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On 1 July 2019, Gazprom registered a new long-term license offshore Sakhalin. License ShOM16554NR, valid until 1 July 2049, granted exploration and production rights for the Tsentralno-Pogranichnyy block in the North Sakhalin Basin. Based on the current legislation, license was awarded without an auction meaning that Gazprom’s competitor Rosneft was not applying for the area. Tsentralno-Pogranichnyy covers 6,320 sq km south of the Kirinskiy block where Gazprom reported three gas discoveries including giant Kirinskoye Yuzhnoye during the last decade. The area encompasses several big structures which need to be confirmed by 3D seismic. Water depth ranges from 0 m at the Sakhalin coast to 300 m in the east.

Gazprom secured rights auctionless to the Tsentralno-Pogranichnyy block (licence ShOM16554NR), 6320km², south of the Kirinskiy block where Gazprom reported three gas discoveries including giant Kirinskoye Yuzhnoye during the last decade. The area encompasses several big structures which need to be confirmed by 3D seismic. WD from 0 to 300 m in the east.

Oilex has announced substantial progress has been made towards the Company’s strategic objective to regain a participating interest in the West Kampar PSC in Indonesia, which is expected to lead, subject to financing, to recommencing production from the Pendalian oil field.West Kampar PSC Location Map, Sumatra, Indonesia (Source: Oilex) Following various meetings and correspondence with the Government of Indonesia (GoI) and with the support of our local Indonesian partner, the GoI has advised that the Company's Proposed Direct Bid, through the Joint Study of the West Kampar Region, is declared administratively complete and have recorded it as a proposal for a Direct Offer through a Joint Study as stipulated in ESDM Regulation No. 35 of 2008. This confirmation from the GoI, which is exclusive to Oilex, provides a pathway to conduct the Joint Study on the proposed development of West Kampar which will then provide certain preferential rights in the ultimate award of the West Kampar PSC by the GoI. Oilex’s interest in the study and ultimate potential award of the PSC will be on a 50-50 joint basis with its local Indonesian partner, PT Ephindo. Further information will be provided when it becomes available.Location Map Central Sumatra Basin Fields and Pipeline Infrastructure (Source: Oilex) Background The West Kampar PSC, covering some 900 sq kms, is located in central Sumatra, adjacent to the most prolific oil producing basin in Indonesia. In 2007 Oilex farmed into the PSC for a 45% Participating Interest (PI).The operator for the joint venture was Indonesian company Sumatera Persada Energi (SPE). In the same year, the joint venture successfully drilled an appraisal well on the earlier discovered Pendalian oil field confirming oil flow at commercial rates. In 2008 Oilex signed a second farmin agreement to earn an additional 15% in the PSC.Oilex contributed funds to the joint venture account under both of these farmin arrangements.With increasing concerns related to the operator’s performance, Oilex terminated the second farmin in 2009, requesting repayment of the relevant funds.Subsequently Oilex served a default notice on the operator and commenced arbitration against SPE’s parent company in the ICC International Court of Arbitration in Singapore.In 2010 the arbitration tribunal ruled in favour of Oilex, instructing SPE’s parent company to return funds to Oilex with interest along with arbitration and legal costs.While the arbitration was registered in the Indonesian courts, the enforcement of the tribunal’s award proved to be unachievable to date. Between 2010 and 2016, SPE produced and sold close to 700,000 barrels of oil, with no entitlements returned to Oilex.The operator failed to call any joint venture meetings nor did it provide work program, budgets, data or reports.In late 2016, SPE was declared bankrupt and Oilex submitted its claims as a creditor to the Curator (liquidator).In 2018, the GoI elected to withdrawthePSCfollowing whichOilex made a number of representations to the GoIin support of its application to be re-awarded the PSC and to restart production from Pendalian and also to re-evaluate the exploration potential of the West Kampar. Technical work carried out by Oilex and its advisors estimate that the field can be quickly brought back online at 350 to 400 bopd and that significant additional production potential may be possible from infill drilling and also water injection support. The return to production will require careful execution in the field given that it has been shut in since 2016. The oil occurs in five good quality, stacked reservoirs with some stratigraphic complexity, and the application of 3D seismic data which has been acquired but not interpreted, should provide a significant improvement in the understanding of the reservoir distribution and future development planning. Access to the data is to be negotiated with the seismic company that acquired it. The oil is good quality with no or little gas.It is believed that the previous production costs can be reduced.A number of exploration opportunities are present both close to the Pendalian field and in the more distant parts of the block, these require further review evaluation. Original article link Source: Oilex

Indonesia (Central Sumatra B.) Kampar PSC op. by PERTAMINA (100%)

Penglai 13-2-6d (PL 13-2-6d) was suspended, having intersected oil in the target reservoirs, on or around 18 July 2019 after having been spudded on or around 8 July 2019, using the "Haiyangshiyou 921" jack-up. The deviated oil and gas appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations. Penglai 13-2-6d is in the CNOOC operated Bozhong 06 Block in the offshore Bohai Gulf Basin.<P />

Penglai 13-2-6d (PL 13-2-6d) was suspended, having intersected oil in the target reservoirs, The deviated oil and gas appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations. Penglai 13-2-6d is in the CNOOC operated Bozhong 06 Block in the offshore Bohai Gulf Basin

PEL 155, Penola Trough, Otway Basin, TD 4,300m, 65m gross gas column identified in the target Pretty Hill fm, moveable gas not confirmed, Easternwell rig 106. Otway (op), partner Vintage Egy.

Nangwarry 1 expl. (Otway Energy 50%, op. Vintage O&G 50%) in PEL 155, gas disc. 120m of saturated gas column, within the Upper Pretty Hill Fm. and there is a possible 160m gas column within the mid-Pretty Hill section.

DeSoto Canyon block 357 (lease G36281), WD 2,386m, drilled 2-22 Dec 19, West Vela DS departed. BP’s plan provides for the drilling of up to 8 wells in blocks 357 (lease G36281), 358 (G36282) + 401 (G36284).

DC 357 001S0B0 (Johanna) expl. (BP 100%) in lease G36281 (DeSoto Canyon block 357), WD=2386m, BP’s plan provides for the drilling of up to 8 wells in blocks 357 (lease G36281), 358 (G36282) + 401 (G36284). P&A, results n/a yet.

Further to yesterday’s DEA, FEL 3/18, Deepwater Porcupine High off SW Ireland, WD 2,160m, now confirmed dry, Stena IceMAX DS. CNOOCI (op), partner ExxonMobil.

052/04-A (Iolar) (CNOOC 50% op, ExxonMobil 50%) in FEL 3/18 licence, as of 15 August 2019 it was confirmed that operations were complete and the rig had left location. Now confirmed dry.

On 29 June 2020, Petrobras published a teaser to sell its working interest in the Tartaruga field, in the shallow waters of the Sergipe-Alagoas Basin. Petrobras holds 25% working interest in the field and Maha Energy Brasil Ltda is the operator with 75% working interest. The concession was officially awarded in August 1998 during the ANP Round Zero. Interested companies must submit the customary manifestation of interest by 17 July 2020 and qualification documents by 31 July 2020 to [email protected] The offshore Tartaruga field was discovered by the 1-SES-107D-SES new-field wildcat (NFW) on 22 December 1994. The well spudded on 5 July 1994 and targeted primarily, Early Cretaceous sandstones of the Penedo Formation, and secondarily Jurassic sandstones of the Serraria Formation. The field produces mainly light crude oil of 37-degree API since October 1999. Installations for the field are located inland, with production coming from directional wells. Petrobras indicated that average production from January to May 2020, was approximately 580 bopd.

(Sergipe-Alagoas B.) Tartaruga op. by MAHA EN (75%), PETROBRAS (25%), On 29 June 2020, Petrobras published a teaser to sell its working interest in the Tartaruga field, in the shallow waters of the Sergipe-Alagoas Basin. Petrobras holds 25% working interest in the field and Maha Energy Brasil Ltda is the operator with 75% working interest.

Nashpa 3370-10 EL, Potwar, P&A at TD ca. 4,500m early Sep ’19 after testing earlier this year, Hilong rig 2. PTD was 5,750m. OGDC (op), partners PPL + Govt Holdings.

Shawa X-1ST2 Op. by OGDCL (65%, PPL 30%, GHPL 5%) in Nashpa 3370-10 EL block, P&A, Results unknown

Shell Australia announced on 21 Novemebr 2018 that it had reached an agreement to sell its 26.56% interest in the Greater Sunrise asset to the East Timor Government.  Shell becomes the second company to sell its interest in the project to the government, after ConocoPhillips reached a similar agreement in October 2018. The sale and purchase agreement entered into by Shell and the East Timor Government, values the interest at USD 300 million (AUD 414 million).  Shell reported that the sale is in line with its global strategy, which is seeing it become a “simpler and more resilient company”. The sale and purchase agreement is conditional on a number of conditions, including regulatory approvals, joint venture pre-emption rights and funding approvals. Upon completion of the deal, Shell will assign its 26.56% interest in permits JPDA 03-19, JPDA 03-20, NT/RL2 and NT/RL4 to the East Timor Government.  The JPDA contracts are, at this stage, within the previous-Joint Petroleum Development Area (JPDA) waters.  These will be renegotiated as East Timor PSCs, after the new maritime boundary was outlined in March 2018. These are expected in late 2018/early 2019. The permits contain the Sunrise and Troubadour discoveries, that make up the Greater Sunrise assets.  The discoveries were made in 1975 and 1974 respectively and contain over 5 Tcf gas and 225 MMb condensate. Shell’s sale comes after ConocoPhillips reached an agreement to sell its 30% interest in the assets to the East Timor Government, though this also remains subject to similar conditions to the Shell sale.  Both companies outlined that they differed in opinion with the East Timor Government over how the Greater Sunrise fields should be developed. Shell reported that it “[understood] the priorities of the Timor-Leste Government”. The development scenario for the fields has been long debated, with the Greater Sunrise joint venture (JV) preferring a Floating LNG (FLNG) option, over the East Timor Government’s suggestion to pipe the hydrocarbons back to an onshore plant in East Timor.  The JV have indicated this would be more costly, but also difficult as a development due to the bathymetry between the discoveries and East Timor. Both deals will have significance, as the East Timor Government has outlined that its preference remains, and with greater interest in the project it will have additional input into the development decisions. Upon announcement of the initial transaction, the East Timor Government reported that it would proceed with further discussions with the JV to evaluate the future development.  Woodside, operator of the assets, has indicated that the project falls under its “Horizon III” planned developments, which are scheduled for post-2027.   The Great Sunrise fields have been under discussion for development for some time, with Woodside initially planning to make a decision in 2009.  However a number of issues, including differing opinions in the development scenario, disputes around the maritime boundary and drop in oil price have pushed the development back a number of times.  Woodside has had several discussions with the East Timor government over the development, looking to come to an agreement. However the maritime boundary dispute put this on hold with Woodside reporting that it would wait for a resolution.   A new maritime boundary was agreed and the initial documents signed in March 2018.  The boundary is expected to be finalized and put in place in late 2018/early 2019.  The new maritime arrangement has included a “Special Regime” for Sunrise, which will see East Timor get at least 70% of the government revenues from the development, with the split to be 70:30 (in favour of East Timor) if the development sees a pipeline to East Timor, and split 80:20 if a pipeline to Australia is utilised.  It is not known if this will alter if the government has a stake in the project. Participants in the Greater Sunrise joint venture are: Woodside Petroleum Ltd (33.44% + Operator), OG ZOKA Ltd, a wholly owned subsidiary of Osaka Gas Co Ltd (10%) and Shell Australia Ltd (26.56%) and ConocoPhillips (30%) – both selling their respective shares to the East Timor Government.

Timor Sea JPDA, JPDA 03-20

Investment company Legendary Investments PLC is to acquire a 2% stake in the offshore Mahdia PSC, from operator Circle Oil Tunisia Ltd (COTL). The deal was agreed in late-December 2017 and is for a cash sum of PS100,000 (c.US$ 130,000). The management of COTL will also gain Legendary's stake in a gold project in Kyrgyzstan, via Manas Resources LLC. The 3,024 sq km block is located in the Gulf of Hammamet, north of Lampedusa Island. The PSC was originally signed between Circle Oil (70% + Op) and Tethys Oil & Mining (30%) on December 2009. The concession agreement was converted from a previously held prospecting permit. In 2013, Circle acquired the remaining 30% stake from Tethys, in a US$ 3 million deal. In August 2014, the company drilled the El Mediouni 1 (EMD 1) NFW (TD 1,200m, WD 216m). It encountered a 133m gross oil column in Miocene Birsa sandstones and Ketatna carbonates. A farm-out campaign in order to develop the discovery was launched, but failed to attract any offers.On 15 March 2016, Circle Oil announced that it had initiated a formal strategic review of its business and assets in order to reduce its debt, which stood at a total of US$ 77.5 million at the time. The company stated in May 2016, following a review of proposals to date and the debt situation that, "it is likely that there will be little or no value attributed to Circle Oil plc holders." The company's shares were suspended on 29 June 2016 and cancelled in December 2016. In late-January 2017, SDX Energy completed the acquisition of Circle's Egyptian and Moroccan assets, with the detailed fate of its Tunisian assets unclear. However, it now appears that the company's Tunisian assets have been restructured and are under new management, with Circle Oil Tunisia Ltd (COTL) operating as an independent entity. At the time of share cancellation, the company also held non-operated equity in the Ben Khaled (30%) and Ras Marmour (23%) licences, in partnership with Exxoil SA. The fate of these assets is unresolved.UK-registered Legendary Investments is listed on the London AIM. The acquisition is the company's first foray into the oil & gas industry.

Tunisia, Mahdia

On 14 July 2017 Vermilion started sidetracked exploration well Eesveen 2 in the Steenwijk licence after permanently abandoning the lower part of the Eesveen 1 well using DrillTec’s “Explorer TB 2100S” rig. It is believed that the well found gas at Eesveen North. The well encountered 24 m of net pay in two separate intervals in Zechstein carbonates and Rotliegend sandstones. The two zones were flow tested at a combined rate in excess of 1,800 Mcfg/d. The operations were completed on 17 August 2017. Vermilion started production from its Eesveen gas field which straddles the Steenwijk and Drenthe VI concessions in April 2015. Initial treatment (separation of the gas and condensate from water) takes place at the Eesveen location and then the well stream is piped to the Garijp processing facility. Eesveen was discovered in 1986 and it has a Rotliegendes Slochteren Sandstone reservoir, approximately 23 m thick with a GWC at 2,045 m TVDSS. A test carried out at that time by operator NAM concluded that the discovery was uneconomic. However, in 2005 Vermilion re-tested the well (Eesveen-1) and these results, together with new 3D seismic acquired later, led to the development of the field. Vermilion is expecting to recover 75% of the gas in place over a period of 2-5 years. Interest in the Steenwijk permit is held by Vermilion Oil & Gas Netherlands BV (50% + operator) and Energie Beheer Nederland BV (50%).  

Netherlands (Northwest German B.) ? op. by VERMILION (50.0%, EBN 50.0%) in Steenwijk block

Ref. DEA 26 Jul '19, IOG's GBP 40 MM farmout to CalEnergy Resources of a 50% interest in much of its upstream assets is now completed, IOG retaining operatorship. The deal includes the Thames pipeline and associated Thames reception facilities but excludes the Harvey licences. CalEnergy has a GBP MM carry of IOG’s Phase 1 development costs for its Core Project, of which Phase 1 FID has also been taken (410 BCF of 2P+2C resources across 6 SNS gasfields).

