TD, the company encountered stuck string problem during logging which could not be retrieved, and it was decided to initiate a second sidetrack in order to reach Khewra formation for testing and evaluation. Drilling activity for second sidetrack is subsequently understood to have started in late May 2020 from the kick-off point (KOP) of 4,889 m. Miraj 1 was drilling at 2,085 m depth by the end of May 2019, reached 2,487 m by the end of June and progressed to 3,311 m during mid-July 2019. It was drilling at 3,754 m depth by the end of July, reached 4,052 m by mid-August 2019 and was drilling at 4,455 m depth by the end of the month. After reaching 4,533 m by mid-September 2019, the well progressed to 4,561 m depth by the end of the month, reached 4,648 m during mid-October and 4,864 m at the end of October 2019. After drilling to a depth of 5,045 m by the end of November 2019, the company had conducted testing from mid-December 2019 to late January 2020. The company had initiated the first sidetrack in late January 2020 and it was drilling at 4,740 m depth in the sidetrack hole by the end of February 2020. The Ghauri block currently covers an area of 889 sq km in the Punjab province and the equity split is as follows: MPCL (65%, operator) and Pakistan Petroleum Ltd (PPL) (35%). MPCL made the Dharian 1 oil discovery in the Ghauri EL concession in April 2019. A drill stem test (DST) was carried out in the Cambrian Khewra Sandstone formation and it flowed 372 bo/d of 29’ API through 64/64” choke at a wellhead flowing pressure of 10 to 25 psi. It also flowed 304 bw/d during testing. The well was spudded on 21 December 2017 and drilled to a TD of 4,770 m (4,472 m TVD) in the Khewra Sandstone. It was targeting the Eocene Sakesar and Cambrian Khewra formations. Ghauri X-1 was the first well drilled in the block through which the company had made an oil discovery in April 2014.   Background Information Ghauri EL was originally awarded to Mari Gas Company Ltd (MGCL) on 16 February 2010 with an area of 1,292 sq km. MGCL then assigned 35% interests to Pakistan Petroleum Ltd (PPL) with effect from 11 July 2011 making the equity split as: Mari Petroleum Company Ltd (65%, operator) and Pakistan Petroleum Ltd (35%). On 14 March 2013 MOL Pakistan Oil & Gas Co BV (a wholly owned subsidiary of the Hungarian state oil company) announced that it had signed a farmout agreement with MPCL that would see it acquire a 30% stake in the block. Mari Gas Company Ltd changed its name to Mari Petroleum Company Limited (MPCL) with effect from 19 November 2012. Seven wells are known to have been drilled within the area covered by the licence to date, none of which has resulted in a hydrocarbon discovery. The most recent of these (Boski 1) was P&A (dry) after reaching TD at 4,611m in June 2003. Mari Petroleum Company Ltd acquired 252 line km of 2D seismic (dynamite / vibroseis source) in the block during June-October 2012 using the BGP ‘0288’ seismic crew. The company was granted a one-year extension to the third licence year of the block with effect from 16 February 2013. MPCL was granted an additional one-year extension to the third licence year of the Ghauri 3273-3 EL onshore concession with effect from 16 February 2014. MPCL had announced the Ghauri X-1 oil discovery on 30 April 2014. The company reported that successful drill stem tests (DSTs) were carried out in the Cambrian Kussak and Eocene Sakesar formations. The well, post-acidisation, flowed from the Sakesar Formation at a rate of 5,500 bo/d, through a 32/64” choke, with pressure of 1,100 psi. The same formation, without acidisation, had flowed 1,200 bo/d through a 28/64” choke. The well flowed from the Kussak Formation in surges, with nitrogen lift, at a rate of 136 bo/d. MPCL acquired 452 sq km 3D seismic during August 2015 – March 2016 period. MPCL was granted an additional one-year extension to the third licence year of the Ghauri EL from 16 February 2015 to 15 February 2016. The company subsequently entered into Phase-II of the initial exploration period of the licence with effect from 16 February 2016 and the area was reduced to 889 sq km. MPCL was granted an eight-month extension to the Phase-II of initial term of Ghauri EL from 16 February 2018 to 15 October 2018. It was reported in July 2018 that MPCL acquired MOL Pakistan’s full 30% interest in the block with effect from 1 May 2017. Prior to acquisition the equity split was as follows: MPCL (35%, operator), PPL (30%) and MOL (30%). MPCL’s Board of Directors had granted the approval on 27 July 2017.

(Potwar B.) Miraj 1 op. by PPL (35%), FAUJI (26%), GHPL (26%), OGDCL (13%) in Ghauri 3273-3 EL block, plugged and abandoned after carrying out testing. The company had initiated testing in early July after drilling to a TD of 4,934 m in the second sidetrack hole – reached in June 2020.

Lundin Petroleum has announced that its wholly owned subsidiary Lundin Norway has been awarded a total of 14 exploration licence interests in the 2017 Norwegian licensing round (Awards in Predefined Areas, APA). The record-high award includes six licences in the North Sea, four licences in the Norwegian Sea and four licences in the southern Barents Sea. Six of the awarded licences will be operated by Lundin Norway. The licence interests are detailed below: PL904 (Blocks 2/9, 3/7): 20% – North Sea PL167C (Block 16/1): 20% – North Sea PL914S (Ivar Aasen unit)(Block 16/1): 1.385% – North Sea PL916 (Blocks 16/2, 25/11): 20% – North Sea PL917 (Blocks 25/7, 10): 20% – North Sea PL919 (Block 25/4): 15% – North Sea PL934 (Blocks 6307/2, 5)*: 40% – Norwegian Sea PL935 (Block 6306/3): 20% – Norwegian Sea PL936 (Blocks 6306/2, 5): 30% – Norwegian Sea PL886B (Blocks 6307/1, 4)*: 40% – Norwegian Sea PL950 (Blocks 7020/1, 2, 7120/11)*: 50% – Southern Barents Sea PL952 (Blocks 7124/5,6,8,9, 7125/4,5,6,7)*: 60% – Southern Barents Sea PL954 (Blocks 7121/1,2,3, 7221/10, 11)*: 40% – Southern Barents Sea PL533B (Block 7219/11)*: 35% – Southern Barents Sea *operator Lundin Norway Original article link Source: Lundin Petroleum

Lundin Petroleum has announced that its wholly owned subsidiary Lundin Norway has been awarded a total of 14 exploration licence interests in the 2017 Norwegian licensing round (Awards in Predefined Areas, APA).

