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NE Obaiyed block, N. Egypt Basin, susp. mid-Nov '19 at TD 5,523m in the Ras Qattara fm.

Aster 1 nfw. (Shell 100%) in Northeast Obaiyed block, susp. mid-Nov '19 at TD=5523m in the Ras Qattara Fm. Results are not available.

Pancontinental Oil & Gas NL is offering a farm-in opportunity for interest parties for exploration permit EP 447, located in the Perth Basin. The permit contains the Walyering gas field, which was discovered in 1971 and produced a total of 261 MMcf of gas from the Lower Jurassic Cattamarra Coal Measures over a four-month period before the reservoir was considered depleted and production ceased. Currently, UIL Energy holds 100% interest in the licence but initiated a farm-in agreement with Pancontinental’s subsidiary company Bombora Natural Energy Ltd in 2016. The agreement is for an area over the Walyering asset, with Bombora negotiating 70% interest and operatorship. The companies have extended the farm-in agreement negotiations to end 2018. Evaluation of Walyering is ongoing as part of the agreement, with a planned 3D seismic survey scheduled. Conventional sandstone reservoirs of Jurassic age, similar to the Gingin West and Red Gully gas and condensate trend, have been identified in the permit area over a structure area of approximately 10 sq km. It’s considered that original drilling failed to target the highs due to poorly positioned 2D seismic data and that there’s a 57% chance of success in the Central High. Additional 3D seismic data is required to provide better definition at the gas reservoir levels. Pancontinental, as part of the farm-in agreement, is planning to conduct the Walyering 3D seismic survey in late 2018.  The survey is planned to commence in November, covering 90 sq km. Pancontinental will fund the survey, up to a capped amount of AUD 2.5 million, to earn the 70% interest in the Walyering, southern section, of the EP 447 permit.  The survey is being scheduled to be undertaken in conjunction with other seismic plans in the Perth Basin. In May 2018 Pancontinental released upgraded gas and condensate volumes for the Walyering field to gross figures of 100 Bcf gas and 2.5 MMbbl condensate. In the case that new 3D seismic data supports the current mapping and size of the undrilled compartments, Pancontinental reports that it will consider an appraisal / development well in 2019. Pancontinental, through its subsidiary company Bombora Natural Energy, is offering a farm-in opportunity for the Walyering field area of EP 447. The offer is reliant on Pancontinental completing a farm-in deal with UIL which will establish permit interests as: Bombora Natural Energy Ltd (70% & operator) and UIL Energy (30%). Parties interested in this opportunity should contact - John Begg, Pancontinental CEO Phone: +61 8 636 7090 Email: [email protected]

Pancontinental Oil & Gas NL is offering a farm-in opportunity for interest parties for exploration permit EP 447, located in the Perth Basin.

Commitment well in Siak PSC in Central Sumatra, TD 274m on 20 Mar ’18, only now reported as oil find, 2C resources 1.9 MMbo assumed in target shallow sst of the L. Miocene Bangko fm (Sihapas Grp).

Kumis 2 (Pertamina 100%) in Siak Area III PSC reported as oil find, 2C resources 2 MMbo assumed in target shallow sst of the L. Miocene Bangko fm (Sihapas Grp).

Australian Gasfields Ltd (AGF) and Beach Energy Ltd entered into an agreement in July 2017 for AGF to acquire complete interest in two Cooper-Eromanga permits: production licence PL 184 (Thylungra field) and exploration permit ATP 932-P. The deal will see AGF increase its interest to 100% in both permits. Currently, AGF holds 19.6% in PL 184 and has zero interest in ATP 932-P. The agreement was expected to be completed by end-January 2018, but registration by the Queensland Government remained pending as of December 2018. Since early 2016, Beach has undertaken geological and geophysical studies in PL 184, in which AGF has contributed around AUD 770,000. The studies have been focused on the determining commercial opportunities for the Thylungra discovery.  PL 184 was awarded on 13 September 2001 and is due to expire on 12 September 2021. Both Beach and AGF have participated in the permit since October 2001. Beach Energy currently holds its interest through Beach Energy Ltd (74.2% + operator) and subsidiary company Mawson Petroleum Pty Ltd (6.2%). ATP 932-P covers at area of 1,541 sq km and was awarded on 15 February 2013. Beach had been offering a farm-in opportunity in the block after a deal with Real Energy to acquire 50% interest failed to complete in 2012. ATP 932-P is currently 100% owned by Beach Energy, through its subsidiary companies: Drillsearch Energy Pty Ltd (50% + operator) and Circumpacific Energy (Australia) Pty Ltd.

Australian Gasfields Ltd (AGF) and Beach Energy Ltd entered into an agreement in July 2017 for AGF to acquire complete interest in two Cooper-Eromanga permits: production licence PL 184 (Thylungra field) and exploration permit ATP 932-P.