United Kingdom, Thames

On 30 April 2019, the Gambian government announced the award of Block A1, deep waters of the MSGBC Basin, to BP. This award is a result of the bid round for six exploration blocks which was launched in early 2018. Block A1 covers 1,300 sq km, it is awarded for an initial period of two years during which BP will complete an environmental assessment followed by exploration activities up to and including the drilling of one exploration well. Block A1 is adjacent to the south of the Woodside-operated Sangomar Offshore Deep block in Senegal where the SNE oil field is currently being developed. Block A1 is also adjacent to the west of Block A2 where Petronas found some oil shows in the Samo 1 wildcat in November 2018. Of note also is that the Gamm 1 well currently drilled by Total in the Rufisque Offshore Profond block lies in a similar geological environment to the Block A1. On 1 May 2019, African Petroleum, former right-holder to Block A1, announced that it continues to reserve its rights in relation to the A1 licence. On 16 October 2017 African Petroleum reported that it is in the process of commencing arbitration proceedings to protect its 100% interest in blocks A1 and A4. It is understood that by that time, African Petroleum’s permit for blocks A1 and A4 had been cancelled by the Gambian authorities. As of May 2019, the arbitration proceedings are believed to be still ongoing.

BP signed a contract (followed The Gambia’s 2018 acreage promotion) for Alhamdulilah Block A1 (1300km²), located in DW offshore and currently under an arbitration process with African Petroleum who claims rights to blocks A1 + A4. The Company continues to reserve its rights in relation to the A1 licence and will continue with its efforts to protect its interest.

Khalda Offset (New) A-West block, N. Egypt Basin, drilled 29 Nov '19 – Feb '20, TD 4,420m (Shifah fm), successfully tested the Alam El Bueb.

Barakat Deep 2 appr. (Khalda 100% = JV between EGPC 50%, Apache 33.5%, Sinopec 16.5%) in Khalda Offset (New) A-West block, successfully tested the Alam El Bueb. TD=4420m (Shifah fm).

Joint venture partners Murphy Oil Corp and Santos Ltd will be looking to farm out equity in Bight Basin exploration permit: EPP 43, from Q3 2018.  The companies reported that once detailed prospect mapping is complete, it will look to farm down the permit. Murphy operates the permit and holds a 50:50 equity share with Santos. EPP 43 covers an area of 16,600 sq km in the western flank of the Ceduna Sub-basin. The permit was awarded on 22 October 2013 and, after two validity extensions in October 2015 and December 2017, is scheduled to expire on, or be eligible for renewal by, 21 October 2022. The 2015 suspension and extension combined the first three years of work requirements into one term (1-3).  After the second extension in December 2017, these are now required to be completed by 21 October 2019.  Murphy planned for a 2,000 sq km 3D seismic survey within the first term followed by 4,600 km 2D seismic survey in the third term. In April 2015 the acquisition of 7,367 sq km of 3D seismic data was completed within the permit during the PGS Springboard MC3D survey. A total 8,012 sq km of data was acquired across EPP 43 and BP operated permits EPP 37 and EPP 38. After the initial three-year work programme in EPP 43, permit terms four, five and six will follow with the work requirements to be completed on a year-by-year basis. Once a permit term has commenced, the work specified must be completed. One exploration well has been scheduled to be drilled in term five at a forecasted cost of AUD 50 million. The commitment to drill the well must be made prior to the commencement of that term which currently starts on 22 October 2020. The joint venture will seek farm-in partners to assist with the forthcoming exploration programme. The permit bathymetry varies from around 200 m in the north to nearly 3,000 m depth in the south. Murphy has both deep water and frontier exploration experience and is comfortable with retaining operatorship. As prospects emerge from the detailed mapping of the 3D Springboard survey data in the end 2017, farm-down activities will commence. Targets will be oil-focused as a function of the less extreme basin subsidence of the permit area compared to the more central Bight Basin blocks. Gnarlyknots 1/1A is the closest deepwater well to EPP 43. The well lies 150 km to the east and was drilled in 2003 by Woodside Energy with the 1A well reaching a total depth of 4,736 m. The well was dry and currently lies within the Chevron operated EPP 44 permit. Chevron announced on 12 October 2017 plans to withdraw from any further Bight Basin exploration. BP Australia had held interest in the basin, with two solely owned permits as of 2017.  However in December 2016 BP reported its plan to withdraw its exploration programme in the Bight Basin stating that the programme no longer suits its global strategic plan due to high costs and core asset selection. BP had a ten well drilling campaign scheduled between 2016 and 2020, starting with the deep Stromlo gas prospect which lies within approximately 2,200 m water depth, 300 km southeast of Ceduna. BP claimed that the geology is synonymous to the river delta systems in Nigeria and the Gulf of Mexico, with targets around 2,000 m beneath seabed in Cretaceous units. The Stromlo Prospect now lies in Equinor held permits, with the operator looking at plans for drilling. Murphy holds 50% interest and operatorship in EPP 43 through subsidiary company Murphy Australia Oil Pty Ltd. Joint venture partner Santos holds the remaining 50% interest through its subsidiary company Santos Offshore Pty Ltd. The joint venture will be seeking to farm-down equity in EPP 43 from early 2018. Companies interested in pursuing this opportunity should contact: Paul Carroll, Exploration Manager – Murphy Oil Corp Phone: +61 8 6313 5200 Email: [email protected]

Murphy Australia Oil Pty Ltd, Santos Ltd set to open a farm-in opportunity in the Bight Basin

On 16 May 2019, the Argentine government granted CAN-114 block to Equinor following the company’s offer of USD 47.42 million in Round 1 of the country’s offshore bid round that ended on 16 April 2019. Equinor will operate the block with 50% participating interest, with state company YPF as partner with the remaing 50%. Work program for the first exploration period is assumed to be limited to seismic work, as there is no drilling commitment required by the government for blocks offered in Round 1 until the second exploration period. The CAN-114 block area is relatively unexplored with no discoveries or significant wells other than two wells that were drilled and P&A’d with oil & gas shows by Union Texas in CAN-109 in the mid-1990’s. CAN-114 covers 7,085 sq km of ultra-deepwater area in Argentina Basin with approximated water depth between 1,500 to 4,000 m. Along with CAN-114, Equinor also partners with YPF in CAN-102 in Argentina Basin, as well as MLO-123 block in Malvinas Basin as part of a consortium with YPF and operator Total from Round 1. Equinor also received 100%-held operatorship on the blocks of AUS-105 and AUS-106 in Austral Basin, CAN-108 in Argentina Basin, as well as MLO-121 block in Malvinas Basin. Background Information The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. An official resolution for granting the exploration permits is expected to be published on 1 August 2019, with official granting of the permits to follow within 15 days.

Equinor ASA received CAN-114 block from Round 1 offshore bid round, Argentina Basin

Ness (397) block, S. Golan Heights, susp. mid-Nov ’17 at TD 2,400m, deeper target zone reportedly non-commercial.

Israel (Western Arabian Province) Ness 10 op. by AFEK OG (100.0%) in Ness (397) block

Siccar Point spudded appraisal well 204/10a-5 on the Cambo discovery on 24 April 2018. The discovery is situated across licences P1028 and P1189. The company contracted the “West Hercules” rig for the operations. The appraisal well targeted the main reservoir. On 29 May 2018 the company completed its vertical well which encountered more than 100 ft oil column with a net pay of 58 ft. Logging operations confirmed a high quality multi-darcy reservoir with an API of 23 degrees. Siccar Point then kicked-off its first horizontal sidetrack 204/10a-5Z. On 5 June 2018 Siccar Point confirmed that it was cementing the casing prior to drilling out into the horizontal section. On 13 June 2018 it was reported that a second sidetrack, 204/10a-5Y had been kicked-off. The horizontal section was drilled for 1,612 ft and was tested for 10 days (which commenced on 3 August 2018). Testing operations indicated excellent reservoir productivity and sustained flow. A full evaluation of the test results will take place in the coming weeks to allow for further pressure build-up following the rigs departure. Licence P1028 was awarded in the 19th Seaward Licensing round and comprises blocks 204/9a and 204/10a covering a total area of 178 sq km. P1189 was awarded in the 22nd Seaward Licensing Round and covers a total area of 60 sq km comprising blocks 204/4a and 204/5a. Cambo was discovered in 2002 by Amerada Hess with well 204/10-2. Five wells in total have been drilled on the structure to date. The plan for the appraisal well is to undertake an Extended Well Test (EWT) on the field. Cambo is a large basement high with sedimentary sequences draped over the top of the structure. It has an Hildasay reservoir and the field is thought to hold approximately 600 MMbo in place. The plan for the potential development is that it will be developed in two phases. Phase one involves a leased FPSO with seven producing wells and two water injectors and the plan is to produce approximately 87 MMbo and also some associated gas. Phase two details have not been defined to date. FID for the field is scheduled for the first half of 2019. Siccar believes that the Cambo area has material upside around areas of undrilled Hildasay reservoir, good potential for Colsay reservoir around the edges of the structure and potential fractured basement underlying the discovery also. Following completion of a deal between Siccar Point Energy and Shell, which completed on 1 May 2018, interest in P1028 and P1189 is held by Siccar Point Energy (70% + operator) and Shell UK Limited (30%).

204/10a-05 (Cambo) (Siccar Point 70% op. Shell 30%) pos. appr. in P1028/1189 block, over 30m oil column (23°API), 18m net, 491m horiz section, tested on natural flow for 10 days, rate yet n/a (w.o. pressure buildup). It was target the main Tertiary Hildasay sst. reservoir sequence.

ENI subsidiary ENI Hewett acquired a 60% interest in AL 006 (Pickering field) and a 59.4% interest and operatorship in DL 005 (Marishes field) from Third Energy. The deals completed in February 2019. The Pickering field was discovered 1992 and is a small Permian sour gas field. Production commenced from the field in April 1995. The Marishes field is also a small Permian discovery. The field was discovered in 1989 and also came onstream in April 1995 in conjunction with Pickering as part of the Ryedale gas fields along with Malton and Kirby Misperton. Interest in AL 006 is now held by Third Energy UK Gas Limited (40% + operator) and ENI Hewett Limited (60%). Interest on DL 005 is held by ENI Hewett Limited (59.4% + operator) and Third Energy UK Gas Limited (40.6%).

Eni acquired 60% stake in AL 006 and 59,4% + Op in DL 005 (Pickering & Marishes fields discovered in naturally fractured carbonate Permian Kirkham Abbey Fm) from Third Energy (-> 40% op. and ->40,6% analogically)

Azimuth Group subsidiary Azinor Catalyst has agreed to farm out 12.5% from its 25% stake in P1763 to Faroe Petroleum on 14 August 2018. The deal is subject to regulatory and partner consent. Faroe's 12.5% in P1763 equates to 25% of the Agar/Plantain well planned for August 2018 where operator Apache (50%) is not participating, and partners will be Azinor (25% + Op), Faroe Petroleum (25%) and Cairn Energy (50%). Cairn farmed in for 25% of P1763 (50% of Agar/Plantain) effective from 9 August 2018. The planned well has a PTD of 1,625m to appraise the Agar discovery near the centre of the licence, then sidetrack to the SE to explore the Plantain prospect. It is targeting combined P50 estimated recoverable resources of 60 MMboe. Success case cost is US$15 million, and the appraisal leg has 58% CoS. Apache opted out of the Agar appraisal after reviewing results from its Titan NFW 9/14b-16, drilled 8km to the S on P1985, which was P&A in December 2017. Agar was discovered by 9/14a-15A (2014, MPX), which encountered a 10m oil column within the Eocene Frigg Formation sandstone. P1763 covers 89 sq km on Northern North Sea blocks 9/9d and 9/14a, adjacent to the S of Bruce Field and 3km E of Beryl Field. It was awarded in the 26th Offshore Round on 10 January 2011, with obligations to reprocess 425 sq km of 3D seismic to PSTM, and a drill or drop option to the shallower of 4,500m or 10m below the logged gas/water contact. Azimuth farmed in for 33% WI in January 2016, increasing its share to 50% in May 2016 with the exit of JX Nippon and Dyas. Licence partners are Apache Beryl I Ltd (50% + Op), Azimuth Group via Azinor Catalyst Ltd (25%) and Cairn Energy subsidiary Nautical Petroleum Ltd (25%).

Azimuth Group (-> 25%, Apache 50% op.) subsidiary Azinor Catalyst has completed the farm out of 25% stake in P1763 to Cairn Energy.

PetroChina has signed with CNOOC for rights to blocks 23/29 (980 sq km in WD 0-85m) + 24/11 (464 sq km in WD 20-40m) in the Fushan and Leidong sags, Beibu Gulf Basin, South China Sea. PetroChina will operate with 70% during the explo phase. A 50:50 JOA will apply in the event of devt.

CNOOC (30%) has signed a PSC with PetroChina (70%) for 23/29 and 24/11 blocks, situated in the Fushan and Leidong sag areas.

An auction was held 6 Mar ’19 for 10 licences, 7 of which failed to attract an offer. Burisma, DTEK and Ukrgazvydobuvannya won the remainder as 20-year contracts: - Pivdenno-Kobzivska 368 sq km in the Kharkiv Oblast, Dnieper-Donets Basin, commitments seismic re-processing, new 2D or 3D + 1 well.  price amounted to UAH 9.623 million (million). Ukrgazvydobuvannya offered USD 1.1 MM, starting price USD 0.34 MM.   - Svitankovo-Lohinska, 197 sq km in the same area, commitments as above. Naftogazsystemy (DTEK) offered USD 3 MM, starting price USD 0.63 MM. - Dubrivsko-Radchenkivska, 65 sq km in the Poltava Oblast , Dnieper-Donets Basin, contains the Radchenkivske + Radchenkivske Zakhidnyy fields. Commitments as above. Naftogazopromyslova Geologiya (Burisma) offered USD 0.9 MM, starting price USD 0.63 MM. The shunned blocks are Suvorivska, 463 sq km (Odeska Oblast, SW Moldavskaya Depr), Zakhidnotokarsko-Krasnyanska, 91 sq km (Luhanska Oblast, Dnieper-Donets Basin), Dykhtynetska, 74 sq km in (Chernivtsi and Ivano-Frankivsk Oblasts, W. Ukraine), Kniazhynska, 75 sq km (Kharkiv Oblast), Saltivska 26 sq km (Kharkiv Oblast), Pechenizko-Kochetkivska, 263 sq km (Kharkiv Oblast), Vatazhkivska, 182 sq km (Poltava Oblast).

An auction was held 6 Mar ’19 for 10 licences, 7 of which failed to attract an offer. Ukrgazvydobuvannya won the Pivdenno-Kobzivska (368km²) block, DTEK (Naftogazsystemy) Svitankovo-Lohinska (197km²) block and Burisma (Naftogazopromyslova Geologiya) Dubrivsko-Radchenkivska (65km²) block.

Equinor reported on 4 July 2019 that it has made a new oil discovery at Oseberg Vestflanken. 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. Estimated recoverable reserves are 22 MMbo. Equinor will bring the new volumes online shortly and may use 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. Oseberg H is the first unmanned wellhead platform on the NCS, a new concept for the country but widely used elsewhere in Northwest Europe including Denmark and the Netherlands. The platform has 10 slots and two existing subsea wells were re-used for the Oseberg Vestflanken 2 development. Two of the slots are used for gas injection for IOR and extra injection gas is received from the existing gas injection system in the area via a new pipeline. The wells are controlled from the Oseberg Field Centre and this is also where processing takes place. Equinor expects to recover 110 MMboe (of which 62 MMb is oil) from the Alpha, Gamma and Kappa structures (between 2,400 m and 3,100 m subsea) at a cost of NOK 6.5 billion (USD 778 million) reduced from the PDO estimate of NOK 8.2 billion (USD 981 million). The field is expected to remain onstream until 2040. Oseberg was discovered in 1979 and lies across blocks 30/6 and 30/9 in the Viking Graben. Oil production started from the field’s Middle Jurassic Brent Group reservoir in 1988 and first gas exports were achieved in 2000 (it was previously re-injected). The four previous platforms on the field are: A (processing and accommodation), B (drilling and water injection), C (production, drilling and accommodation) and D (gas processing). Oseberg is a hub for a number of other accumulations in the area. Initially the field was expected to produce 2 Bboe over its lifetime but this is now expected to be around 3.1 Bboe. Oseberg is unitised and interests are divided between Equinor Energy AS (49.3% + operator), Petoro AS (33.6%), Total E&P Norge AS (14.7%) and ConocoPhillips Skandinavia AS (2.4%).