Anadarko has sold its working interest in the Equinor-operated Monument prospect, a subsalt Wilcox play covering six blocks in the Walker Ridge area about 175 miles (280 km) off the Louisiana coast. Anadarko US Offshore LLC and Venari Offshore LLC joined the project only nine months earlier, taking stakes of 41.66% and 16.67%, respectively, in January 2018. The formation of this new partnership had led to speculation that Equinor was setting the stage to test this prospect, which consists of Walker Ridge blocks 227, 270 (E/2), 271, 272, 315, and 316. In September 2015, government regulators approved a five-well, initial exploration plan submitted by Statoil (now called Equinor) for the prospect over Walker Ridge blocks 271 and 272, but the Bureau of Safety and Environmental Enforcement has not issued any drilling permits for the planned Monument wells as of September 2018. With Anadarko’s exit, Equinor’s working interest jumps from 41.67% to 60% while Venari now holds a 40% participating interest. The prospect lies in some 6,700 ft (2,042 m) of water in the deepwater Central Gulf of Mexico. Statoil’s USD 81.7 million signature bonus for Walker Ridge block 271 was the highest bid on a block at Sale 227, held in March 2013. The company and original partner, Samson Offshore, paid over USD 160 million to assemble its six-block acreage position. The prospect’s apparent core leases at Walker Ridge blocks 271 and 272 remain valid through July 2023.

United States, not found

On 26 November 2018, China Congo Wing Wah Petrochimie SA (Wing Wah) completed the Homloni-5 (HOL-5) appraisal well located within Kayo Bloc Nord. The well was drilled to a TD of 2,644 m (the Sialivakou formation) both the Chela and Mengo sandstones were oil bearing. The well was spudded on 26 September 2018. To date Wing Wah has drilled 5 wells: HOL-1, HOL-2, HOL-3, HOL-4 and HOL-5 all have been positive except for HOL-1. Wing Wah plan to drill an exploration well within the block in June 2019. Wing Wah operates the tract with an 85% interest. SNPC holds the remaining 15% carried interest as partner.

China Congo Wing Wah Petrochimie SA drills the successful Homloni-5 appraisal well (HOL-5)

According to official reports in March 2019, Chilean state company ENAP has completed a 50% farm-out process to partner ConocoPhillips on the El Turbio Este block by the end of February 2019. The original agreement was reportedly signed in early-2018, although no other details are currently available. Most recently ENAP launched a 1,300 sq km 3D seismic acquisition project on the block in January 2019 as part of its work program with expected completion date in March 2019. Prior reports indicated that the work commitments also include an investment of USD 47 million over three years. El Turbio Este block covers 3,230 sq km of land on the Santa Cruz Province side of Austral Basin. The farm-in process marked ConocoPhillips first re-entry into Argentina since 2008, when the company sold its Neuquen Basin assets to Petrobas Energia. In addition, ENAP and ConocoPhillips have already partnered on the Chilean side of Austral Basin (locally known as Magallanes Basin) in the Coiron block since 2016. Background Information The Province of Santa Cruz granted the license for El Turbio Este block to ENAP in September 2017, following its Licitacion Publica Nacional e Internacional call for tenders on four inactive blocks in June 2017. The Tapi Aike, Paso Fuhr, El Turbio, and El Turbio Este blocks were offered then after their relinquishments to the province in 2015 due to lack of investments.

ENAP has completed a 50% farm-out process to partner ConocoPhillips on the El Turbio block

Sval Energi has farmed-in to PL 889 by taking a 10% interest in the licence from operator Neptune. Sval will cover 20% of Neptune's costs for the imminent Grind exploration well. In the event of a dry hole this will be capped at NOK 45 million but could increase to NOK 85 million if a discovery is made and the well is sidetracked. Neptune reported in early March 2020 that the deal had been completed on 28 February 2020. Grind exploration well 6507/8-10 S is located approximately 10 km east of Heidrun and 15 km east of Canela and has Jurassic Garn, Ile and Tilje Formation objectives. Planned TD is 2,479 m (2,439 m TVD) and planned duration is up to 67 days (if the sidetrack, which would have a TD of 2,533 m, is drilled). Neptune is expecting to encounter oil similar to that found at Heidrun and the key risk is migration. Interest in PL 889 is now divided between Neptune Energy Norge AS (50% + operator), Equinor Energy AS (20%), Wellesley Petroleum AS (20%) and Sval Energi AS (10%).