OMV and Sapura Energy have agreed on a strategic partnership under which OMV will buy a 50% stake of the issued share capital in a new JV designated SEB Upstream (SUP). OMV will pay USD 540 MM for its stake, however the parties also agreed to an additional (up to) USD 85 MM based on certain conditions mainly linked to resources in block 30, Mexico. Through this deal OMV aims towards establishing Australasia as a new core region. Completion of the deal is subject to Sapura Energy’s shareholder approval, Petronas approval and other 3rd party consents inter alia.

OMV and Sapura Energy have agreed on a strategic partnership under which OMV will buy a 50% stake of the issued share capital in a new JV designated SEB Upstream (SUP). OMV will pay US$540 MM for its stake.

In late October 2019, operator Kosmos Energy Ltd (Kosmos) has hit a 39-m net oil pay in its S-5 exploration well in Block S, offshore Rio Muni Basin. The well (AKA G-13 ILX for Infrastructure-Led Exploration), was spudded on 20 September with the “Maersk Voyager” drillship. The company explained that oil was encountered in good-quality Santonian reservoir (Upper Cretaceous). With this success, Kosmos sees a potential for an accelerated development through the existing nearby infrastructures (Ceiba and Okume Complexes). First oil for G-13 is therefore expected around 2021. S-5 is considered as an appraisal well by IHS Markit, as it is located in the center of G-13 oil discovery made in 2002 by Triton Energy. It targeted the G-13 main reservoir fairway (prospecting resources estimated at 50 MMboe). Kosmos mobilized the “Maersk Voyager” drillship on 18 September. This well is part of a five-well programme for Kosmos, including one basin-opener in Mauritania, and three exploration wells in the Gulf of Mexico, all to be drilled in 2019. Of note, Kosmos is believed to have a good understanding of the regional geology of Rio Muni Basin, as Kosmos was formed in 2003 from Triton people, who discovered Ceiba in 1999. As of February 2019, Kosmos Energy was estimating the G-13 oil discovery recoverable reserves around 56 MMboe. Three outposts were drilled after the discovery (two in 2003 and one in 2014), but the development of the field was never made possible because of the failure to clearly identify the Senonian main fairway. Recent new seismic material apparently helped the company to image it.

S-5 (G-13 ILX) expl. (Kosmos ) S. part of G-13 oil discovery area in block S, 39m net oil pay in the Santonian, The scale of the resources is under evaluation, well in tieback range of the Ceiba FPSO. G-13 'ILX' stands for Infrastructure-Led Exploration. WD=800m, TMD= 4400m.

On 27 March 2018, Repsol with 100% working interest was granted a preliminary award for the 814 sq km Area 5, G-BG-05 block and 811 sq km Area 12, G-BG-07 block from the CNH-RO3-LO1/2017 Bid Round.  The final official contract signature award is to take place within 90 days or 1 July 2018. The company bid 56.29% state take over the minimum of 22.5% for the Area 5 block and 48.17% for the Area 12 block. The company bid 0 in additional work units factor equivalent to no exploration wells. There was one other bid for the Area 5 block by PEMEX who offered 23.89% state take and 0 additional work unit factor. There were no other bids for the Area 12 block.

Repsol with 100% working interest was granted a preliminary award for the 814 sq km Area 5, G-BG-05 block and 811 sq km Area 12, G-BG-07 block from the CNH-RO3-LO1/2017 Bid Round.

SDX has secured operating rights to the Moulay Bouchta Ouest and Lalla Mimouna Sud licences: -Moulay Bouchta Ouest: 458 sq km in the Rharb, to SDX 75% for 8 years, Commitments 150km 2D seismic reprocessing, 100 sq km of new 3D + 1 well in 3.5 years.   -Lalla Mimouna Sud, 857 sq km in the Rharb-Prérif, to SDX 75% for 8 years. Commitments 50 sq km of 3D seismic 1 well within 3 years. Partner Onhym.  www.sdxenergy.com.

SDX has secured operating rights to the Moulay Bouchta Ouest and Lalla Mimouna Sud licences.

Block 6, S. Oman Salt sub-basin, drilled 10 Feb – 9 Mar '20, TD 2,397m.

Wafra N.-2 expl Block 6, S. Oman Salt sub-basin, drilled 10 Feb – 9 Mar '20, TD 2,397m.