Norway (Oseberg Fault Block (Horda Platform)) Oseberg

Hydrocarbon Finder E&P LLC (HCF) is offering 39% of its 90% share in the onshore 1,390 sq km Block 15 (Jebel Aswad) licence, Odin Energi A/S holds the remaining 10%. The block is located in the Fahud Salt Sub-basin of the Oman Basin, to the east of Occidental’s (Oxy) Block 09 (Suneinah) and to the north of Oxy’s Block 27 (Wadi Aswad), both neighbouring blocks contain fields which produce from the Cretaceous Natih and Shu’aiba formations. In addition to the main Cretaceous reservoirs, there is thought to be potential in the Jurassic Mafraq Formation. Block 15 (Jebel Aswad) has excellent nearby infrastructure, exploration and production sharing agreement terms are favourable, and extensive 2D and 3D seismic data is available. Between October 2017 and January 2018, HCF was exploratory drilling in Block 15 (Jebel Aswad). The well Ataya 1 (previously reported here as HCF 2017 1) is located in the southern part of the block, near to the border of Block 27 (Wadi Aswad) and roughly 6.5 km northeast of Oxy’s Nasiyah Far East 1 discovery well. According to HCF, the Ataya 1 discovery has over 4 MMbbl of contingent reserves with considerable upside potential and is currently undergoing production testing. HCF is also planning to undertake a subsurface evaluation of the existing Jebel Aswad field area in Block 15 (Jebel Aswad). It will evaluate new leads and prospects, as well as looking at deeper reservoir potential in existing structures. Jebel Aswad 1, discovered in 1995 by Arakis Energy Corp, is a small/medium Cretaceous gas/condensate/oil discovery that has often been described in the past as a volatile oil field. Furthermore, in late-2016, HCF reported that it will commence a study to assess unconventional potential in the block. In northwest Block 15 (Jebel Aswad), on the Block 09 (Suneinah) border and approximately 10 km northwest of Jebel Aswad 1, the well Wadi Saylah 1 drilled in 1997 also by Arakis Energy Corp, was plugged and abandoned after encountering oil shows in the Cretaceous Natih and Shu’aiba formations. Block 15 (Jebel Aswad) contains additional identified prospect areas: Ataya East and Thimar, with the same Cretaceous play types.  Deeper potential is reported to exist in the Mafraq Formation (tilted fault blocks) and HCF also report unconventional potential in the Natih B source rock. In the west of Block 15 (Jebel Aswad), stratigraphic pinch-outs are thought to exist, as encountered by Petroleum Development Oman LLC in Block 06. HCF (operator) owns a 90% share in the Block 15 (Jebel Aswad) licence, Odin Energi A/S holds the remaining 10%. In early-2016, a Royal Decree was issued endorsing Tethys Oil Ltd to concede 100% of its share of the Block 15 (Jebel Aswad) licence to ODIN Energi A/S (article 1), as well as endorsing Odin Energi A/S to concede 90% of its share quota, to HCF (article 2). The current exploration phase expires on 22 October 2018 however, HCF is entitled to apply for a two-year extension. Companies interested in pursuing this opportunity should contact: Ian Cross - Managing Director, Moyes & Co. Tel: +65 9776 0753 Email: [email protected]

Hydrocarbon Finder E&P LLC (HCF) is offering 39% of its 90% share in the onshore 1,390 sq km Block 15 (Jebel Aswad) licence, Odin Energi A/S holds the remaining 10%.

Deepwater block 58, TD 6,300m, oil + cond discovery in multiple stacked targets in Campanian (50m net, 40-60 API) and Santonian (73m net, 45-45 API) intvs, a deeper Turonian intv was not reached owing to an over-pressured lower Santonian which will be investigated by future drilling. Next well planned Sapakara W.-1, ab.20km SE of Maka, target Campanian + Santonian. Noble Sam Croft DS. Apache (op), partner Total.

Maka Central-1 nfw Deepwater block 58, TD 6,300m, oil + cond discovery in multiple stacked targets in Campanian (50m net, 40-60 API) and Santonian (73m net, 45-45 API) intvs, a deeper Turonian intv was not reached owing to an over-pressured lower Santonian which will be investigated by future drilling. Next well planned Sapakara W.-1, ab.20km SE of Maka, target Campanian + Santonian. Noble Sam Croft DS. Apache (op), partner Total.

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

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

Bucsa block, Hajdú–Bihar sub-basin (Pannonian), drilled 18-28 Jan ’18, TD 1,300m (L. Pannonian), tested 770 Mcf/d CH4 from 1,141-1144m interval on 6mm choke, susp. mid-Feb ’18, Rotary Lyb 42 rig.  Note: discovery was Tiszaszentimre-2.

Tiszaszentimre-1 Bucsa block, Hajdú–Bihar sub-basin (Pannonian), TD 1,300m (L. Pannonian), tested 770 Mcf/d CH4 from 1,141-1144m interval on 6mm choke, susp. mid-Feb ’18,

Tower is on the lookout for potential partners in its 119-sq km Thali block in Rio del Rey shallow waters, in which Njonji-3 appr is to spud shortly. Contact via Envoi.

Tower is on the lookout for potential partners in its 119-sq km Thali block in Rio del Rey shallow waters, in which Njonji-3 appr is to spud shortly.

Penglai 13-2-8d (PL 13-2-8d) was suspended, having intersected oil in the target reservoirs, on or around 9 August 2019 after having been spudded on or around 2 July 2019, using the "Zhongyouhai 6" jack-up. The deviated oil and gas appraisal well was likely to be targeting the Guantao, Dongying and Shahejie formations. Penglai 13-2-8d is in the CNOOC operated Bozhong 06 Block in the offshore Bohai Gulf Basin. CNOOC conducted a four well appraisal drilling programme at the Penglai 13-2 discovery in Q3 2019 and successfully intersected oil at appraisal wells Penglai 13-2-6d, Penglai 13-2-7 and Penglai 13-2-8d with Penglai 13-2-5d being the only unsuccessful well. <P /><P />

Not Found

Fierbinti-Targ block/field, S. Carpathian Foredeep in S. Romania, drilled Feb – May '19, TD 3,400m, recently tested and ops concluded, results yet n/a, Dafora Medias F-200 rig. Amromco (op), partner Romgaz.

Fierbinti Vest-7 appr ierbinti-Targ block/field, S. Carpathian Foredeep in S. Romania, drilled Feb – May '19, TD 3,400m, recently tested and ops concluded, results yet n/a, Dafora Medias F-200 rig. Amromco (op), partner Romgaz.

During H2 2019, Sonatrach had concluded drilling operations in its Draa Allal Sud 1 (DRAS 1) NFW. Results are not yet available. The onshore well was drilled in the south of the In Amedjane exploration licence, located in the Berkine Basin. It was spudded on 18 April 2019, with operations being carried out by the ENAFOR #36 rig. DRAS 1 is understood to have been targeting a Triassic TAGS prospect, located to the south of the Draa Allal gas field. It is the first well spudded on the block, which was awarded as an effective re-award of the Rhourde Nouss In Amedjane licence (which expired in November 2018). Sonatrach operates the licence with 100% equity.<P />

Sonatrach had concluded drilling operations in its Draa Allal Sud 1 (DRAS 1) NFW. Results are not yet available.

Romgaz is looking to form partnerships to explore the Black Sea gas potential. The company is currently Lukoil partner to the E X-30 Trident licence in which the Trinity-1 nfw is still believed planned.

Romgaz is looking to form partnerships to explore the Black Sea gas potential. The company is currently Lukoil partner to the E X-30 Trident licence in which the Trinity-1 nfw is still believed planned.

Further to DEA 1 Jul '20, Somerton (Cooper Egy sub) and Adelaide Energy (Beach Egy sub) were retained as preferred applicants for bid block OT2019-B, 1,931 sq km in the Otway Basin, released under the 2019 SA acreage release. 5-yr commitments included 500km 2D seismic.

Australia (Otway B.), Somerton (Cooper Egy sub) and Adelaide Energy (Beach Egy sub) were retained as preferred applicants for bid block OT2019-B, 1,931 sq km in the Otway Basin, released under the 2019 SA acreage release. 5-yr commitments included 500km 2D seismic.

On 13 November 2019, Eni and Angola’s National Oil, Gas and Biofuels Agency (ANPG) signed a contract for the shallow water Congo Fan Block 1/14. The 3,730 sq km block plays host to four small oil discoveries all discovered by Agip (Africa) Ltd in the early 1980s. At least 18 additional prospects have been identified - thought to be gas prone. Eni operates the block with a 35% interest, Equinor holds a 30% stake, Sonangol P&P holds a 25% interest and ACREP holds a 10% stake. As of late June 2019, it was understood that Eni would take over operatorship of the block. According to sources a new contract to explore the block had already been negotiated and was with the ministry for final approval. Background information Block 1/14 was awarded to Sonangol E.P. in 2014. Sonangol was the sole participant in the Risk Service Contract.

Angola, not found

Operator BP is acquiring 16.5% in Clair Field from ConocoPhillips (currently 24%) for an undisclosed fee. The agreement involves transfer of the stake to a ConocoPhillips' subsidiary which will then be transferred to BP. It was announced on 3 July 2018 and remains subject to regulatory approvals. Clare is licensed via P165 - 206/8a, P168 - 206/7a & 11a, and P170 - 206/9a and was originally discovered by 206/8-1A (1977, BP, 2,327mMD) which tested 25 deg API oil at a rate of 15,000 bo/d and was estimated to contain 7 Bboe initially in place in thick but fractured Devonian to Carboniferous reservoirs overlying Lewisian basement. Clair Phase One production commenced in March 2005 targeting 300 MMboe recoverable reserves, and cumulative output to date is 125 MMbo and 40 Bcfg, averaging around 19,000 bo/d and 6 MMcfg/d in 2017. ConocoPhillips reports gross remaining recoverable reserves of 240 MMboe, assumed to be attributable to Phase One only. BP plans to commence production from Clair Ridge (immediately NNE of Phase One) during 2018, estimated to hold 640 MMboe recoverable resources and expected to produce up to 120,000 bo/d. ConocoPhillips had reportedly been seeking to sell it's 24% share of Clair since 2014. Pending approval and completion of the ConocoPhillips-BP deal, Clair Field partners are BP (28.6% + Op), Shell (28%), ConocoPhillips (24%) and Chevron (19.4%).

BP will increase its stake in the Clair oilfield through an asset swap with ConocoPhillips. BP will acquire from an additional 16,5% interest in the field (-> 45,1% op.). ConocoPhillips will keep a 7,5% interest. For its part, ConocoPhillips will acquire BP's entire 39,2% interest (-> 94,68% op.) in the Greater Kuparuk Area on the Alaska North Slope.

Suneinah block 9, drilled, tested + completed late Jun – early Aug ’19, TD 3,080m (Kharaib fm), no results. Oxy (op), partners Oman Oil + Mitsui.

Reham Kharaib-1 nfw, Suneinah block 9, drilled, tested + completed late Jun – early Aug ’19, TD 3,080m (Kharaib fm), no results. Oxy (op), partners Oman Oil + Mitsui.

A-location in Walker Ridge block 881 (lease G36181), WD ca. 2,300m, drilled end Dec '19 – early Feb '20, results n/a, Ocean Blackhawk DS released 8 Feb. Oxy (ex-A'ko) (op), partner Inpex.

WR 881 001S0B0 (Magnus) nfw. (Occidental (ex-A'ko) 60% op, Inpex 40%) in A-location in lease G36181 (WR block 881), P&A, results n/a. WD ca. 2300m.

Azinor and Cairn are offering the opportunity for interested parties to farm into licence P1763 (blocks – 9/9d and 9/14a) which contains 2018 Agar discovery. Interested companies could obtain up to a 75% interest and operatorship in the discovery which equates to a 37.5% interest in the licence P1763. Azinor states that the discovery is ready to move forward to development with FID planned for January 2021. The companies believe the discovery to be economically robust under a range of development scenarios with up-side nearby in the form of the Alpha and Plantain South prospects. In November 2018 it was announced that Azinor Catalyst had been successful with operations on its Plantain prospect and appraisal of its Agar discovery. Following two re-spuds of initial wellbore 9/14a-17 (A & B), the well 9/14a-17B targeting Plantain, was drilled to a depth of 2,254 m where it encountered the prospect at 2,066 m. A total of 27 m of high quality net reservoir sandstones in the Eocene Lower Frigg Formation were encountered and through logging-while-drilling and pressure analysis indicated a thin net oil pay zone with a significant underlying zone of residual hydrocarbons. Based on this result the sidetrack was kicked-off. Well 9/14a-17Z encountered the Upper Frigg Formation at 1,763 m and penetrated a gross reservoir of 20 m with a high net to gross ratio confirmed by log and pressure analysis and an average porosity of 30%. No Oil-Water contact was encountered. The sidetrack reached a depth of 1,962 m. It is thought recoverable resources from Agar are estimated at 15 to 50 MMboe. In terms of development the Beryl Bravo facilities are located 12 km to the north east of Agar-Plantain and the Alvheim FPSO is located approximately 14 km to the south east. The well was plugged and abandoned and the rig left location on 18 November 2018. The Agar discovery was made in 2014 with well 9/14a-15A which encountered a 33 ft oil column in high quality Eocene Frigg Formation sands. The well was drilled by MPX which was primarily targeting the Upper Jurassic sands of the Aragon prospect. The Upper Jurassic sands were encountered in the well but were water bearing. Interest in P1763 is held by Apache Beryl Limited (50% + operator), Cairn subsidiary, Nautical Petroleum Limited (25%), AziNor Catalyst Limited (12.5%) and DNO North Sea (U.K.) Ltd (12.5%).

Azinor and Cairn are offering the opportunity for interested parties to farm into licence P1763 (blocks – 9/9d and 9/14a) which contains 2018 Agar discovery.

On 19 July 2018 Santos Ltd reported that it was still in discussions regarding a proposal to farm-in to the P’nyang retention licence – PRL 3. It is thought that Santos has been in discussions with the joint venture for some time and was close to signing a deal in early-2018 before delays pushed back negotiations. PRL 3 is operated by Exxon Mobil Corp through its subsidiary company Esso Highlands Pty Ltd. Santos is already a partner in the Exxon Mobil operated PNG LNG project with 13.5% working interest and in late-2017 Santos farmed in to five Oil Search-- Exxon Mobil exploration licences which lay across the Muruk to P’nyang, Toro gas play trend. P’nyang is outlined to provide feed stock for an additional train at the PNG LNG facility, located in Port Moresby. It is considered that the field could be developed as a standalone project but be fully integrated for transportation / processing and would be aligned to the current PNG LNG joint venture partnership. With that said, Exxon holds a total of 49% interest in PRL 3 and Oil Search holds 38.51%. This equates to 15.8% and 9.51% above the respective PNG LNG equity. A farm-down of interest could accommodate for a Santos entry, and perhaps other PNG LNG partners also: JX Nippon and Kumul Petroleum. P’nyang’s position as future high impact producer in PNG was underlined in April 2018 after the completion of appraisal activities increased the natural gas resource to 4.36 Tcf, moving it into rank #4 of PNG field based on recoverable reserves. The independent recertification of the P’nyang resource was conducted by Netherland Swell and Associates following completion of P’nyang South 2 in late January 2018. The recertification certainly supports the proposed PNG LNG expansion project with the 1C upgrade likely to more than sufficient to underpin an additional train in Port Moresby. The P’nyang 1 field was discovered in 1990 and PRL 3 was awarded on 12 April 2000. Participants in the permit are Esso Highlands Pty Ltd (21.01% + operator), Ampolex (PNG) Ltd (27.98%), Merlin Petroleum Co (12.5%) and Oil Search (PNG) Ltd (38.51%).