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

Saka Energi has likely completed testing operations at the Tambakboyo 2 (TBKY 2) well in the Pangkah PSC, located in the offshore East Java Basin, as the “Hai Yang Shi You 937” J/U rig was demobilized in early October 2018. The well has been earlier reported as an oil and gas discovery. Likely five DSTs were conducted on the well. According to oil and gas regulator SKK Migas, the fourth DST flowed hydrocarbons from the Miocene Kujung Formation in early September 2018. The discovery was announced by operator Saka Energi on 31 August 2018, when the well was reported to have flowed oil and gas from the Tuban, Kujung I and Ngimbang carbonate formations after the completion of the third DST. The reservoir zones are on trend with the Ronggolawe prospect located northeast of the Tambakboyo structure. Initial news of the discovery was reported by local media in mid-August 2018. The flow testing campaign was ongoing at the time, to determine reservoir quality and deliverability. TBKY 2 has been drilled to a total depth of 2,896 m (9,500 feet). The well was likely spudded in late June 2018. Operations were expected to be completed in approximately one month, likely excluding testing. Primary target of the well could be Miocene carbonates of the Kujung Formation. The TBKY 2 well is located approximately 10 km northwest of the Ujung Pangkah B wellhead platform (WHP-B), therefore there is potential for future development of the discovery. Saka reported in mid-May 2018 that drilling preparations were underway. The drilling campaign is part of the commitment from the company to support government’s call to increase exploration activities in the country. One well was previously drilled in the Tambakboyo structure, Tambakboyo 1 by Premier Oil in October 2000. The well, targeting Kujung I carbonates, was drilled to a TD of approximately 1,670 m and encountered oil and gas shows. The company was previously planning to drill exploration well Ronggolawe 2, in 2H 2017, however this well could have been deferred or cancelled. Ronggolawe 2 could have been targeting the Upper Eocene carbonates of the Ngimbang Formation. Saka commenced a new development drilling campaign at the Ujung Pangkah field around October 2017. In addition, the Sidayu field within the block has received Plan of Development (POD) approval in October 2017. In mid-May 2018, Saka reported to have reached FID for the Sidayu development, with first production planned in 2019 from four wells. In addition, the POD for the western area of the Ujung Pangkah field has been reportedly approved, with FID still pending as of early July 2018. The Pangkah PSC produced approximately 4,000 bo/d and 40 MMcfg/d in February 2018. PT Saka Energi Indonesia operates the block with 100% interest after it bought over 75% operating interest from Hess in January 2014.  Prior to the Hess deal, Saka was already a partner in the block via acquisition of 25% partner interest from KUFPEC in June 2013. Background Information Gas from the Ujung Pangkah field is delivered to an onshore processing facility in the Gresik area, operated by Saka’s parent company, PT PLN. The field started producing gas in May 2007 at an initial rate of 20-25 MMscfg/d. LPG production reportedly commenced in late March 2009 with 3,000 b/d and was expected to increase to 10,000 b/d by late 2009. In March 2010, the field produced some 50 MMscfg/d plus 4,000 b/d of LPG. All LPG production from the field is allocated to supply domestic demand. The 3,500 sq km Pangkah PSC was awarded to Premier on 8 May 1996 upon payment of bonuses totalling USD 450,000 with a work obligation of USD 27.1 million in 10 years and USD 6.3 million in the first three years. The partnership at the time comprised Premier (40%), Amerada Hess (36%) and Seafield Resources (24%). Partial relinquishments have since reduced the block to approximately 780 sq km. Premier Oil Pangkah Ltd spudded vertical wildcat Tambakboyo 1 on 17 October 2000 using the Sedco-Forex J/U "Trident 17" in 30m of water in its East Java Sea Pangkah PSC as part of a planned multi-well programme. On 29 October 2000 the well was abandoned with oil and gas shows after having been drilled to TD at 1,672m and logged. The well was targeting a Miocene Kujung Formation Unit I reefal build-up with a PTD of 1,673m and is located 18km west north-west of the 1998 Ujung Pangkah 1 oil and gas discovery. The first well in the Ronggolawe structure, Ronggolawe 1, was drilled by Hess, the previous operator of the block. Ronggolawe 1, situated at a water depth of 50 m, was spudded on or around 6 November 2012 and was drilled to a TD of 2,375 m using the “Rowan EXL 1” J/U. The well was plugged and abandoned in early January 2013, without testing. It is understood that oil and gas indications were encountered, with high gas reading in the Kujung Formation. Ronggolawe 1 is located approximately 15 km northeast of the Ujung Pangkah field. Hess had been planning to drill Ronggolawe 2 since 2013, but the plan did not materialize at the time.

Saka Energi has likely completed testing operations at the Tambakboyo 2 (TBKY 2) well in the Pangkah PSC, located in the offshore East Java Basin, as the “Hai Yang Shi You 937” J/U rig was demobilized in early October 2018. The well has been earlier reported as an oil and gas discovery. Likely five DSTs were conducted on the well. According to oil and gas regulator SKK Migas, the fourth DST flowed hydrocarbons from the Miocene Kujung Formation in early September 2018. The discovery was announced by operator Saka Energi on 31 August 2018, when the well was reported to have flowed oil and gas from the Tuban, Kujung I and Ngimbang carbonate formations after the completion of the third DST. The reservoir zones are on trend with the Ronggolawe prospect located northeast of the Tambakboyo structure. Initial news of the discovery was reported by local media in mid-August 2018. The flow testing campaign was ongoing at the time, to determine reservoir quality and deliverability.

Lundin has transferred 15% of its 35% interest in PL 758 and PL 800 to partner Capricorn with effect from 31 January 2018 (reported by the NPD on 3 February 2018. The licences, which were awarded in APA 2013 and APA 2014 respectively, are located immediately southeast of Norne. PL 758 covers 135 sq km over parts of blocks 6508/1, 6608/10 and 6608/11 and PL 800 covers 185 sq km over parts of blocks 6508/1 and 6508/2. Block 6508/1 contains a minor oil and gas discovery made by Det norske in 2011. Lundin acquired its interest in the licence (and operatorship) from EnQuest in 2015. Exploration well 6508/1-2 was drilled on the Skaugumsasen prospect when the area was held under PL 482. It reached a TD of 1,810 m (1,770 m TVDSS) in the Lower Jurassic and proved an 18 m gas column plus a 23 m oil column in the Lower Jurassic Tilje / Are formations. Recoverable reserves were estimated at 6 MMboe. Following completion of this latest deal, interest in both licences is divided between Lundin Norway AS (20% + operator), Cairn Energy through Capricorn Norge AS (50%) and Skagen44 AS (30%).  

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

Santos Ltd was awarded exploration licence WA-541-P, located in the Beagle sub-basin, North Carnavon Basin, on 26 September 2019. The licence, which was originally offered as W18-4 in the 2018 Offshore Federal Acreage Release, covers an area of  6964.26 sq. km and has been awarded for a period of six years. The license will expire or be eligible renewal on 25 September 2025. Work commitments have been assigned for the duration of the permits validity. During the first two years, Santos are committed to undertaking, processing and reprocessing new and existing 2D cubed and 3D seismic data along with well planning, with a total estimated expenditure of around AUD 31 million. A total of three exploration wells are to be drilled, two in the third permit year at a cost of around AUD 56 million and one in the final year, at an estimated cost of around AUD 20 million. The total estimated cost for the work programme is around AUD 119.8 million. WA-541-P is the third exploration licence to be awarded from the 2018 Offshore Federal Acreage Release, and the first in the North Carnarvon Basin. VIC/P75 and VIC/P76 awarded in early September 2019. The license lies on trend with the recent Dorado discovery, which lies in the adjacent permit. WA-541-P covers an area of 6964.26 sq. km and was awarded on 26 September 2019. Participants in the licence are Santos Ltd (50% interest and operatorship) and BP Developments Australia Pty Ltd (50% interest).