On 19 July 2018 Santos Ltd reported that it was still in discussions regarding a proposal to farm-in to the P’nyang retention licence – PRL 3. It is thought that Santos has been in discussions with the joint venture for some time and was close to signing a deal in early-2018 before delays pushed back negotiations

Hitherto unreported on 22 August 2019, the Petroleum Agency of South Africa (PASA) granted Afro Energy (Pty) Ltd (Afro Energy) a Karoo Basin Coal Bed Methane exploration right (271ER). The Application was lodged in November 2013. 271ER covers some 295 sq km within the Karoo Basin within the Amersfoort magisterial district of the Mpumalanga Province. The work programme for the first three-year exploration period includes the following. Year 1: Drill 1 to 3 exploration core holes, Geophysical log of holes and the analysis of core sample gas content Year 2: Drill 1 to 3 exploration core holes, Geophysical log of holes, analysis of core sample gas content, design a pilot test well program and apply for approval to test. Year 3: Drill 2 to 3 pilot wells and analysis of pilot test programme results. Afro Energy operates the exploration right with a 100% interest.

Afro Energy has awarded a Coal Bed Methane exploration right in 270 and 271ER block.

006-4R-001 field, block 6, Sirte Basin (Zelten Platform), drilled 9 Nov '19 – 3 Jan '20, P&A'd at TD 1,255m (Gialo fm), Adwoc rig 12.

RRRR-003-006 (4R-3-6) appr. 006-4R-001 field, block 6, Sirte Basin (Zelten Platform), drilled 9 Nov '19 – 3 Jan '20, P&A'd at TD 1,255m (Gialo fm),

10 years after having sold a 10% interest in the REC-T-158 block to Labrea Petróleo, Cowan Petróleo has re-acquired the interest. Cowan is now again sole holder of the 31-sq km block within the BT-REC-037 contract, Recôncavo Basin.

10 years after having sold a 10% interest in the REC-T-158 block to Labrea Petróleo, Cowan Petróleo has re-acquired the interest. Cowan is now again sole holder of the 31-sq km block within the BT-REC-037 contract, Recôncavo Basin.

In June 2019 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 April 2018 industry sources reported that a company from the UK was interested in a partnership with Moesia but no more details were communicated. The company completed the reprocessing of more than 2,000 km of data across all four blocks. Moesia anticipates to re-appraise the Devetaki gas field which produced more than 15 Bcf of gas and condensate at economic rates but was not appraised or developed optimally. The Devetaki field is believed to contain significant incremental volumes and being located adjacent to existing infrastructure it offers near term production potential. Interest in the four permits are 100% held by Moesia Oil and Gas EOOD.

In June 2019 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.

Goshawk Energy Pty Ltd was awarded four special prospecting authority (SPA) licences on 8 November 2018.  The licences cover a total 41,725 sq km within the Canning Basin. The licences have been awarded for a period of six months, and will expire on 7 May 2019.  They are eligible for surface exploration and evaluation during their tenure.  The permits were applied for in November 2017. Goshawk Energy Pty Ltd was awarded four new SPAs on 1 November 2018 and holds 100% interest in all six licences.   Contract Name Basin Area (Sq km) Application Name SPA 28 AO Canning Basin 3,275 STP-EPA-0078 SPA 29 AO Canning Basin 14,992 STP-EPA-0079 SPA 30 AO Canning Basin 11,477 STP-EPA-0080 SPA 32 AO Canning Basin 11,982 STP-EPA-0069

Goshawk Energy was awarded 4 special prospecting authority (SPA) licences cover a total 41,725 sq km. not found

Global Vanadium is selling its 100% interest in EP 127, 14,280 sq km in the Georgina Basin, to Westmarket O&G. The AUD 1.5 MM deal is expected to be completed next month.

Global Vanadium is selling its 100% interest in EP 127 (14280km²) to Westmarket O&G.

Melbana Energy Limited announced on 26 April 2019 that it has cancelled the farm out agreement signed on 31 December 2018 with Anhui Modestinner Energy Co. (AMEC), for Block 9, located onshore North Cuban Province. AMEC, a subsidiary of Anhui Guangda Mining Investment Co Ltd (AGMI), did not satisfied the conditions listed in the agreement according to the timetable – which included Cuban and Chinese approvals. Melbana will pursue discussions with other interested companies, according to their statement – but it is also open to re-evaluate the partnership with AMEC. The agreement signed, AMEC would fund all operational costs for at least three exploration wells, with two drilled prior to 1 November 2019 – prospects Alameda and Zapato. If a discovery is confirmed, an appraisal well will be drilled, if not – a third exploration well, Piedra prospect will be drilled prior to July 2020. AGMI also assumes operatorship. In the event of a commercial success Melbana would recover its back costs from the authorized cost recovery pool as well as 12.5% of the profit oil. The company has been searching for a partner since November 2017 following the Cuban government’s refusal to grant Petro Australis the right to exercise a 40% back-in option on the block, as a result Melbana retains a 100% interest. Melbana’s top three prospects on Block 9 are: Alameda, Piedra and Zapato. Third party consultants in a recent prospective resource assessment of the block, assigned a best estimate prospective resources of 270 MMbbl of oil in the five targeted objectives contained within the three prospects. Alameda Prospect will test three separate objectives in the Upper and Lower Sheet formations. Best Recoverable Prospective Resources of the three objectives at 140 MMbbl of recoverable oil and assign 72 MMbbl of recoverable oil and a 32% chance of success. Piedra Prospect will test a Lower Sheet fractured carbonate closure which features roughly 1,400m (4,595 ft) of vertical relief at its crest. Best Recoverable Prospective Resources at 34 MMbbl of recoverable oil and a 23% chance of success. Zapato Prospect will test a Lower Sheet fractured carbonate closure which features almost 1,000m (3,280 ft) of vertical relief. Best Recoverable Prospective Resources at 95 MMbbl of recoverable oil and a 23% chance of success. On 11 October 2017 Melbana Energy Limited announced the company had notified Cuba Petroleo Union (CUPET) authorities it has fulfilled all its commitments required for the 1st sub-period of exploration on the Block 9 Production Sharing Contract (PSC). The commitments included reprocessing of 200 km of 2D seismic data and several geological studies. The 2nd sub-period of exploration starts on 3 November 2017 and has a term of 2 years and requires the drilling of one well on the block. The company completed a prospectivity assessment of the 2,380 sq km block in February 2017 and estimates the block to contain 12.5 Bbbl of in-place oil resources, with prospective recoverable resources pegged at 637 MMbbl. Melbana also reported that it has identified 19 prospects and leads within the tract.  Drilling in 2018 is expected to target the Alameda prospect, which will test three independent objectives with a deviated well, and possibly the Zapato or Piedra prospects. Costs for the two-well campaign are estimated at USD 20 – 30 million. The Cuban government is targeting accelerated oil exploration to increase its production volumes, currently reported to be approximately 45,000 b/d of oil plus 3 MMcm/d (100 MMcf/d) of gas.

Melbana Energy said it has terminated a farm-out agreement for Block 9 due to a lack of progress by the farminee Anhui Modestinner Energy.

On 5 December 2018, the Federal Agency for Subsoil Use held an auction for the Kubanskiy Severnyy block in Krasnodar Kray (North Caucasus Province). Integra won the auction with an offer of RUB 1.975 million (USD 0.033 million). The winner of the auction will receive a 25-year E&P license. The Kubanskiy Severnyy block covers 421 sq km in the Kubanskaya Zapadnaya Depression. No exploratory wells have been drilled in the area. Stratigraphic traps within the Miocene sedimentary section are the main exploratory targets. Hydrocarbon resources of the block are estimated at 6 MMbbl of oil and 123 Bcf of gas. The starting price amounted to RUB 1.795 million (USD 0.03 million).

Russia, not found

Brasse Field's northern appraisal sidetrack 31/7-3 A has proved successful and encountered 40m gross hydrocarbon bearing Jurassic reservoir, as released on 2 January 2019. 31/7-3 A was kicked-off on 17 December 2018 and reached SSTD at 2,254m. Both the reservoir depths and the hydrocarbon contact is similar to the pre-drill expectations and further wireline logging is ongoing. Brasse East exploration well 31/7-3 encountered 48m of aquiferous Jurassic excellent quality reservoir. Faroe Petroleum states that the excellent sand quality in the Brasse East Exploration well has reduced the reservoir risk of the Brasse Extension exploration prospect located to the north east of the Brasse Field. The wells were drilled with the "Transocean Arctic" semi-sub over PL740 in 124m WD. The Brasse discovery was made by 31/7-1 (2016, Faroe, 2,780m) which encountered 18m gross gas pay and 21m gross oil pay in good quality Fensfjord Formation reservoir, and a sidetrack confirmed 25m oil and 6m gas gross pay in good quality Fensfjord sandstones. Following two successful appraisal wells in 2017, 31/7-2 S & A, gross recoverable volumes have been estimated at 46-76 MMbo and 59-97 Bcfg. Brasse is located 5km S of Brage oil field (Wintershall operated with Faroe as partner), and 5km E of Equinor's Oseberg field cluster. Brasse development concept selection was ongoing in 2018. PL740 was awarded on 7 February 2014 in the APA2013 licensing round, and covers 87 sq km in blocks 31/7 and 30/9. On 10 December 2018, licence partner Point Resources merged with Eni Norge to form Var Energi. Brasse lies in PL740, B & C and equity partners are Faroe Petroleum Norge AS (50% + Op) and Var Energi AS (50%).

Brasse Field's northern appraisal sidetrack 31/7-3 A has proved successful and encountered 40m gross hydrocarbon bearing Jurassic reservoir,

Equinor has increased its interest in PL 785 S by 20% as a result of a deal with operator Total. The licence covers parts of blocks 26/2 and 31/11 (to the south of Troll), totalling 622 sq km, and applies below Base Cretaceous. Total plans to drill a well on the Brunost prospect in 2020. The deal was reported by the NPD on 4 January 2020 and is effective from 20 December 2019. This area of the Horda Platform (Stord Basin and Bergen High) has seen almost no drilling. The closest wells to the north and south are dry holes 31/8-1 and 26/5-1. 31/8-1 was drilled by E.ON Ruhrgas in 2011 on the Breiflabb prospect. The main target was the Upper Jurassic Sognefjord Formation and there were secondary objectives in the Jurassic Johansen, Fensfjord and Krossfjord formations and the Brent Group. The Sognefjord, Fensfjord and Krossfjord formations were all present but there were no shows. The Brent Group was not reached (the Krossfjord Formation was mistaken for the Brent Group at the time). 26/5-1 targeted the Paleocene Balder Formation and the Miocene Utsira Formation in the Storbarden prospect. Rocksource drilled this well in 2013, finding both formations but with almost no sand. Interest in PL 785 S is now divided between Total E&P Norge AS (50% + operator) and Equinor Energy AS (50%).

Equinor has increased its interest in PL 785 S by 20% as a result of a deal with operator Total. The licence covers parts of blocks 26/2 and 31/11 (to the south of Troll), totalling 622 sq km, and applies below Base Cretaceous.

Gran Tierra reported in early November 2017, that the Siriri-1 NFW on the PUT-4 Block in the Caguan-Putumayo Basin, hit 65.8m of potential net oil pay across five prospective zones based on logging results. This includes zones primarily in the Villeta Formation - 21.3m of potential oil pay in the 'A' limestone, 19.5m of potential new oil play in the 'B' limestone, 12.2m in the 'M2' limestone, 2.4m of potential oil pay in the 'N' sands and 10.4m in the Upper Pepino Formation. Gran Tierra commenced production testing operations on the well in December 2017 which are still ongoing in early 2018. The well was spud on the western edge of the block on 20 August 2017, with the Pioneer '303' land rig tapped to drill the NFW to a PTD of 3,754m, targeting the 'N' sands and 'A' limestones of the Cretaceous Villeta Formation. By mid-September 2017, Siriri-1 was drilled to a TD of 3,864m. The preceding NFW which also hit oil pay in five zones, Vonu-1, drilled in the PUT-1 block approximately 40km away was brought onstream in the 'A' limestone in July 2017 and is averaging 1,803 boe/d. Costatyaco-19 was the first well tested in the 'A' limestone that was brought onstream in September 2016. Gran Tierra's primary fields in the Caguan-Putumayo Basin are the Costayaco and Mosqueta Fields which produce oil from multiple intervals in the Villeta Formation. Gran Tierra holds 100% WI in the block, after acquiring PetroLatina (which held 30% WI) in August 2016.

Colombia, PUT 4

In Late February 2019, Apache Corporation abandoned the Kalabsha West Tayim Southeast 1 (WK-Tayim SE-1) (Le009-9)) exploration well in the West Kalabsha exploration block at a TD of 4,633 m in the Carboniferous Desouky formation. The well was spudded on 21 January 2019 using the “ST-4” land rig. It had a planned TD of 4,663 m and the Alam El Bueib A, Alam El Bueib 6 and the Upper Safa units as the objectives. The West Kalabsha exploration block is operated by Apache Oil Egypt (67%) and Sinopec International Petroleum E&P Corp (33%). Background Information The area of the West Kalabsha block was previously held by Epedeco Sallum as part of a larger block called Sallum relinquished in November 1999. The Sallum block extended to the border with Libya and to the Mediterranean coastline. Epedeco recorded 1,181 km of 2D seismic data in the last quarter of 1996. The company drilled one well in the area which become West Kalabsha. In early June 2004, Apache was assigned the West Kalabsha exploration block covering 2,714 sq km in the Northern Egypt Basin. The block was offered under the terms of the 2003 bid round.

Kalabsha West Tayim Southeast 1 (WK-Tayim SE-1) (Le009-9)) explo. in the West Kalabsha exploration block P&A at a TD=4633m in the Carboniferous Desouky formation, results n/a.

Oil co’s intending to participate in Lebanon’s planned 2nd round will be able to start pre-qual’s soon. Bids could be required by October and contracts signed-up early 2020. It is recalled 4 blocks are to be offered (in yellow below): 1 (1,928 sq km), 5 (2,374 sq km), 8 (1,400 sq km) + 10 (1,383 sq km) The 1st round in 2017 saw Total-Eni-Novatek walk away with blocks 4 and 9 (in brown).

Oil co’s intending to participate in Lebanon’s planned 2nd round will be able to start pre-qual’s soon. Bids could be required by October and contracts signed-up early 2020. It is recalled 4 blocks are to be offered (in yellow below): 1 (1,928 sq km), 5 (2,374 sq km), 8 (1,400 sq km) + 10 (1,383 sq km)

On 11 December 2019, the Federal Agency for Subsoil Use held an auction for two blocks in Udmurtia Republic (Volga-Ural Province). Lukoil and Udmurtneft (Rosneft/Sinopec) emerged as the winners. Results of the action as follows: The Pyzepskiy Yuzhnyy block covers 61.7 sq km and encompasses the Pyzherskoye Yuzhnoye field with 3P reserves estimated at 4.7 MMbbl of oil. Oil resources (category D1) of the block are estimated at 2 MMbbl. The starting price amounted to RUB 107.4 million (USD 1.65 million). Lukoil-Perm offered RUB 236.28 million (USD 3.63 million). The winner of the auction will obtain a 25-year E&P license. The Kacheshurskiy block covers 115 sq km and encompasses the Kacheshurskaya and Menilskaya Severnaya prospects with combined oil resources estimated at 3.6 MMbbl. Oil resources (category D1) of the block are estimated at 5 MMbbl. The starting price amounted to RUB 8.7 million (USD 0.13 million). Udmurtneft offered RUB 66.12 million (USD 0.99 million). The winner of the auction will obtain a 25-year E&P license.

Lukoil-Perm won Pyzepskiy Yuzhnyy block (62km²) and Udmurtneft (Rosneft/Sinopec) won Kacheshurskiy block (115km²).

Murphy is reportedly looking into selling its remaining Asia-Pacific portfolio: - Brunei: Murphy partners deepwater blocks CA1 (Shell op) + CA2 (Petronas) with 8.05% + 30% resp. - Vietnam: operated blocks 15-1/05 + 144&145, the former containing the Lac Da Vang, Lac Da Nau + Lac Da Trang oil finds/fields. - Australia: operated AC/P57, AC/P58, AC/P59 + EPP43, and non-operated AC/P21 (Eni) and AC/P36 (Inpex). All lie off WA except EPP43, in the Bight.

Brunei, not found

In Q2-Q3 2018, Sonatrach was awarded the ~19,000 sq km Negrine II prospecting permit, located in the Melrhir Trough of NE Algeria. It is understood to have been awarded on an initial two-year term. The block comprises of acreage formerly held by Sonatrach under the Biskra and Negrine exploration licences, relinquished in late-2016 and 2017 respectively. Three wells were drilled on the Negrine block, with one non-commercial Cretaceous gas discovery, Oglat Troudi 1 (OGT 1) being made in October 2015. The acreage also encloses the Guerguit El Kihal Nord and Guerguit El Kihal Sud fields, formerly operated by Gulf Keystone. Sonatrach operates the permit with 100% equity.<P />

Sonatrach was awarded the ~19,000 sq km Negrine II prospecting permit, located in the Melrhir Trough of NE Algeria.

On May 29, Petrobras issued a press release indicating it completed the sale of its entire working interest in the Macau package of seven fields to SPE 3R Petroleum. The transaction concluded with SPE 3R Petroleum paying BRL 678.8 million (~USD 127.20 million, 1 USD = 5.34 BRL) to Petrobras. The seven production concessions include the Aratum, Lagoa Aroeira, Macau, Porto Carao, Salina Cristal, Sanhacu, and Serra. Petrobras held 100% working interest in all the production concessions, except the Sanhacu concession, in which Petrobras was the operator with 50% working interest. The remaining 50% working interest belongs to Petrogal Brasil S.A. Macau Package of fields Field Name Field sqkm Disc Date Year Cumul Gas Prod MMscf (2019) Cumul Oil Prod MMbbl (2019) Aratum 5.26 1982 944.53 5.26 Lagoa Aroeira 0.6 1989 58.72 0.81 Macau 2.5 1982 610.03 2.68 Porto Carao 0.9 1992 49.36 1.22 Salina Cristal 15.01 1987 11,909.99 27.08 Sanhacu 7.42 2007 11,959.05 0.40 Serra 3.3 1996 4,829.66 25.48 Source: IHS Markit © 2020 IHS Markit   Background Information On 30 March 2020, the ANP formally approved the sale and transfer of the entire working interest in the Macau package of seven fields from Petrobras to SPE 3R Petroleum. On 8 August 2019, Petrobras issued a press release indicating it signed the sales agreement with SPE 3R Petroleum SA for the Macau package of seven fields in the onshore Potiguar Basin. The terms of the deal were reported to be a total consideration of USD 191.1 million to be paid in two installments. The first installment of USD 48 million paid on signing date and the remainder of USD 143.1 million to be signed after formal approvals and transaction closing. On 22 September 2017, Petrobras issued a press release indicating that it is offering for potential sale and assignment 19 production concessions in five separate packages or poles onshore in the Potiguar and Sergipe-Alagoas basins.

Brazil (Potiguar B.) Macau op. by 3R PT (100%) Petrobras issued a press release indicating it signed the sales agreement with SPE 3R Petroleum SA for the Macau package of seven fields in the onshore, for US$191 MM. The seven production concessions include the Aratum, Lagoa Aroeira, Macau, Porto Carao, Salina Cristal, Sanhacu, and Serra.

On 12 September 2018 Sapura Energy Bhd announced that it had signed a heads of agreement with OMV AG to form a strategic partnership, to create “sustainable long-term growth [and] expand(ed) portfolios”.  The transaction is thought to be worth around USD 1.6 billion. Under the terms of the agreement OMV is to acquire a 50% interest in Sapura’s wholly owned subsidiary Sapura Upstream Sdn Bhd. The companies reported that it allows them to expand their acreage positions and better opportunities within the upstream energy sector. Within Australasia, OMV holds interest in two Australian permits, in the North Carnarvon Basin, and ten New Zealand permits across the Taranaki, East Coast and Great South basins.  Sapura has interest in three Australian permits, also within the North Carnarvon Basin, and in five of OMV’s Taranaki Basin permits.

Australia, not found

In late June 2020, industry sources indicated that Khalda Petroleum's new field wildcat Kalabsha West A 25 (WKAL A-25X) drilled in the West Kalabsha concession, Northern Egypt Basin, was reported dry. The well, which was spudded on 21 March 2020 presumably in the West Kalabsha-A (Dev) block was targeting objectives in the Alam El Bueib Member Unit 6 (Burg El Arab Formation) and in the Safa Member of the Khatatba Formation. Khalda Petroleum is a JV between the EGPC (50%), Apache (33.5%) and Sinopec (16.5%).

Egypt (Northern Egypt B.),Kalabsha West-A 25 (WKAL A-25X) nfw, op. by APACHE (67%), SIPC (33%), EGPC (0%) in Kalabsha (Dev) block, P&A dry.

Hitherto unreported, Sezigyn was awarded in Aug ’18 former Unimag block 2413B (PEL 88), 5,800 sq km in the Lüderitz Basin WD 0-500m.

Sezigyn (Understood to have ties to Sungu Sungu) had been awarded an exploration licence covering Block 2413B (PEL 88).

The CEO of Predator Oil & Gas (Predator) Paul Griffiths reported on 15 July 2019 that he sees the farm-in as an option to finance the company’s gas exploration project in its Guercif licence, onshore in the Guercif Basin. Mr Griffiths also said that it is a low risk, low capital opportunity which has already attracted some interest. The firm is currently working on the Environmental Impact Assessment to drill the Moulouya prospect in the licence. Predator operates the Guercif Licence (I, II, III and IV exploration permits) with the 75% while the state-owned ONHYM holds the remaining 25%

Predator Oil & Gas seeking partners to finance its gas exploration project in the Guercif Licence

The South Sudan authorities are promoting the country’s open blocks which are available to companies for direct negotiations. Petroleum agreements are of the production sharing type and are entered into by the Ministry. The Council of Ministers (the cabinet of the government of South Sudan) has the power to open or close areas for petroleum activities. Petroleum agreements are negotiated and signed by the Ministry of Petroleum and Mining. Within the ministry, there is a General Director Petroleum and under him, four directorates. The Directorate of Upstream is the most important for licensing purposes. An Exploration and Production Sharing Agreement, gives the contractor an exclusive right to explore for petroleum in the contract area. In addition, an Exploration Drilling Permit is required before drilling starts. The exploration phase of an EPSA has a duration of up to six years, comprising a first commitment period and two optional commitment periods to be specified in the Agreement.   For more information contact to: Eng. Mohamed Lino Benjamin, Undersecretary, Ministry of Petroleum Tel: +211 956 666 935 / +211 912 366 661 Email:  [email protected]   Mr.Steven Puoch Riek Deng, Executive Director, Office of the Minister, Ministry of Petroleum Tel: +211 950 800 039 / +211 922 555 344 Email: [email protected]   The available blocks as of September 2018 are understood to be as listed below. There are 12 available blocks. Total open acreage amounts to 209,835 sq km, all onshore.   Open blocks       Block Name Area (sq km) Situation Block Basin Block A2 18,374 onshore Melut Basin Block A3 11,409 onshore Muglad Basin Block A4 2,993 onshore Muglad Basin Block B1 43,626 onshore Melut Basin Block B2 47,742 onshore Muglad Basin Block E2 22,331 onshore Muglad Basin Block S7 5,522 onshore Melut Basin Block A5 4,206 onshore Muglad Basin Block A6 4,007 onshore Muglad Basin Block A1 23,251 onshore Melut Basin Block DC 4,932 onshore Melut Basin Block E1 21,442 onshore Central African Shield

South Sudan, not found

On 17 September 2018 Zennor Petroleum announced that its subsidiary Zennor North Sea Limited has agreed to acquire Mitsui E&P UK Limited’s 8.97% interest in the Britannia field (P213, Block 16/26a Area B and P345 Block 16/27b Area B). The deal is key with regards to the developing Finlaggan field which will be a sub-sea tie-back to the Britannia platform. Also, in the 30th Round, Zennor acquired acreage nearby to Finlaggan and Britannia. Through the deal, Zennor will double its production to around 5,000 boe/d. Mitsui will retain the majority of the decommissioning liability up to the agreed cap with Zennor fitting the balance. The effective date of the transaction is 1 January 2018 and the deal requires regulatory approval. Zennor submitted its Environmental Statement for the development of the Finlaggan discovery in block 21/5c (P2013) in early 2018. The development for the field comprises a subsea manifold and two production wells tied back to the Britannia platform (in block 16/26) which is operated by ConocoPhillips. Zennor has an option to drill a third well, two to three years after first production but this will be dependent on how the reservoir performs but the initial plan just involves two development wells. Fluids will be processed on the Britannia platform and exported to shore via existing infrastructure. Peak production rates at Finlaggan are expected to be 80 MMcfg/d and 4,500 bc/d. The subsea infrastructure has a design life of 15 years and the field is expected to produce for 10 years. Zennor commenced drilling activities in Q3 2018. The wells will then be suspended until the subsea infrastructure is installed in 2020 with the project planned to come onstream in late 2020. Following completion of the deal interest in the Britannia field will be held by ConocoPhillips (UK) Ltd (40.6%), Chevron North Sea Ltd (32.28%) ConocoPhillips (UK) Theta Ltd (9.01%), Zennor North Sea Ltd (8.97%), ConocoPhillips Petroleum Co (UK) Ltd (7.23%), ConocoPhillips Ltd (1.81%).

Zennor Petroleum announced that its subsidiary Zennor North Sea Limited has agreed to acquire Mitsui E&P UK Limited’s 8.97% interest in the Britannia field (P213, Block 16/26a Area B and P345 Block 16/27b Area B).

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

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

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

Australia, NT/RL2

Mubadala Petroleum was officially awarded the Andaman I block, located in the offshore area of northern Aceh, on 31 January 2018. The block was offered as part of the Conventional Oil and Gas Bidding First Round 2017 under the Direct Offer mechanism. The block will be operated under the new Gross Split fiscal terms. The base government/contractor split under Gross Split terms is 57%/43% for oil and 52%/48% for gas, subject to modifiers depending on the specific situation of the block. Signature bonus for the block was USD 750,000. The minimum exploration commitments for the first three-year exploration period include one G&G study and a 500 sq km 3D seismic survey, for a total value of USD 2.15 million. The Andaman I block covers an area of approximately 7,400 sq km. The block is primarily located within the deep water area of the South Sumatra Basin, with the western edge bounded by the Mergui Ridge. Data available for this area consist of 5,204 km of 2D seismic data (ranging from 1983 to 2008). The block has been estimated by Migas to have prospective resources of 402 MMbo. No well has been drill to date within the acreage. Potential source rock in the area is provided by the Bampo and Parapat shale formations. The lacustrine Parapat facies could be only locally distributed, whereas the Bampo Formation is expected to be widespread in the area. Based on previous drilling results and geochemical analysis in the area, the block is likely gas-prone. Exploration targets in the block could be clastic reservoirs of the Upper Oligocene Parapat Formation, Lower Miocene Bampo Formation and Middle Miocene Baong Formation, mostly in structural trap settings. Directly south of the block is the Andaman III PSC, awarded to Talisman (currently Repsol) in November 2009. Repsol acquired a 3,000 sq km 3D seismic survey in the Andaman III PSC in late 2017. The Andaman I block is located approximately 150 km northwest of the Jambu Aye Utara field in the Krueng Mane PSC, where development is being planned with first gas potentially in 2022.

Indonesia (North Sumatra B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Andaman III op. by REPSOL (100.0%) to be check.Jambu Aye Utara op. by HYOIL (85.0%, KOGAS 15.0%) to be check.Krueng Mane op. by HYOIL (85.0%, KOGAS 15.0%) to be check.

Central part of WA-437-P, Bedout sub-basin (N. Carnarvon), WD 95m, ops terminated and well now P&A'd after successful testing (ref. recent releases + DEAs), Noble Tom Prosser JU released 17 Oct '19. Santos (op), partner Carnarvon.

Central part of WA-437-P, Bedout sub-basin (N. Carnarvon), WD 95m, ops terminated and well now P&A'd after successful testing (ref. recent releases + DEAs),

PEMEX suspended with results unreported the Bukma 1SON new-field wildcat (NFW), stratigraphic test in the AE-0101-2M-Ayikal-03 entitlement block in the deep water Campeche Deep Sea Basin during early-May 2018. There is no report as to the final status of the well nor the final total depth (TD).  The NFW was spudded on 8 January 2018.   The NFW had a proposed total depth of 8,020 m and the primary target is the Lower Eocene Formation.  PEMEX will also traverse a portion of the Paleocene Formation to collect data from that deeper zone.   The well was drilled by the “Centenario GR” semi-submersible in an approximate water depth of 2,700 m.  It is one of the deepest wells drilled in the country and will have implications for the operators who acquired deep water blocks in R1.4 regarding any deeper potential in the Eocene and Paleocene formations in this area.   The well is also located near the Area 24 block provisionally awarded to the consortium of ENI (65%), QPI  (35%) through deep water Ronda 2.4.   On 15 November 2017 the CNH granted a permit for PEMEX to drill the Bukma 1SON new-field wildcat (NFW), stratigraphic test.  The reported prospective resources is 375 MMboe.  The NFW is part of the approved exploration plans granted on 9 November 2017 for the two year extension period that commenced on 27 August 2017.  The NFW is located approximately 5.3 km northeast of the Nat 1 NFW gas and condensate discovery and 4.3 km east southeast of the Nat 1DL confirmation outpost that was successfully tested in the Miocene Formation also.  The Nat 1 discovery represents the deepest water discovery and most distant discovery offshore in the southern Gulf of Mexico for PEMEX. SENER granted the AE-0101-2M-Ayikal-03 entitlement to Pemex 100% through Ronda 0 on 27 August 2014.  The entitlement was modified twice by SENER, the second time on 9 November 2017 with a new work commitment plan.   Background Information PEMEX suspended as a gas condensate producer the Nat 1 DL directional outpost in the AE-0101 block in the Campeche Deep Sea Basin on 19 October 2015.  The operator reported on 9 December 2015 that it will incorporate an additional 250 MMboe 3P reserves to the 866 MMboe 2P reserves attributed to the Nat 1 discovery and field from the Middle Miocene Formation.  The company tested a show zone from 4,158 m to 4,188 m in the well during September and October.  The operator released test data with its 31 December 2015 annual report.  The productive zone tested 10 MMcfg/d and 412 bc/d.   The operator spudded the outpost in the block on 7 June 2015. The well reached a total depth (TD) of 4,349 m during late August 2015. The outpost had a proposed total depth (PTD) of 4,569 m measured depth (MD). The Early to Late Miocene Formation was the primary objective. The Grupo R Exploracion “Centenario GR” S/S drilled the well in an estimated water depth of 2,718 m. The well is located in the southern area of the AE-0101 block.  It is a 2.8 km northeastern outpost of the Nat 1 ultra-deep water gas discovery completed in February 2015. SENER granted the AE-0101 – Ayikal -03 Entitlement to PEMEX 100% on 27 August 2014 in Ronda 0. The block covers an approximate area of 309.73 sq km.  Pemex has three years to drill and or develop any discoveries in its exploration blocks with the possibility of a two year extension for appraisal. In mid-February 2015, the CNH published that the PEMEX operated Nat 1 New Field Wildcat (NFW) was completed as a wet gas discovery. The well was spudded on 25 May 2014 in 2,636 m of water in the Campeche Deep Sea Basin, and reached a total depth (TD) of 5,531 m on 11 October 2014. The well was completed in the Middle Miocene interval 4,080-4,130 m with initial test results indicating gas and condensate.