Santos op & BP and were officially awarded exploration permit WA-541-P (4855km²) in the offshore Beagle Sub-basin. Due to the proximity to the Dorado o&gas and cond. discovery, a record 7 qualifying bids were received.

Cairn (through its subsidiary Capricorn) announced on 6 August 2019 that it had sold 10% of its interest in the Nova field to ONE-Dyas for the sum of USD 59.5 million. The field, currently under development with first oil due in September 2021, is covered by PL 378, PL 418 and PL 418 B. The deal sees ONE-Dyas take a 12.12% interest in PL 378 and 10% in both PL 418 and PL 418 B. Cairn stated that it will use the proceeds of the sale to fund exploration and development activities across its group portfolio. The deal was confirmed as complete on 4 December 2019 and is effective from 29 November 2019. Nova was previously called Skarfjell and was discovered in 2012 by 35/9-7. Its reservoir is the Upper Jurassic Heather Formation. The discovery was appraised over the following year and the PDO was submitted in May 2018 (and received approval four months later). Operator Wintershall Dea intends to recover 77 MMboe from the field over an eight-year period using two 4-slot subsea templates (installed in May 2019) sited one kilometre apart (the northerly template will host three water injectors and the southerly one will have three producers). The templates will be tied back to Gjoa which lies approximately 16 km to the northeast. There is also provision for a third template with four more wells if needed. Gjoa will supply Nova with power (from shore), gas lift and water injection. Drilling of six wells will commence in H1 2020 and the installation of the other facilities will take place in 2019 / 2020. A new topsides module will be installed at Gjoa in May 2020 where processing will take place prior to export via the Troll oil pipeline to Mongstad. Maximum production is expected to be 50,000 boe/d and investment is estimated at NOK 9.9 billion (USD 1.23 billion). The field consists of three segments and the initial development relates solely to Nova Main, with the Southeast and East segments representing future upside potential. Upon completion of the deal, interest in PL 378 is divided between Wintershall Dea Norge AS (75.76% + operator), Cairn through Capricorn Norge AS (12.12%) and ONE-Dyas Norge AS (12.12%) and interest in PL 418 and PL 418 B is held by Wintershall Dea Norge AS (45% + operator), Spirit Energy Norway AS (20%), Edison Norge AS (15%), Cairn through Capricorn Norge AS (10%) and ONE-Dyas Norge AS (10%).

Cairn (through its subsidiary Capricorn) announced on 6 August 2019 that it had sold 10% of its interest in the Nova field to ONE-Dyas for the sum of USD 59.5 million.

In October 2017, Sonatrach released the ENAFOR #16 rig, having successfully tested from its Rhourde Debdaba Profond 1 (RDBP 1) deeper-pool test. The well flowed from the Palaeozoic, at a rate of ~935 bo/d & 5.7 MMcfg/d, at a WHP of 1,450 psi. RDBP 1 was drilled on the Sif Fatima II exploration licence, in the Berkine Basin. It was spudded on 4 April 2017 and reached a TD of 5,180m (PTD 5,100m) in July 2017. The well had a primary objective in the Palaeozoic, below the Rhourde Debdaba Field. It was also exploring the northern extent of the Triassic TAGI sandstone reservoir. Sonatrach operates Sif Fatima II, which also confers exploration rights over the Rhourde Debdaba production licence, with 100% equity.

Algeria, Sif Fatima II (Dev)

KG-DWN-98/2 block, SW of the KG-DWN-M-1 (Padmavati) deepwater field, ops terminated at TD 2,652m, believed suspended, Platinum Explorer DS off location 8 Jun ’19.

G-3-E 1(AA) appr in KG-DWN-98/2 block, SW of the KG-DWN-M-1 (Padmavati) deepwater field, ops terminated at TD 2,652m, believed suspended,