Mexico (Campeche Deep Sea B.) Nat 1

PetroChina – Xinjiang achieved success in an appraisal well in the Junggar Basin. Kemei 002, drilled in the south of Kelameili gas field, tested 3.9 MMcf/d of gas in the Carboniferous reservoir. The well is to test upside reserve potential in the lower part of the structure and during drilling the well penetrated two sets of gas pay with overall 100 m thick. In 2017 PetroChina achieved success in Dixi 121 in the southern part of the field, with Kemei 002 success, it indicated additional 1 Tcf of gas in place to the field.   Background information The Kelameili gas field includes Dixi 14, Dixi 17, and Dixi 18 and Dixi 10 discoveries and has the main reservoir in the Carboniferous. In 2007, 3 Tcf in place gas had been proved with additional 1.6 Tcf of possible gas reserves. With success appraisal work in 2008, a total of approximately 3.7 Tcf of proven gas in place had been confirmed. The Kelameili field was onstream in 2008. By November 2010, the field had 25 wells producing at a rate of 60 MMscfg/d. In 2015, PetroChina drilled several successful wells around Kelameili field which added additional reserves, such as Dixi 189, Dixi 323, Dixi 405, Dixi 406, Dixi 407 and Dixi 106. In 2016 the field produced at a rate of 70 MMcf/d of gas. In 2017 the field produced at a rate of 100 MMcf/d of gas.

PetroChina – Xinjiang achieved success in an appraisal well in the Junggar Basin. Kemei 002, drilled in the south of Kelameili gas field, tested 3.9 MMcf/d of gas in the Carboniferous reservoir. The well is to test upside reserve potential in the lower part of the structure and during drilling the well penetrated two sets of gas pay with overall 100 m thick.

On 17 April 2020, Petrobras concluded drilling the 1-RJS-753 (1-BRSA-1375-RJS), new-field wildcat (NFW), Natator prospect, in the SO Tartaruga Vd_P5 Contract, SO_TRTG_VD Block in the deep water of the Campos Basin. Petrobras issued a press release on 7 April 2020 indicating it logged oil shows in the well in the Early Cretaceous post-salt Quissama Formation target and will further evaluate the data to determine commerciality and future appraisal activity. The NFW was spudded on 13 February 2020 and had a proposed total depth (PTD) of 3,326 m. The well reached a total depth (TD) of 3,216 m The "Gold Star" S/S drilled the well in a water depth of 1,080 m and has left the country. The NFW lies in the north-eastern area of the block approximately 3.6 km south-east of the southwestern area of the Tartaruga Verde Field. The prospect was initially named Michelangelo and was identified by the ANP as a structural lead when the block was on offer in the ANP 5th PSC Pre-Salt Bid Round. Petrobras has 100% working interest in the SO Tartaruga Vd_P5 Production Sharing Contract (PSC), which includes two blocks: the 123.42 sq km SO_TRTG_VD Block and the 3.7 sq km Tartaruga Verde Sudoeste Block. The original 127.12 SO_TRTG_VD Block was preliminary awarded to Petrobras on 28 September 2018 through the 5th PSC Pre-Salt Bid Round, and officially awarded on 17 December 2018. Petrobras paid a fixed bonus of USD 17.50 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. Petrobras offered the minimum state take of 10.01% and won the block as there were no other bidders. The PSC contract has a seven year exploration period.

1-RJS-753 (1-BRSA-1375-RJS / Natator / Michelangelo) nfw. (Petrobras 100%), NE part of SO Tartaruga Vd_P5 contract, SO_TRTG_VD block, WD=1 080m, oil shows in the target L. Cretaceous post-salt Quissama Fm, shows report to ANP early Apr '20. PTD is/was 3326m. Petrobras issued a press release on 7 April 2020 indicating it logged oil shows in the well in the Early Cretaceous post-salt Quissama Formation target and will further evaluate the data to determine commerciality and future appraisal activity.

The Department of Energy (DMF) announced the winning bidders of the Thailand Petroleum Bidding Round 2018 for G1/61 and G2/61 blocks, on 13 December 2018. The operatorships of the Erawan field (G1/61) and Bongkot field (G2/61) have been awarded to PTTEP, with holding interests of 60% and 100%, respectively. PTTEP will be partnering with MP G2 (Thailand) Limited, a subsidiary of Mubadala Petroleum, for the G1/61 block. The 10 years Production Sharing Contracts (PSCs) for these two blocks are expected to be signed in February 2019. The new PSCs will take effect upon the expiry of the current concessions. The current production concessions for Erawan and Bongkot are due to expire in 2022 and 2023, respectively. Earlier on 25 September 2018, the DMF received two joint bids from PTTEP and its partner Mubadala, to compete with Chevron and partner Mitsui for G1/61 area. PTTEP submitted a single bid for G2/61 area to compete with a joint bid by Chevron and Mitsui. The winners will be required to invest at least USD 4 billion and to produce at least 800 MMcfg/d over the first ten years (2022-2032), according to the new contract. As of end of 2017, the combined production from both fields is approximately 2.1 Bscfg and 75 Mbc, which is equivalent to 70% of the total production in the country. Background Information The Erawan and Bongkot fields auction was officially launched by DMF on 24 April 2018. The auction was originally planned for November 2014. However, it was delayed due to amendment of the Petroleum Act. The revised petroleum law gives more flexibility to the investors, adding PSCs and service contracts to the existing concessions. Previously, the Erawan field in was licensed under Contract 1 (Blocks B12 and B13) and Bongkot field was covered by the B15, B16 and B17 concessions. Both concessions have been renewed once in 2007, and according to Petroleum Act 1969, the concession cannot be renewed for a second time. Chevron received 10 years extension of production period for the Erawan field on 29 October 2007 till April 2022. PTTEP, on the other hand, received approval the concession blocks B15, B16 and B17 (Bongkot field) 10 years’ extension of production period on 16 October 2007 till April 2022 (for B15) and March 2023 (B16 & B17). The Erawan Complex, located in the Pattani Trough, Gulf of Thailand, has been producing at 1,270 MMscfg/d and 47,400 bc/d in October 2018. The field has remaining 2P reserves estimated at approximately 880 Bcf of gas with 20 MMbbl of condensate, which is equivalent to 22% of the field total reserves. The field is currently operated by Chevron with 80% interest, partnering with MOECO (20%). The Bongkot field, located in the north Malay Basin, is operated by PTTEP with 66.67% interest. The other partner is Total with 33.33% interest. The Bongkot complex, including the main Bongkot field and the Greater Bongkot South development, produced approximately 980 MMscfg/d and 27,200 bc/d in October 2018. Remaining reserves are estimated at approximately 1.8 Tcf of gas and 27 MMbbl of condensate, representing approximately 25% of the total field reserves.

Thailand, G2/61 (Bongkot)

On 27 September 2019 Cairn Energy spudded exploration well 3/17a-3 targeting the Chimera prospect in block 3/17a (P2312). The well targeted the Paleocene Heimdal turbidites with a secondary objective of Eocene turbidites. Cairn estimated Chimera to hold 154 MMboe recoverable resources (>1 Bboe in place). The well was drilled with the “Stena Don” (S/S). On 17 October 2019 it was reported that the well was drilled to a TD of 1,830 m and terminated in the Paleocene Lista Formation with no hydrocarbons being encountered. As of 22 October 2019 abandonment operations were ongoing. Licence P2312 was awarded in the 29th Frontier Licensing Round in 2016. The licence covers an area of approximately 220 sq km. The nearest discovery is 3/17-2 (Tryfan) located roughly 3 km to the east. Chimera had an amplitude and AVO supported trap comprising a 3-way dip closure with up-dip stratigraphic pinch-out. If successful the prospect could have been developed via a standalone FPSO. Suncor completed the farm-in taking a 40% interest in the licence in December 2018. In September 2019 it was confirmed that DNO has acquired a 15% interest in the licence. Pending completion of a deal between Cairn and DNO interest in the licence will be held by Cairn subsidiary Nautical Petroleum Limited (45% + operator), Suncor Energy UK Limited (40%) and DNO (15%).

United Kingdom, P2312

PN-T-069 block, Parnaíba Basin, susp. mid-Sep ’19, no shows report yet, GWDC rig 120. PTD was 2,442m, targets Cabeças + Poti fm’s,

1-ENV-BL69GA-MA (1-ENV-007A-MA) nfw. (Eneva 100% )in PN-T-069 block, no shows report yet, PTD was 2442m, targets Cabeças + Poti fm’s.

As of 1 June 2019, ConocoPhillips Alaska has reached total depth on the West Willow 2 outpost well located in National Petroleum Reserve-Alaska (NPR-A) oil & gas lease AA-094413 on the North Slope of Alaska. The well is located 2.5 mi (4 km) to the west of the West Willow 1 discovery well located in NPR-A lease AA-094422. The West Willow 1 well discovered oil in the Cretaceous Nanushuk Formation in early 2018 after reaching a total depth of 3,783 ft (1,153 M). Total depth was reached on 17 April 2019. ConocoPhillips spud the West Willow 2 on 28 March 2019 using the Doyon Drilling Inc rig 141. The well will have a proposed total depth of around 4,000 ft (1,291 m) and be targeting the Cretaceous Nanushuk Formation. The 5,750 ac (23.31 sq km) NPR-A lease AA-094413 (Block 991-H-086) was officially awarded on 1 April 2017 to ConocoPhillips Alaska (78%) and partner Anadarko (22%) as a result of the 2016 NPR-A oil & gas lease sale. ConocoPhillips acquired Anadarko’s 22% working interest in late 2017.

ConocoPhillips Alaska has reached total depth on the West Willow 2 outpost well located in National Petroleum Reserve-Alaska (NPR-A) oil & gas lease AA-094413 on the North Slope of Alaska.

HCF is offering 39% of its 90% equity in its Jebel Aswad onshore block 15, 1,390 sq km in the N. Oman Fahud Salt sub-basin. It contains the Ataya, Wadi Saylah + Jebel Aswad finds as well as prospects, main reservoirs Cretaceous Natih (A-E) + Shuaiba carbs, deeper potential in the Mafraq fm. HCF (op), partner Odin Energi. Contact: [email protected].

HCF is offering 39% of its 90% equity in its Jebel Aswad onshore block 15, 1,390 sq km in the N. Oman Fahud Salt sub-basin. It contains the Ataya, Wadi Saylah + Jebel Aswad finds as well as prospects, main reservoirs Cretaceous Natih (A-E) + Shuaiba carbs, deeper potential in the Mafraq fm. HCF (op), partner Odin Energi. Contact: [email protected].

Canadian operator PentaNova Energy subsidiary Alianza Petrolera was reported on 9 January 2018 to have acquired the 54% interest from Argentine operator Roch for the 269 sq km Rio Deseado Este I exploration block and the 52 sq km Sur Rio Deseado Este II production concession in the southern San Jorge basin. The development block has 7 wells, some of them in production. In August 2017, Pentanova reported the completion of the acquisition of Patagonia Oil Corp, including Alianza Petrolera. Through the Alianza transaction, Pentanova acquired 29% of the Neuquen Basin Llancanelo Block, partnering with YPF and an 18% fully carried interest on the Tecpetrol operated Estancia La Mariposa license in the San Jorge Basin. An additional working interest in Llancanelo also gave Pentanova a 50% stake in the block as reported by YPF in April 2017. This agreement also provides preferred rights to negotiate on the Llancanelo R Block 1 block held 100% by YPF. In July, Patagonia, as a Pentanova subsidiary executed a final deal to acquire and operate the former Kilometer 8 contract including the current San Jorge, Burmeister, Sol de Mayo and Stephenson blocks in the San Jorge Basin for total of US$ 12.5 million. In May it was reported to the Buenos Aires exchange that Patagonia had obtained approval to acquire the stake held by Roch in five blocks. Patagonia will get 20.28% of the 420 sq km Angostura, 367 sq km Rio Cullen and 1,183 sq km Las Violetas licenses, all in the Tierra del Fuego portion of the Austral Basin. Roch is the current operator of these licenses.

Alianza Petrolera has acquired the 54% interest from Roch for the Rio Deseado Este I exploration block (269 sq km) and for the Sur Rio Deseado Este II (52 sq km).

PL 509, Cooper-Eromanga, drilled early Mar ’18,  1.4m net oil pay in target Murta, suspended. Santos (op), partner Beach.

Cocinero-6 PL 509, Cooper-Eromanga, drilled early Mar ’18, 1.4m net oil pay in target Murta, suspended. Santos (op), partner Beach.

Baron Oil and SundaGas have terminated a proposed reverse takeover agreement on concerns the deal would not be completed within the required timeline. SundaGas is involved in Indonesia (Telen block) + Timor-Leste (new Chuditch block, ref. DEA 15 Nov '19).

East Timor, not found

Santos Ltd, through wholly owned subsidiary Bonaparte Gas & Oil Pty Ltd, increased its interest in retention leases WA-27-R and WA-40-R, located in the Bonaparte Basin, on 11 April 2019.  Santos has acquired an additional 54% interest upon the withdrawal of joint venture partner Neptune Energy Bonaparte Pty Ltd which has exited both licences.  Santos is now sole holder and operator of the permit. Neptune Energy had entered the licences in February 2018, when it acquired Engie E&P International.  Engie held interest in four licences (WA-27-R, WA-40-R, WA-06-R and NT/RL1) which Neptune acquired interest in, marking its entrance into Australia.  Through the transaction, Neptune acquired 60% interest and operatorship of the assets, which contain the proposed Bonaparte LNG project fields - Frigate Deep (WA-40-R), Tern (WA-27-R) and Petrel (WA-06-R / NT/RL1).  At this stage, Neptune Energy retains its interest in the Petrel field and licences. WA-27-R was awarded to Santos Ltd in October 2003.  GDF SUEZ, which later changed name to Engie, entered the permit in May 2010.  The licence contains the Tern discovery, which was made in August 1971.  WA-40-R was awarded to Santos and GDF SUEZ in September 2011. It contains the Frigate Deep discovery, which was made in August 2008.  The two discoveries are considered part of the Bonaparte LNG Project, alongside Petrel.  The fields were initially outlined for a standalone Floating LNG project, but development evaluation has been undertaken and more recently has included looking at the option for tie-back as FLNG was not considered to meet the commercial requirements of the joint venture. WA-27-R and WA-40-R, which cover areas of 334 sq km and 166 sq km respectively, saw an interest change on 11 April 2019.  Santos Ltd now holds 100% interest and operatorship of the licences, with 65% held through wholly owned subsidiary Bonaparte Gas & Oil Pty Ltd.

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

DNO ASA confirmed on 26 November 2018 that it has announced the terms of an offer to be made for the whole of the issued and to be issued share capital of Faroe Petroleum Plc. The offer stands at 152 pence in cash per Faroe share which values Faroe’s existing share capital at approximately GBP 608 million (USD 781 million). Faroe responded to the announcement by DNO stating that DNO did not engage with Faroe before making the announcement of its unilateral offer. Further announcements will follow once the Board of Faroe has met with its advisers. DNO already holds 28.22% of Faroe Petroleum’s issued share capital.