In April 2018, PEMEX commenced an extended well test (EWT) of the Ixachi 1 gas and condensate discovery.  Through August 2018, the well has tested an average of 8.18 MMcfg/d and 1,146 bc/d.  The operator is conducting testing operations through the A-0269-M-Campo Perdiz production facitilities.  The highest average production rate occurred in May 2018 at 10.03 MMcfg/d and 1,442 bc/d.  The latest month average production in August 2018 was 7.1 MMcfg/d and 1,026 bc/d.  The EWT is part of the CNH approved evaluation plan.  PEMEX continues operating on the first outpost well the Ixachi 1DEL directional outpost during late-September 2018.  On 15 March 2018, the CNH granted approval for the discovery evaluation plan submitted by operator PEMEX for the Ixachi 1 new-field wildcat (NFW) gas and condensate discovery in the AE-0032-2M-Joachin-02 entitlement block in the onshore Veracruz Basin on 5 November 2017.  The evaluation plan also includes the southerly adjoining AE-0028-2M-Cotaxtla-01 entitlement.  The evaluation plan includes the firm commitments of drilling one outpost well the Ixachi 1DEL, and an extended well test (EWT).   The drilling of the outpost and the EWT will commence by April 2018.  The EWT will conclude in September 2018.  A contingent commitment is the drilling of the Ixachi 2DEL outpost well that would spud in August or September 2018.  Additional information was reported regarding the reservoir properties and the production tests conducted on the discovery well.  The Ixachi mapped structure covers an approximate area of 56 sq km.  The Ixachi 1DEL will be located approximately 4.4 km south-east of the Ixachi 1 discovery well.  The Ixachi 2DEL will be located approximately 5.2 km south-east of the Ixachi 1DEL outpost well.  PEMEX tested two intervals in the discovery well, the first from 6,560 m to 6,620 m and the second zone from 6,854 m to 6,904 m.  Both zones were stimulated with acid fracture treatments which resulted in three-fold productivity gains from the production tests with only perforations.  The highest production was reported for the upper zone and this was 29.93 MMcfg/d and 3,269.30 bc/d 40.3° API after acid-frac through a 32/64” choke. The Ixachi 1 is a high temperature, high pressure reservoir with reservoir temperature reported to be 161° C and bottom hole pressure (BHP) is 17,102 psi with a shut-in tubing pressure (SITP) of 12,780 psi.  There is 1.35% CO2 and 0.033% H2S in the reservoir fluids.  No details regarding porosity and perm was reported but they were reported to be variable, due to the various reefal facies encountered in the reservoir section. On 26 February 2018, PEMEX reported with its 4th quarter 2017 results that the well tested 28.9 MMcfg/d and 3,269 bc/d.  It also reported that it will incorporate 3P reserves in 2017 of 366.3 MMboe attributed to the discovery.     In early-February 2018, the CNH published some information on the NFW.  The CNH reported the well reached a final total depth (TD) of 7,700 m and that the productive zone is at 6,854 m to 6,904 m, in the objective Lower Cretaceous Orizaba Formation.     On 3 November 2017, PEMEX issued a press release indicating the well has estimated in place resources of 1.5 Bboe with recoverable reserves estimated to be potentially in the 350 MMboe range.     The NFW was spudded on 25 January 2017 after receiving approval from the CNH on 20 September 2016.     The well had a proposed total depth (PTD) of 7,728 m. The Middle and Lower Cretaceous Formation, Orizaba Formation, were the main objectives.     The well represents a significant Cretaceous test that represents the deepest well ever drilled in the Veracruz Basin and is a new play-opener in this area of the Veracruz Basin. The Ixachi prospect is a four way closure on a northwest to southeast trending anticlinal feature above a prominent basement high and underlying a thrust fault. The Middle Cretaceous Formation is the main objective from 6,368 m to 7,048 m and the Lower Cretaceous Formation is a secondary objective from 7,228 m to 7,498 m.  The Middle and Lower Cretaceous formations consist of a basin-ward prograding reef and associated talus facies. It is speculated to be a basin-ward continuation of the Cordoba Platform carbonate trend 20 km to the west and similar to the Golden Lane El Abra reef trend located 200 km to the north.  The nearest deep Cretaceous test drilled was the Torcaza 101A located 29 km to the northwest.  The well was plugged and abandoned with results unreported, assumed dry hole, in 1981 and a total depth (TD) of 6,741 m.  The Mecayucan 1 discovery and field is the principal analogue located 8 km northwest of the Torcaza 101A.  The well is located higher on the platform but was productive from the Lower Cretaceous.  The Ixachi 1 is a high temperature, high pressure well with target formation temperatures estimated to be 167° C and bottom hole pressure (BHP) estimated at 11,305 psi with a wellhead pressure (WHP) estimated at 4,550 psi. SENER awarded the AE-0032-2M-Joachin-02 block entitlement to Pemex 100% through Ronda 0 on 27 August 2014. The operator was granted a two year extension for the entitlement on 27 August 2017.  The block covers an approximate area of 976.40 sq km.

Mexico (Veracruz B.) Ixachi 1

S-C part of Norte de Carcará block, Santos Pre-Salt, WD 2,051m, PTD 3,215m, P&A after around a week of drilling, may be a technical well to evaluate shallow geo-hazards. West Saturn DS. Equinor (op), partners ExxonMobil + Galp.

Carcará W. U1 (9-EQNR-002-SPS) appr (special)S-C part of Norte de Carcará block, Santos Pre-Salt, WD 2,051m, PTD 3,215m, P&A after around a week of drilling, may be a technical well to evaluate shallow geo-hazards. West Saturn DS. Equinor (op), partners ExxonMobil + Galp.

Shell has been pre-awarded two blocks, following the announcement of the winners of the EGAS 2018 International Bid Round on 12 February 2019. North Sidi Gaber Offshore (2,040 sq km) and North El Fanar Offshore (2,265 sq km) lie in an under-explored part of the Nile Delta Basin, ~75-100km offshore in WD between 1,000-2,350m. They are located north and NW, of the Burullus Gas' West Delta Deep Marine (WDDM) concession (Shell 25%, PETRONAS 25%, EGCP 50%). Work commitments on North Sidi Gaber Offshore include expenditure of US$ 60 million, 1 well and 1,500 sq km of 3D seismic. A US$ 10 million signature bonus will be paid. On North El Fanar Offshore, commitments are expenditure of US$ 9 million, 2,250 sq km of 3D seismic, with a US$ 3 million signature bonus. Upon PSC signature, both blocks will be operated by Shell, in partnership with PETRONAS. Equity splits are not yet available.

Shell has been pre-awarded two blocks, following the announcement of the winners of the EGAS 2018 International Bid Round on 12 February 2019. North Sidi Gaber Offshore (2,040 sq km) and North El Fanar Offshore (2,265 sq km) lie in an under-explored part of the Nile Delta Basin, ~75-100km offshore in WD between 1,000-2,350m. They are located north and NW, of the Burullus Gas' West Delta Deep Marine (WDDM) concession (Shell 25%, PETRONAS 25%, EGCP 50%). Work commitments on North Sidi Gaber Offshore include expenditure of US$ 60 million, 1 well and 1,500 sq km of 3D seismic. A US$ 10 million signature bonus will be paid. On North El Fanar Offshore, commitments are expenditure of US$ 9 million, 2,250 sq km of 3D seismic, with a US$ 3 million signature bonus. Upon PSC signature, both blocks will be operated by Shell, in partnership with PETRONAS. Equity splits are not yet available.

Local sources confirmed in mid-March 2018 that Moesia was still looking for partners for additional funding of its planned operations in the 1-5 Devetaki, 1-7 Tarnak, 1-9 Miziya and 1-10 Botevo exploration permits in northwestern Bulgaria. It was also reported that a company from the UK was interested in a partnership with Moesia but no more details were communicated. The company communicated on 12 May 2017 that it continues with seismic reprocessing and that more than 2,000 km of data is planned to be reprocessed across all four blocks. The company anticipates to re-appraise the Devetaki field which produced gas and condensate until 2003. The 787 sq km 1-5 Devetaki, the 156 sq km 1-9 Miziya and the 281 sq km 1-10 Botevo permits were awarded on 16 April 2014, while the 253 sq km 1-7 Tarnak permit was awarded on 28 February 2014. The licensing round for the 1-5 Devetaki, 1-9 Miziya and 1-10 Botevo exploration permits was launched on in 2009. The bidding round for the 1-17 Tarnak exploration permit was launch in June 2009. In mid-May 2016 the company completed seismic reprocessing of about 1,000 km of 2D. Interest in the four permits are 100% held by Moesia Oil and Gas EOOD.  