Norway, not found

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

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

On 1 December 2017, RDG Niedersachsen GmbH, an investment platform of the equal partners Rohöl-Aufsuchungs Aktiengesellschaft (RAG) and Petroleum Equity, was granted the Lahberg mining plot in northern Germany. The contract, valid until 30 November 2020, has been secured to attest the potential for residual crude oil production. The 8 sq km Lahberg block is located several kilometres southeast of the city of Hannover. In a geological sense, the block is situated within the Northwest German Basin.

Germany, not found

On 30 August 2018, the ANP approved of the sale of the 100% working interest held by Engepet in the Riacho Sesmaria block to Petroil Oleo e Gas Ltda as operator with 50% working interest and Oil and Gas Investments Group Exploracao e Producao Ltda with 50% working interest.  On 12 May 2016, the ANP granted a final award to Engepet 100% for the 1.96 sq km Riacho Sesmaria block in the Reconcavo Basin through the ANP Round 13 Marginal Fields Round.  The ANP granted a provisional award to Engepet Ltd 100% for the 1.96 sq km Riacho Sesmaria block in the Reconcavo Basin on 10 December 2015 through the ANP Round 13 Marginal Fields Round as the high bidder for the block. There were no other bids for the block. The company bid BRL 267,750 versus the minimum bonus set of BRL 41,548. The concession contract for the block has an initial three year evaluation period that may be extended. The company can then declare commerciality and this period can last up to five years. The production phase is 15 years. These different phases may be extended at the discretion of the ANP. The initial work program for the block is BRL 700,000 and only requires the re-entry of a well or wells and 3D seismic re-interpretation. The ANP set local content requirements for all phases at 70%.

Petroil Oleo e Gas acquired operated 50% WI and Oil and Gas Investments Group Exploracao e Producao with 50% WI in Riacho Sesmaria block from Engepet.

Heshen 3 was drilled to a TD of 6,410m MD on 5 July 2020 and was suspended for testing in mid-July 2020, having encountered strong gas shows in the target formation. The gas exploration well was spudded in January 2020 to drill to a PTD of 6,536m with a 905m horizontal section. Heshen 3 was targeting the Permian Maokou Formation with the objective of exploring the hydrocarbon potential of the Paleo Uplift, central Sichuan Basin. Heshen 3 is in the PetroChina operated Anyue-Tongnan Block in the Sichuan Basin.

China (Central Sichuan B.), Heshen 3 was drilled to a TD of 6,410m MD on 5 July 2020 and was suspended for testing in mid-July 2020, having encountered strong gas shows in the target formation.

Total SA announced on 18 March 2018 that it had paid US$ 1.15 billion for a 20% stake in a new 40-year concession agreement to operate the offshore Nasr and super giant Umm Shaif oil fields. Eni SpA acquired an initial 10% holding on 11 March 2018, while Abu Dhabi National Oil Company (ADNOC) subsidiary ADNOC Offshore will retain a 60% government working interest. The Supreme Petroleum Council (SPC) approved the creation of a new operating consortium prior to the expiry of the former Abu Dhabi Marine Operating Co (ADMA-OPCO) contract for the ADMA Central Block. The remaining 10% interest has yet to be awarded. ADNOC had confirmed in October 2016 that it planned to combine its two largest offshore operating companies, namely ADMA-OPCO and Zakum Development Company (Zadco) into a single operating unit. It subsequently announced on 15 October 2017 that it had established a new subsidiary “ADNOC Offshore” to be responsible for the development and delivery of oil and gas resources in Abu Dhabi waters. In launching its new unified brand in line with a 2030 smart growth strategy, ADNOC entered a transition period during which former company names are hereby being referenced for the purposes of clarity and historical integrity. ADMA-OPCO shareholders were ADNOC 60%, BP 14.66%, Total 13.33% and JODCO 12%. ADMA-OPCO was 100% right holder in the ADMA Central Block up until the point that its 45 year ADMA contract expired on 18 March 2018. Background information The 1,303 sq km former ADMA Central concession encompassing both the giant Nasr and super-giant Umm Shaif oil fields expired in March 2018. Although discovered in 1971, the Nasr oil field was only brought onstream during 2015. Early production averaged around 22,000 bo/d during 4Q 2017, but the field is being developed to reach a peak plateau rate of 65,000 bo/d in 2H 2019. Umm Shaif was producing at a rate of around 250,000 bo/d during 4Q 2017. A new oil gathering network is to be commissioned during 2H 2019, which will allow an average production rate of 275,000 bo/d to be sustained until the year 2031. The original Abu Dhabi offshore concession was awarded to D'Arcy Exploration Company in 1953. In 1955 the concession was assigned to ADMA, a company owned by BP and CFP. BP assigned 45% of its interest to Japan Oil Development Company Limited (JODCO) in 1972. In January 1973 ADNOC acquired 25% interest in ADMA Limited. The following January ADNOC increased its shareholdings in ADMA to 60%. ADMA-OPCO was subsequently incorporated in 1977 to operate the ADMA concessions on behalf of the interest holders, ADNOC (60%) and ADMA (40%). In early November 2010, ADMA-OPCO CEO Ali Rashid Al Jarwan re-affirmed the fact that his company intended to increase its offshore oil production capacity to 1.75 million barrels a day (MMbbl/d) by 2019.    

UAE, not found

North El Arish Offshore block 6, deepwater Eastern Nile Delta, WD 755m, P&A non-comm. hc at TD 3,890m on 28 Jul ’19, Tungsten Explorer DS. The rig contract has options for 3 more wells.

Egypt, Nile Delta (Dev)

On 15 January 2019, the Federal Agency for Subsoil Use held an auction for the Pukhutsyayakhskiy block in Yamalo-Nenets Autonomous Okrug (West Siberia). The winning bid of RUB 20.988 million (USD 0.31 million) was submitted by Gazprom Neft-Aero Bryansk. The winner of the auction will obtain a 25-year E&P license with a seven-year exploratory stage. Details of the offer are as follows: The Pukhutsyayakhskiy block covers 825 sq km in the eastern part of the South Kara-Yamal Province bordering Krasnoyarsk Kray. Seismic coverage amounts to 225 km of 2D data. No exploratory wells have been drilled in the area. Hydrocarbon resources (categories D1+D2) of the block are estimated at 23 MMbbl of oil, 1,182 Bcf of gas and 21 MMbbl of condensate. The starting price amounted to RUB 17.49 million (USD 0.26 million).

Russia, not found

Total (op), Qatar Petroleum + Petronas were amongst the first to announce a result from ANP's round 16, bidding deadline for which was yesterday (see related entry). The 40:40:20 partnership won block C-M-541, deepwater Campos pre-salt (WD 3,000m). Total confirms however that it will not participate in the upcoming Transfer-of-Rights (TOR) surplus production round, as this tender offers only non-operated interests. Map below courtesy Total. .

Brazil, not found

On 14 November 2018, Abu Dhabi National Oil Company (ADNOC) announced new investment of US$ 1.4 billion (AED 5.1 billion) to fast-track and significantly expand its planned Bu Hasa oil field upgrade to increase its productive capacity to 650,000 barrels a day (bo/d). ADNOC Onshore forerunner Abu Dhabi Company for Onshore Oil Operations (Adco) had originally launched a more modest development plan for the super-giant field within the ADNOC Onshore Concession during early 2016, which intended to raise sustainable oil production from 540,000 barrels of oil a day (bo/d) to 570,000 bo/d by 2024. Front end engineering and design (FEED) studies completed by CH2M Hill in 2017 called for the upgrading of existing flow lines, construction of two additional compressor trains and an expanded water injection network. Tecnicas Reunidas SA is engineering procurement and construction (EPC) contractor for the project, with Target Engineering Construction its primary subcontractor. The multi-billion barrel Bu Hasa field was brought onstream in May 1964 at a rate of 115,000 barrels of oil a day (bo/d) and currently produces in excess of 500,000 bo/d. It is the largest onshore producing field in the United Arab Emirates (UAE), so current development programmes are specifically intended to prolong its plateau production rate and maximise ultimate oil recovery. It produces oil from multiple, well established Jurassic and Cretaceous reservoirs, in addition to Permo-Triassic gas. Abu Dhabi National Oil Company (ADNOC) launched a new unified brand in October 2017, bringing together all its subsidiary companies under one common identity to highlight the scale of its business and size of its contribution to the national economy. As a result, the name change from Adco to ADNOC Onshore was adopted with immediate effect. Improved recovery techniques began to be employed at Bu Hasa during the 1970s. Discovery well Murban 12 (later renamed Bu Hasa 12), was drilled in 1962 at the crestal position on the Bu Hasa structure, which was at that time was considered to be a southern extension of the Bab field. Gravity and magnetic surveys conducted during the 1950s provided initial indications of the presence of the Bu Hasa structure, which was subsequently seismically mapped in the early 1960s. Bu Hasa is a north-south trending, broad anticline developed over deep seated Cambrian salt movement. The ADNOC Onshore Concession encompasses a number of developed and undeveloped hydrocarbon accumulations. Total is Asset Leader for the Bu Hasa, Sahil, Asab, Shah, Qusahwira and Mender oil fields. ADNOC Onshore partners are ADNOC (60%), Total (10%), BP (10%), CNPC (8%), INPEX (5%) NPIC (4%), GS (3%). CEFC China Energy Company Limited (CEFC China) was replaced in the onshore concession by North Petroleum International Company Limited (NPIC), a subsidiary of China ZhenHua Oil Company Limited (ZhenHua) in December 2018.

UAE, not found

On 1 November 2018 OMV Petrom reported that the takeover of Repsol’s interest in the V Baicoi deep, VI Targoviste deep, XII Pitesti deep and XIII Targu Jiu deep blocks has been approved by the National Agency for Mineral Resources (NAMR). In Q2 2018 Repsol had notified OMV Petrom of its intention to exit the four blocks where it held 49% interest. The blocks are situated in the southeastern part of the country. Repsol was officially granted the 49% interest in the deep blocks (below 2,500 m) by NAMR on 17 September 2013. The investments done by Repsol and OMV Petrom amount to more than USD 200 million. It includes 2D and 3D seismic surveys and the drilling of two deep wells. A third exploration well is currently in the drilling phase below 5,000 m. Interest in the four licences is now solely held by OMV Petrom SA.

OMV Petrom reported the takeover of Repsol’s interest in the V Baicoi deep, VI Targoviste deep, XII Pitesti deep and XIII Targu Jiu deep blocks

BP has put its first shale gas well on stream (probably for a pilot production test) in the Sichuan Basin. Wei 206-H1, located in Neijiang-Dazu PSC block, currently produces at a rate of 350 Mcf/d of gas after fracking. BP spudded Wei 206-H1, a shale gas exploration horizontal well, in the block on 30 August 2017. The well has a PTD of 4,790 m with target in the Longmaxi shale. BP completed drilling operation on Wei 206-H1 and reached a TD of 4,368 m on 28 December 2017. During drilling the well penetrated 30-50 m shale in the Longmaxi Formation and proved newly acquired 3D seismic interpretation. Following Wei 206-H1, BP has spudded additional wells in Neijiang – Dazu and Rongchangbei blocks. Next to the BP block in the west PetroChina has established Weiyuan shale gas field, the field has main reservoir in the Longmaxi Formation. In 2018 PetroChina produced 1.5 Bcm of shale gas from Weiyuan field. Background Information BP signed two shale gas production sharing contracts (PSC) with CNPC in 2016 on the Neijiang-Dazu and Rongchangbei in the Sichuan Basin. The Neijiang-Dazu block has area of approx. 1,500 sq km and the Rongchangbei block has area of approx. 1,000 sq km. CNPC is operator for both blocks. Neijiang – Dazu block used to be a joint study between CNPC and ConocoPhillips during 2013 to 2014. ConocoPhillips completed the study without moving forward to PSC. Rongchangbei block used to be a joint study between CNPC and Eni during 2013 to 2014. Eni completed the study without moving forward to PSC. The main reservoir in the blocks is the Silurian Longmaxi shale.

BP has put its first shale gas well on stream (probably for a pilot production test) in the Sichuan Basin. Wei 206-H1, located in Neijiang-Dazu PSC block, currently produces at a rate of 350 Mcf/d of gas after fracking. BP spudded Wei 206-H1, a shale gas exploration horizontal well, in the block on 30 August 2017.

According to industry sources in October 2017, the Pemex-operated Octli 1 well, drilled on the AE-0009-M-Tucoo-Xaxamani-01 Block (Salina del Istmo Basin), has been classified as an oil and gas producer. At last report in June 2017, the exploration well reportedly reached a TD of 2,155m (2,149m TVD). Pemex used the Grupo R "Cantarell I" jack-up to spud the well on 10 May 2017, targeting Late Miocene/ Early Pliocene objectives. Pre-drill prospective resources were thought to be in the order of 41 MMboe. This is the same contract area where Pemex, in 2016, made the Teca 1 discovery. Pemex, at that time, said that Teca potentially held between 50 MMbo and 60 MMbo. The Cahua 1 well was also drilled in the contract area in mid-2017 (see related Scout articles). In October 2017, the Comision Nacional de Hidrocarburos (CNH) granted Pemex an additional two-year exploration period for the contract so that it can further drill additional prospects and build up its reserves book. Pemex was awarded 100% interest in the acreage in the Round Zero assignment allocation in August 2014.<P />

Octli 1 op. by Pemex (100%) in AE-0009- M-Tucoo-Xaxamani-01 contract area, has been classified as an oil and gas producer from Late Miocene/ Early Pliocene objectives.

On 8 December 2017, Jaguar Exploracion y Produccion de Hidrocarburos, S.A.P.I. de C.V. signed the contracts with the CNH and was granted official final awards for the CNH-RO2-L03-TM-01/2017 contract from the CNH-RO2-LO3/2016 Bid Round.  The CNH-RO2-L03-TM-01/2017 contract is also known as the Area 5, TM-01 block.  Jaguar formed a separate subsidiary, Jaguar Exploracion y Produccion 2.3, S.A.P.I. de C.V. with 100% working interest as the official designated operating company for the block.  The 72.40 sq km CNH-RO2-L03-TM-01/2017 contract has a total financial commitment of USD 42.2 million, USD 16.1 million in work commitments including two additional wells plus the tie-break bonus of USD 26.10 million.   On 12 July 2017 Jaguar Exploracion was the high bidder in the CNH-RO2-LO3/2016 Bid Round for the Area 5 block in the Tampico-Misantla Basin and was granted a preliminary award.   For the 72.40 sq km Area 5 block Jaguar offered the maximum additional royalties of 40% and 1.5 work unit factor equivalent to two additional wells.  There were seven other bids for the block and six offered the same royalties and work units so ended in a tie.   Jaguar won the tie break with a bonus bid of USD 26.1 million beating the 2nd place bonus offer from DEP PYG who offered a bonus of USD 5.002 million.    Jaguar has 100% working interest in the contract. The general license contract terms include a 1st exploration period of two years with the possibility of a two-year extension.  In the case of a discovery the operator can request a two-year evaluation phase for oil and a three-year evaluation phase for non-associated gas discoveries once the evaluation plan is approved.  The total contract term is for 30 years with the possibility of two five year extensions for a 40-year total contract term from signature date. The base royalty rate is a sliding scale royalty depending on type of hydrocarbon and oil price.  The values for oil range from 5% for USD 40/bbl oil to 25% for USD 200/bbl oil.  The relinquishment schedule is tied to exploration well commitments.  If the exploration period ends but the operator offers to drill an additional well it doesn’t have to relinquish any area.  If the exploration period ends and the contractor doesn’t have any discoveries it must relinquish 100%.  If the exploration period ends and the operator doesn’t offer to drill an additional exploration well it will have to relinquish 50% of the area.  Local content during the exploration period is 26% for the exploration and evaluation period, and varies from 27% to 38% in the development period.