Local sources confirmed in mid-March 2018 that Moesia was still looking for partners for additional funding of its planned operations in the 1-5 Devetaki, 1-7 Tarnak, 1-9 Miziya and 1-10 Botevo exploration permits in northwestern Bulgaria.

In early February 2018, Khalda Petroleum Co. (Khalda) abandoned the Mercury 1 (Ii018-3) wildcat in the Khalda Offset (New) B-North block as a dry hole. The well was spudded on 23 December 2017 with “EDC-17” land rig and drilled to a TD around 4,100 m in the Alam El Bueib Member. It had a planned TD of 4,115 m and objectives in the Alam El Bueib Member. The Khalda Offset (New) block is held by Khalda with a 100% interest.  

Egypt (Shoushan Sub-basin (Northern Egypt B.)) Khalda

AziPac continued to offer a farm-in opportunity in the North Madura PSC, located in offshore East Java Basin, in April 2018. The company is planning to drill a commitment well in the block, likely in 2018. The well, Ratna 1, will primarily target Kujung carbonates with prospective resources of 450 Bcfg. Drilling cost are estimated at around USD 8 million on a dry-hole basis. The block is located near producing fields such as Ujung Pangkah (Pangkah PSC, operated by Saka Energi) and KE-5 (West Madura Offshore PSC, operated by Pertamina Hulu Energi). AziPac is operator and sole interest holder in the block after the acquisition of 50% interest from outgoing operator AWE in March 2016. The company received a four-year exploration extension for the North Madura PSC, effective on 18 May 2016. The last exploration activity in the block was a 400 sq km 3D seismic survey. Acquisition was done using “PGS Apollo” S/V, utilizing dual sensor broadband technology. It was part of the multi-client survey project, with a total survey area of 2,536 sq km, which also covers North Madura II and Ketapang blocks, operated by Petronas Carigali.   The previous exploration activity in the block was a 350 km 2D seismic survey in September 2014. Future exploration activities could be targeting deeper potential reservoirs of the Eocene Ngimbang Carbonate Formation, in addition to the shallower Kujung carbonates. Moyes & Co is Azipac’s representative for this opportunity. Interested parties may contact: Ian Cross Managing Director Email: [email protected] Tel: +65.9776.0753  Background Information The North Madura block was offered on 30 November 2009 as part of the Second Petroleum Bidding Round 2009 under the direct offer mechanism. Preliminary award for the block was made on 14 May 2010. The North Madura PSC was officially awarded to AWE (50%, operator) and Black Platinum Energy (50%) on 18 May 2010. Mitra Energy then farmed-in and acquired 25% interest from Black Platinum on 9 June 2011. Firm commitments for the first three years of exploration include G&G studies (USD 0.4 million), and drilling of one exploration well (USD 8 million). Signature bonus for the block was USD 1 million. The block covers an area of approximately 625 sq km following the second partial relinquishments in 2016 and comprises two separate areas in shelf water. It is adjacent to Pertamina’s West Madura Offshore PSC, which includes Poleng and KE 6 oil fields and KE 5 gas field and to Petronas Carigali’s Ketapang PSC, which includes the Bukit Tua oil and gas field. Several sub-blocks were previously covered by the Pangkah PSC, currently operated by Saka Energi. AziPac initially entered the block in October 2015, acquiring a combined 50% interest from Mitra Energy (25%) and North Madura Energy Limited (25%), a wholly-owned subsidiary of Black Platinum Energy.

AziPac continued to offer a farm-in opportunity in the North Madura PSC, located in offshore East Java Basin, in April 2018. The company is planning to drill a commitment well in the block, likely in 2018. The well, Ratna 1, will primarily target Kujung carbonates with prospective resources of 450 Bcfg.

Bridgeport Energy Ltd was awarded exploration licence PEL 641, located in the Cooper-Eromanga Basin, on 9 February 2018.  The permit has been awarded for a period of five years and will expire, or be eligible for renewal, on 8 February 2023. Bridgeport applied for the permit in August 2014, after it was offered in the 2013 South Australia Cooper Basin Acreage Release as block CO2013-C. Work commitments have been assigned for the duration of the permit’s validity and will include 200 km new 2D and 200 sq km new 3D seismic in years one and two respectively, plus five exploration wells: one in year three, between February 2020 and February 2021 and two in each of years four and five. The licence are contains part of the Maslins oil discovery, which was made in 2002, though reservoir quality was considered to be low. PEL 641, which covers an area of 1,953 sq km, was awarded on 9 February 2018.  Bridgeport (Cooper Basin) Pty Ltd holds 100% interest and operatorship of the licence.

Bridgeport Energy (100%) was awarded exploration licence PEL 641.

PPL 43, Cooper Eromanga, drilled and P&A gas shows 18-29 Jun ’19, TD 3,001m, Ensign rig 970.

Taylor S.-2 appr PPL 43, Cooper Eromanga, drilled and P&A gas shows 18-29 Jun ’19, TD 3,001m,

Tatneft has reportedly signed with Uzbekneftegaz for initial exploration efforts in the Pritashkentsky block, believed to be the former XLVII Tashkent block partly in the Syr-Darya Basin + partly in non-prospective territory. In the event of a commercial find, Tatneft will have right of 1st refusal on PSC rights or negotiate a JV agreement with Uzbekneftegaz. Meanwhile Tatneft has also signed to embark on EOR for the older Andizhansky, Palvantazhsky + West Palvantazhsky fields (aka Andizhan, Palvantash + Palvantash Garbiy) in the Fergana Basin. The above are the result of an Uzbekneftegaz offering of prospective blocks to IOCs.  Total, Novatek, BP-Socar, Mubadala + Eni are also either interested or already negotiating opportunities.

Tatneft has reportedly signed with Uzbekneftegaz for initial exploration efforts in the Pritashkentsky block, believed to be the former XLVII Tashkent block partly in the Syr-Darya Basin + partly in non-prospective territory.

RockRose Energy has signed a sale and purchase agreement to acquire the entire issued share capital of Idemitsu Petroleum UK from Idemitsu Kosan, a Japanese corporation. The Acquisition will be funded out of the existing facilities and cash resources of the Company.  Completion of the Acquisition is conditional upon confirmation from the UK Oil and Gas Authority that there is no objection to change of control. The Idemitsu UK's assets comprise, inter alia, a substantial number of producing fields in the North Sea which include: The Acquisition also brings with it a number of key employees and its premises in London, which will enhance RockRose's internal expertise providing continuity on the acquired assets and assisting with the management of the wider portfolio. On closure of this Acquisition and previously announced transactions, RockRose will have a projected 6,200 - 7,000 boepd of production in 2018 on an aggregated basis. Andrew Austin, Chairman of RockRose said: 'RockRose is continuing to deliver on its stated strategy of building a business through the acquisition of mature producing assets. We believe that this acquisition is a significant one for the Company and that this portfolio also has a lot of potential for extended field life and gives Rockrose access to significant tax losses. 'We continue to review further acquisition opportunities in North West Europe and, post completion of this along with the previously announced Maersk, Sojitz and Egerton transactions by the end of this year, will have established a material business in the North Sea, set to deliver value to our shareholders.' The Acquisition constitutes a reverse takeover for the purposes of the listing rules, the Company has requested that the UK Listing Authority to suspend the listing of the shares with immediate effect. The Company will proceed to prepare and publish a new prospectus in the coming weeks which will include a competent persons report on the assets of the Company as enlarged by the Acquisition. Further details and updates on the Acquisition will be released in the near future. Original article link Source: RockRose Energy

RockRose has agreed with Idemitsu for the purchase of the latter’s UK sub issued share capital. This involves interests in Repsol’s Tain (50%), Burghley (41,1%), Beauly (40%), Ross (30,8%), Black (30,8%), and Galley (17,4%) fields, in Shell’s Howe (20%) and Nelson (7,5%) fields, and in Premier’s Balmoral (6,7%) and Stirling (16%) fields. No value is revealed.

Oil of DRC (Caprikat - Foxwhelp JV) is negotiating the sale of its 85% interests in to blocks I + II to an undisclosed buyer. Both lie in the E. part of the country, Albertine Graben. The move has its roots in US sanctions imposed on the Dan Getler Group, owner of Caprikat and Foxwhelp. So far Oil of DRC (op), govt partner.

Democratic Republic of Congo, Oil of DRC (Caprikat - Foxwhelp JV) is negotiating the sale of its 85% interests in to blocks I + II to an undisclosed buyer. Both lie in the E. part of the country, Albertine Graben. The move has its roots in US sanctions imposed on the Dan Getler Group, owner of Caprikat and Foxwhelp. So far Oil of DRC (op), govt partner.

PetroChina – Tarim made an important discovery in the Tarim Basin. Manshen 1 tested 4,430 b/d of oil and 13 MMcf/d of gas through a 10 mm choke at a depth around 8,000 m in the Ordovician-Cambrian carbonate formation in early April 2020. During drilling the well penetrated 54 m oil/gas pay. Manshen 1 discovery made a breakthrough in the basin, it indicated a deep carbonate play fairway with 3,520 sq km where would have 1.6 bn bbl of oil geological resources. The well, geologically, is located between the Tabei and Tazhong uplifts and has target in deep Ordovician-Cambrian formations. It is a frontier area in the basin and few wells have been drilled. According to IHS Markit data, Mancan 1 drilled in 1992 and Xiaotang 1 in 2008 around this area, both wells drilled to below 6,000 m but without discovery. In addition, PetroChina drilled Mancan 2 in this area but without details available. In early 2019 PetroChina made an important discovery, Luntan 1, in the Tarim Basin. The well tested 840 b/d of oil and 1.7 MMcf/d of gas at a depth between 8,203 and 8,260 m after acidizing fracture in the deep sub-salt Wusonggeer Formation of the Cambrian, as a play opener well in the basin. PetroChina started commercial exploration activities 30 years ago in the Tarim Basin, by end 2018 the company has approved about 7 bn bbls of oil and 60 Tcf of gas in place. In 2019 PetroChina made a significant achievement oil and gas production and produced at 113 Mb/d of oil and 2.8 Bcf/d of gas, comparing 110 Mb/d and 26 Bcm in 2018. PetroChina has a plan to produce at 120 Mb/d of oil and 3 Bcf/d of gas by 2020 in the Tarim Basin.

China, not found

Zawtika-25, block M-09, Moattama Basin, WD 120m, P&A results n/a (though tested) in late Jul ’19, TD 3,450m, Noble Clyde Boudreaux SS off to Zawtika-26  6km to the SE, spudded end Jul ’19. PTTEP (op), partner MOGE.

Zawtika-25, PTTEP (op), partner MOGE, block M-09, Moattama Basin, WD 120m, P&A results n/a (though tested) in late Jul ’19, TD 3,450m,

Block 10 in Basra, S. Iraq, tested ab. 9,500 bo/d from the Mishrif fm. Plans include several more appr’s + complete 3D seismic over the Eridu field area, and 2D seismic will follow in the S + C parts of the block. Lukoil (op), partner Inpex.

Eridu 5 (Aredo) appr (Lukoil 60% op, Impex 40%) in Block 10 in S. Iraq, tested ab. 9 500 bo/d from the Mishrif fm. Plans include several more appr’s + complete 3D seismic over the Eridu field area, and 2D seismic will follow in the S + C parts of the block.