Mexico (Campeche Deep Sea B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: 10 op. by ENI SPA (100.0%) to be check.2 op. by PEMEX (50.0%, RWE 50.0%) to be check.12 op. by LUKOIL (100.0%) to be check.7 op. by ENI SPA (45.0%, CAIRN EN 30.0%, CITLA 25.0%) to be check.

An unusual one here, BPC announces the award of offshore block OFF-1 for 4+3+3 years explo, commitments seismic reprocessing + reinterpretation of vintage 2D seismic. OFF-1 was on offer in the country's open round and covers ab. 15,000 sq km in WD 20-1,000m. BPC's rationale is owed to perceived similarities between the area and the Guyana - Suriname basins.

Uruguay, (Pelotas B.) BPC (Bahamas Petroleum Company) announces the award of offshore block OFF-1 for 4+3+3 years explo, commitments seismic reprocessing + reinterpretation of vintage 2D seismic. OFF-1 was on offer in the country's open round and covers ab. 15,000 sq km in WD 20-1,000m. BPC's rationale is owed to perceived similarities between the area and the Guyana - Suriname basins.

On 6 June 2018, Xinjiang Energy Co Ltd was officially awarded exploration license Wensu West Block in the onshore Tarim Basin. Wensu West Block covers approximately 1,384 sq km and was offered in the 2017 Xinjiang Oil & Gas Bid Round. Xinjiang Energy won the right to explore the block with a winning bid of 380.84 million RMB (~US$ 59.7 million) for an initial five year exploration period. Xinjiang Energy is the operator and sole rightholder of the Wensu West Block.

Xinjiang Energy Co Ltd was officially awarded exploration license Wensu West Block in the onshore Tarim Basin. Wensu West Block covers approximately 1,384 sq km

Pakistan Petroleum Ltd (PPL) reported on 23 December 2019 that it has discovered gas in Margand X-1 new-field wildcat (NFW) well within the Margand 2866-4 EL (Kirthar Fold Belt) onshore licence. The company carried out drill stem test (DST) after drilling to a TD of 4,500 m and it flowed 10.7 MMcfg/d and 132 b/d of liquids through 64/64" choke with a well head flowing pressure (WHFP) of 516 psi from the Jurassic Chiltan Limestone Formation. PPL was conducting the study about the nature of liquid which is assumed to be condensates. It was reported that the well has a potential to flow at higher rates through acid stimulation. This is the first discovery in Kalat Plateau, opening up a new area for hydrocarbon exploration. Margand X-1 was the first well in the Margand EL block and it was spudded on 30 June 2019 using the “WDI-812” land rig with a prognosed TD of 4,500 m. Prior to initiating DST in early December 2019, PPL conducted wireline logging and modular dynamic testing which suggested the presence of hydrocarbons. Margand X-1 was drilling at 1,168 m depth during mid-July 2019, reached 1,743 m by the end of the month and progressed to 2,116 m depth during mid-August 2019. It was drilling at 2,800 m depth by the end of August, reached 3,488 m by mid-September and 3,669 m depth during late September 2019. It was drilling at 3,703 m depth in October 2019, progressed to 4,279 m by mid-November and reached the final TD of 4,500 m in late November 2019. Margand EL covers an area of 2,484 sq km and is located in Balochistan province. PPL currently hold 100% interest in the block. PPL reported in the 2H 2018 report in March 2019 that it has acquired 2,434 line km gravity and magnetic data in the block. The company had earlier acquired 261 line km of 2D seismic (dynamite source) in the acreage between December 2017 to April 2018 using the BGP 9501-B seismic crew.   Background Information PPL (operator), along with OMV, were awarded the Margand exploration license, with the Petroleum Concession Agreement (PCA) having been signed on 28 February 2014. The equity split at the time of award was as follows: PPL (50%, operator) and OMV (50%). It was subsequently announced in January 2017 that OMV has farmed out from the block assigning its full 50% interest to PPL, effective 30 June 2016. PPL was granted a 12-month extension to the Phase-I of initial term for Margand EL from 28 February 2017 to 27 February 2018. It was followed by a further 12-month extension to the Phase-I from 28 February 2018 to 27 February 2019. PPL was subsequently granted the renewal with licence entering into two-year Phase-II of initial term with effect from 28 February 2019.

Margand X-1 nfw. (PPL 100%) in Margand 2866-4 EL block, in Balochistan, gas discovery in the Middle Jurassic (Bajocian-Callovian) Chiltan Fm, DST'd 10,7 MMcfg/d + 132 b/d liquids [1" choke]. TD=4500m

Pan Orient continued a 90-days production testing on new-field wildcat L53 DD1 in the L53/48 concession, onshore Chao Phraya Basin, in late November 2018. The well was reported to have flowed at an average rate of 779 b/d of oil through 5.2 m of perforations between the depths of 1,157 and 1,162 m (1,116 – 1,121 m TVD) within the ‘DD sand’, since 23 November 2018. The measured density of the oil is approximately 24 degrees API gravity with Basic Sediment and Water (BS&W) of 0.4%. Located 5 km south of the U Thong oilfield, the deviated wildcat was drilled to a total depth of 1,373 m (1,323 m TVD) on 22 October 2018. The well was suspended on 22 November 2018 as an oil discovery and was immediately appraised by L53 DD2 well, which is also currently under a 90-day production test. The DD sand is the deepest of three oil bearing sands and represents 8 m of the 26 m of total interpreted net oil pay encountered in the well. The well encountered a combined 26 m of net oil pay from three zones across 165 m interval (960-1,125 m TVD), interpreted from wireline logs. The other two reservoirs, “BB sand” and “CC sand” share the same oil-water contact with the L53-DD2, which is 24 – 29 m structural high than those in L53-DD1. The reservoirs quality is excellent with high permeability which was confirmed by pressure data and oil samplings from each of the zones. The well is currently on beam pump with the fluid level at surface, which will continue for the remainder of the 90 days test period. The completion of L53 DD1 has fulfilled the USD 600,000 minimum annual expenditure that is required to retain the 214 sq km of the L53/48’s ‘Exploration Reserved Area’. The previous exploratory well, L53-AC-C1 was abandoned on 31 December 2017, with oil shows. A fluid sampling determined the oil shows area to be dominantly water-bearing reservoir. The L53/48 concession produced at approximately 455 b/d of oil in October 2018, as compared to 505 b/d of oil in late 2017. The concession holds a 2P crude oil reserves of 546,500 barrels from the Lower Miocene sandstone reservoir, excluding the exploration area (As of 31 December 2017). The L53/48 concession is fully owned and operated by Pan Orient (Siam) Ltd, which is in turn controlled by Pan Orient Energy Corp (50.01%) and Sea Oil Public Company (49.99%). The exploration Area A and B will expire in January 2021, after which the production areas (A, B, D and G) will be retained. Background Information The L53/48 block lies onshore in the Kamphaeng Saen Sub-basin of the Chao Phraya Basin, around 50km WNW of Bangkok. The area is covered by at least 580 sq km of 3D seismic data which were acquired since 2007. Seven minor oil discoveries were encountered from 2009 to 2013 with estimated total recoverable reserves of approximately 25 MMbbl. As of December 2018, a total of three fields are producing (L53-A, L53G, L53-D East), two are developing (L53-B and L53-DD) and another two fields are appraising (L53-D and L53-D C-EXT). The oils were trapped in the Lower to Middle Miocene structural play sealed by Middle Miocene Series mudstone. The reservoirs were deposited in lacustrine environment. The block also covers an area that was previously partially covered by BP’s B04/27 and Britoil’s Block BT concessions. It encompasses and excludes the Kampheang Saen field (previously called Neung), which was discovered by BP in February 1987. The original 3,997 sq km L53/48 block was awarded to Pan Orient Energy on 8 January 2007 as the operator and sole interest holder, under the 19th Licensing Round. The concession agreement allows Pan Orient to explore for hydrocarbons over a period of six years with a minimum three years first phase commitment of approximately US$ 2.1 million, which includes 3D seismic acquisition and two exploratory wells. On 2 February 2015, Pan Orient Energy Corp closed the sale of 49.99% of its own equity interest in Pan Orient (Siam) Ltd, which is in turn operator of the concession, to Sea Oil Public Company. With all conditions being met, Sea Oil transferred a consideration of USD 38.5 million to Pan Orient. Pan Orient (Siam) Ltd remained operator of the block with 100% interest, as an equally controlled subsidiary of Pan Orient Energy Corp and Sea Oil Public Company. In October 2016, the operator completed a five wells workover program which has increased production from 192 bo/d in August 2016 to 303 bo/d. The December 2016 production from L53-G1 was substantially reduced to approximately 100 bo/d, as a result of a replacement of downhole pump. The focus for the 2017 was to maximize production from the existing wells. In late 2016 and 2017, the operator attempted to find several upside potentials within the Miocene sandstone reservoirs by drilling L53-ANE-A1 and L53 AC C1 in the Reserve Area A. The wells failed to encounter hydrocarbons within the target intervals, which were determined to have excellent quality of sandstones.

Pan Orient Energy Corp L53/48 - L53 DD1, oil discovery, production test ongoing, The well was reported to have flowed at an average rate of 779 b/d of oil through 5.2 m of perforations between the depths of 1,157 and 1,162 m (1,116 – 1,121 m TVD) within the ‘DD sand’, since 23 November 2018.

Santos and KrisEnergy are seeking to farm-out up to equity in the SS-11 shallow water offshore block in Bay of Bengal. In late-August 2018, Ophir Energy Plc announces that in a general meeting held on 20 August 2018, the acquisition of southeast Asian non-core assets from Santos for aggregated cash considerations of USD 205 million pre-working capital adjustments, was approved by its shareholders. However, the company also states that transaction was conditional subject to this approval from shareholders but completion in respect to exploration assets, such as SS-11 block is also conditional upon, amongst other things, regulatory and certain consents, and respective pre-emption regimes. Ophir envisages a completion date for exploration assets to be in the first half of 2019. In early-August 2018, Ophir Energy Plc announced that the UK Listing Authority as of 3 August 2018 approved a class 1 circular in relation to the transaction of southeast Asian non-core Assets from Santos. It was announced in early May 2018 that Santos had entered into an agreement to sell a number of non-core Asian assets, including SS-11 in Bangladesh, to Ophir Energy Plc.  The deal remains subject to a number of approvals, but is expected to complete in 2H 2018. Santos and KrisEnergy each hold 45% stake in SS-11 block with Santos as the operator, with Bangladesh Exploration and Petroleum Exploration Company Ltd (BAPEX) holding a 10% carried interest. The Production Sharing Contract (PSC) for the award of SS-11 block was signed on 12 March 2014. The block, which covers 4,475 sq km area, was offered under the Bangladesh Offshore Bidding Round 2012, launched from 9 December 2012 to 29 July 2013 for shallow water blocks. On 21 August 2015, Santos had announced a strategic review with the aim of addressing the share price fall issue. The company is considering a range of options including asset sales, structured finance transactions, company restructurings, capital markets transactions and other strategic alternatives. It is understood that the company was looking for fast-track sale of its assets, including outside Bangladesh. Companies interested in this opportunity can contact: Chris Luxton - email: [email protected] tel: +618 8116 7192 Mike Whibley – email: [email protected]   Background Information Santos-KrisEnergy JV has committed to drill one exploration well in SS-11 block, carry out 1,876 line km 2D and 300 sq km 3D seismic during the initial five year exploration period and is expected to spend around USD 32 million for this work. The JV will provide a bank guarantee of USD 15 million. The five year Phase I will be followed by a three year second exploration period. SS-11, originally reported to cover an area of 4.622 sq km, straddles the margins of the Bengal Basin and Rakhine Basin. Portion of the block was under Block 18 (Block 17 & 18 PSC) last operated by Okland International LDC. This PSC was awarded in 1997 and was relinquished in 2011. Companies who have farmed-in to the block were Tullow, Total and PTTEP.  No wells have been drilled within the SS-11 block boundaries. Within the vicinity of the block, BODC 2 and BODC 3 dry holes were drilled by Bengal Oil Development Corp. from 1976 to 1977.

Santos and KrisEnergy are seeking to farm-out up to equity in the SS-11 shallow water offshore block in Bay of Bengal.

Corallian Energy announced on 1 August 2019 that it has completed the acquisition of Corfe Energy’s interests in the following licences – PEDL 345, PEDL 330, P1918, P2235 and three licences awarded in the 31st Frontier Licensing Round. One licence comprises blocks 98/11b and 98/12, another is made up of 12/27, 17/5, 18/1 and 18/2 and the last is made up of 11/23, 11/24c and 11/25b. In all these licences, prior to the deal, Corallian and Corfe were JV partners.   The acreage is located in the Moray Firth and Wessex Basin. Corallian drilled two wells which completed in early 2019, one on the Wick prospect (dry) and an appraisal well on the Colter discovery where it made the Colter South discovery. Following the completion of the deal Corallian will hold a 74% interest in its acreage in the Wessex Basin and a 45% interest in the Moray Firth.

Corallian Energy announced on 1 August 2019 that it has completed the acquisition of Corfe Energy’s interests in the following licences – PEDL 345, PEDL 330, P1918, P2235 and three licences awarded in the 31st Frontier Licensing Round. One licence comprises blocks 98/11b and 98/12, another is made up of 12/27, 17/5, 18/1 and 18/2 and the last is made up of 11/23, 11/24c and 11/25b. In all these licences, prior to the deal, Corallian and Corfe were JV partners.

Petronas has further extended the bid deadline for explo blocks in the 2020 Malaysia bidding round from 30 Jul '20 to 30 Nov '20. Contacts: Block Promotion ([email protected]) and Asset/Field Promotion ([email protected]). It is recalled 8 explo blocks, 4 Discovered Resources Opportunity clusters + 3 Technical Study opportunities are on offer. Exploration blocks lie off Peninsular Malaysia (PM-326, 416, 417 + 524) and in shallow - deepwater Sabah (SB-408, 410, 414 + 2T). DROs include the Diwangsa Cluster and Rhu-Ara Cluster in off Peninsular Malaysia, and the Bambazon + Kerisi clusters in shallow - deepwater Sabah. Technical Studies are mainly off Peninsular Malaysia, namely the MASA cluster + Tembungo field off Sabah + one gasfield (BIGST cluster). Data room via EzDataRoom to 30 Nov '20 for exploration and DRO Clusters.

(Northwest Sabah Province), Petronas has further extended the bid deadline for explo blocks in the 2020 Malaysia bidding round from 30 Jul '20 to 30 Nov '20. It is recalled 8 explo blocks, 4 Discovered Resources Opportunity clusters + 3 Technical Study opportunities are on offer. Exploration blocks lie off Peninsular Malaysia (PM-326, 416, 417 + 524) and in shallow - deepwater Sabah (SB-408, 410, 414 + 2T). DROs include the Diwangsa Cluster and Rhu-Ara Cluster in off Peninsular Malaysia, and the Bambazon + Kerisi clusters in shallow - deepwater Sabah. Technical Studies are mainly off Peninsular Malaysia, namely the MASA cluster + Tembungo field off Sabah + one gasfield (BIGST cluster).

Eni is understood to have applied for the Dumre block, 587 sq km in central Albania north of the Kuçova oilfield. Parallel rumours suggest Shell is also eying the tract to the north of its block 2 (Shpiragu).

Eni is understood to have applied for the Dumre block, 587 sq km, north of the Kuçova oilfield. Parallel rumours suggest Shell is also eying the tract to the north of its block 2 (Shpiragu).