Bozhong 29-6S-3 (BZ 29-6S-3) was suspended, having intersected oil in the target reservoirs, in late April 2018 after having been spudded in mid-April 2018 using the "Bohai 5" jack-up. The oil appraisal well was likely targeting the Guantao, Dongying and Shahejie formations with the objective of appraising the westerly extension of the Bozhong 29-6S-1 oil discovery made by CNOOC in February 2017, which encountered approximately 33m of net oil pay. Bozhong 29-6S-3 is in the CNOOC operated Bonan Block in the offshore Bohai Gulf Basin and is approximately 9km W of Bozhong 29-6S-1. <P />

Bozhong 29-6S-3 (BZ 29-6S-3) was suspended, having intersected oil in the target reservoirs, in

On 31 July 2019, Eni SpA and BP plc announced that they had signed an exploration and production sharing agreement (EPSA) with the Ministry of Oil and Gas for Block 77. The block covers an area of >2,700 km and is located 30 km to the east of Block 61 (Khazzan-Makarem Gas Field). Eni Oman (a wholly owned subsidiary of Eni SpA) will act as operator during the exploration phase and both companies will take a 50% share.  The two companies had entered into a Heads of Agreement (HoA) for the block in January 2019. Block 77 contains a number of existing discoveries and fields including Qarn Alam, Ghaba North and Saih Nihayda Southeast.

Eni SpA and BP plc announced that they had signed an exploration and production sharing agreement (EPSA) with the Ministry of Oil and Gas for Block 77.

Buru is looking to dilute its interests in EP 391, 428, 431, 436, 457 + 458, total ab. 20,500 sq km in the Fitzroy Graben, Canning Basin, up to 50% (non-operated) on offer. All are wholly-owned bar EP 457 + 458 (Buru op, 60%, partner Rey Resources). Contact: [email protected].

Buru is looking to dilute its interests in EP 391, 428, 431, 436, 457 + 458, total ab. 20,500 sq km in the Fitzroy Graben, Canning Basin, up to 50% (non-operated) on offer. All are wholly-owned bar EP 457 + 458 (Buru op, 60%, partner Rey Resources).

Total (30%) has exited licence K01c to operator ENGIE as of 24 January 2018. The exploration licence covers 274 sq km and is located 5 km N of the K01-A and K04-A producing gas fields, both operated by Total. ENGIE has until 1 July 2018 to decide if to drill K01c, with drilling operations to be completed by 4 January 2019. K01c was awarded to GDF SUEZ (renamed ENGIE in April 2015) and Total for four years initial period, commencing 2 January 2012. The two companies had submitted a joint application for the acreage in November 2010 and the Ministry of Economic Affairs received no competing bids during the public tender period. Three dry exploration wells have been drilled on the acreage between 1979 and 2006. On 11 May 2017, ENGIE received a binding offer from Neptune Energy to acquire a 70% interest in its E&P division, and is pending completion. K01c licence partners are ENGIE E&P Netherlands BV (60% + Op) and Energie Beheer Nederland (EBN) (40%).

Total (30%) has exited licence K01c to operator ENGIE

In early-2020, official maps published by state company ANCAP showed some changes to the blocks that are being offered in the country's Uruguay Open Round. Specifically, three onshore blocks (ON-3, ON-4, and ON-5) have been modified to include new acreage from areas that were relinquished by Schuepbach Energy International and a new offshore block, OFF-7, has been added in the former Area 15 license that was relinquished by Tullow Oil in mid-2019. In June 2020, ANCAP announced that it has awarded OFF-1 to Bahamas Petroleum Company and approved the offers for OFF-2 and OFF-3 from Kosmos Energy, although the signing of the corresponding contracts for the latter two blocks is being delayed due to the current coronavirus disease 2019 (COVID-19) pandemic. As of mid-June 2020, there are nine available blocks covering approximately 87,354 sq km of area with five onshore blocks (25,767 sq km) and four offshore blocks (61,587 sq km), specifically. The five onshore blocks were created from the combination and rearrangement of the ten available open areas in Chaco-Parana Basin that have been offered since 2014 in a previous open round. Each of the new onshore area included at least one P&A’d new-field wildcat well from the 1930’s and the 1980’s, except ON-3 block which had no NFW wells and only stratigraphic wells from 2012 and 2013. Uruguay Open Round (onshore)   Block Name Main Basin Area (sq km) ON-1 Chaco-Parana Basin 5,021 ON-2 Chaco-Parana Basin 4,424 ON-3 Chaco-Parana Basin 6,677 ON-4 Chaco-Parana Basin 5,456 ON-5 Chaco-Parana Basin 4,189   Meanwhile in offshore, four blocks are offered with water depths ranging from 50 m to over 4,000 m in the Pelotas, Rio Salado, and the margin of Argentina Basin. Outside of the aforementioned new OFF-7 block, all of the other blocks covered areas that were previously offered in the last Round 3 offshore round in 2018, in addition to areas that were relinquished by Total (Area 14) and Shell (Area 8, 9, and 13). OFF-6 block includes the most recently drilled Raya 1 well that was P&A’d by Total in 2016. Uruguay Open Round (offshore) Block Name Main Basin Area (sq km) OFF-4 Rio Salado Basin 10,000 OFF-5 Pelotas Basin 16,848 OFF-6 Pelotas Basin 16,519 OFF-7 Pelotas Basin 18,220   The biannual open round process was originally launched in May 2019 with six blocks offshore and five blocks onshore. The exploratory period reportedly will have a term of up to 11 years, with no drilling commitment in the first and second phase (the first six years), then followed by 30 years of exploitation period with possibility of a ten-year extension. The round will be open continuously, with offers opened at the end of the month in May and November of every year. Interested companies will need to qualify one month prior to the deadline for the submission of bids and submit a bid with their proposed work program for the first exploration period, profit oil split with the Uruguayan government, and ANCAP’s association percentage. More information regarding the Uruguay Open Round can be obtained by contacting ANCAP at [email protected] . Background Information According to reports in June 2018, Uruguayan Minister of Industry, Energy and Mining was considering an open round process to offer the country’s offshore blocks after the Uruguay Round 3 offshore round was declared with no bids received. Meanwhile, the country also has been offering opportunities on its onshore blocks through an open door round process since 2014, although no offers have ever been received since it was launched.

In early-2020, official maps published by state company ANCAP showed some changes to the blocks that are being offered in the country's Uruguay Open Round. Specifically, three onshore blocks (ON-3, ON-4, and ON-5) have been modified to include new acreage from areas that were relinquished by Schuepbach Energy International and a new offshore block, OFF-7, has been added in the former Area 15 license that was relinquished by Tullow Oil in mid-2019.