According to reports in late-January 2018, Echo Energy has completed the acquisition of 50% interest from Cia General de Combustibles (CGC) in Laguna de los Capones block and the surrounding Fraccion C & D (or Blocks C & D) of the Santa Cruz I concession, as well as the recently awarded Tapi Aike block. The transaction was originally signed in November 2017, and said to include a USD 2.5 million cash consideration for Laguna de los Capones and Fraccion C & D, while there was no upfront cash consideration for Tapi Aike. Laguna de los Capones (413 sq km), Fraccion C & D (5,804 sq km total), and Tapi Aike (5,147 sq km) are situated in onshore Austral Basin within the Province of Santa Cruz. Laguna de los Capones (413 sq km) and Fraccion C & D (5,804 sq km total) are producing blocks where Echo plans to carry CGC’s 50% interest during the initial work program in the next 18 months. Commitment for Laguna de los Capones consists of reprocessing and analysis of existing 3D seismic in the area. Work program for Fraccion C entails the acquisition of 500 sq km 3D seismic and the drilling of 4 exploration wells, while the program in Fraccion D includes the workover of 3 wells and the drilling of a new exploration well (pending on positive results from said workovers), along with acquisition of 230 sq km of 3D seismic. The latter commitment is transferable to Fraccion C block, pending on results of said workovers too. Tapi Aike block was awarded to CGC in September 2017. Work commitments for the block was said to include reprocessing of existing 2D and 3D seismic, acquisition of 1,200 sq km of 3D seismic, and the drilling of 4 exploration wells in the first exploration phase of three years (or four if tight gas play is developed). It is worth noting that the Argentinean government recently announced in November 2017 that the country has expanded the subsidies in its “Gas Plan” to also cover unconventional natural gas production from the Austral Basin. Echo will carry CGC for 15% of the total work program in Tapi Aike block.

Argentina (Austral B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Laguna de los Capones (CA-2 M) op. by CGC (100.0%) to be check.Tapi Aike op. by CGC (100.0%) to be check.

Ledong block, Yinggehai Basin SW of Hainan in WD 80m, compl. gas end Dec ’18, tested the HPHT Miocene turbidite play. Kantan 3 SS.

Ledong block, Yinggehai Basin SW of Hainan in WD 80m, compl. gas end Dec ’18, tested the HPHT Miocene turbidite play.

Aladdin Middle East Ltd completed and brought onstream the Petek 2 appraisal well in October 2017. The well, which is located in Block L44-d4-2, southeast Turkey, was spudded on 28 August 2017. The Petek 1 exploration well was completed as an oil production well on 12 February 2014 after reaching a TD of 2,917m. Three drill stem tests (DST), one of which was bypassed, were conducted in the Cretaceous Mardin Group. The third DST reportedly recovered some light oil.  Based on these results the well was put on test production and completed as a Mardin Group producer.  During production tests at this reservoir, the well started artesian flow at varying rates and finally settled at 90 bbls per day of light oil of 35.9° API gravity with 0% water cut using a 14/64" choke. Block L44-d4-2 covers an area of 13.6 sq km and was first awarded in October 2014. Aladdin (50%, operator) is partnered in the block by Guney Yildizi Petrol 50%.    

Turkey (Zagros Province) Petek 2 op. by ALADDIN (50.0%, GUNEY YILD 50.0%) in L44-D4-2 block

South Betung block in S. Sumatra, oil discovery, ops terminated Feb ’19. Targets assumed Air Benakat + TAF, no details.

Indonesia (South Sumatra B.) Benakat

Total spudded exploration well 30/12d-11 in licence P1820 on 13 October 2019 targeting the Isabella prospect. The HP/HT (12,960 psi and 175 degrees centigrade) gas condensate prospect was understood to be located on one of the largest undrilled fault blocks in the Central North Sea. The well was drilled with the Noble Sam Hartley (J/U). On 17 March 2020 Total announced that it had made a discovery. A total of 64 m net pay of lean gas and condensate and high quality light oil in Upper Jurassic and Triassic sandstone reservoirs has been encountered. Partner Neptune announced that hydrocarbons had been encountered in three separate formations. Further analysis of the discovery is ongoing to determine the discovered resources, subsequent appraisal programme and confirm commerciality. The Isabella trap is formed by closure on a salt pierced anticline. The reservoir target was the Triassic Joanne and Judy Sandstones. The well was planned to be slightly deviated with an estimated TD of 5,607 m. P1820 was awarded in the 26th Offshore Licensing Round to Valiant and Apache North Sea Ltd. On 23 September 2013 Ithaca announced that it has agreed to farm down a 10% interest in licence P1820 (blocks 30/6b, 30/11a and 30/12d) to Edison subsidiary EDF Production UK Limited in return for a cash payment. It was confirmed that the deal completed on 31 December 2013. On 13 August 2018 Neptune announced that it had agreed to acquire Apache’s interest in the licence and then late 2018 / early 2019 the operatorship was transferred over to Total. Interest in P1820 is held by Total E&P North Sea UK Limited (30% + operator), Neptune E&P UK Limited (50%), Edison subsidiary, Euroil Exploration Limited (10%) and Ithaca Energy (UK) Limited (10%).

United Kingdom (Silverpit B. (Anglo-Dutch B.)) Neptune

The Jardfeingi has confirmed that it is aiming to launch its 5th Licensing Round in July 2019. The company is looking to run the round in conjunction with the UK 32nd Round also due to launch in July 2019. The round will run until November 2019. A total of 9,418 sq km will be on offer. The Jardfeingi opened the 4th Exploration Licence Round on 17 May 2017. The round was open for nine months and closed on 17 February 2018. The area open for bidding was mostly the east and south east of the Faroe Islands with blocks and part blocks from quads – 6004, 6005, 6103, 6104, 6105, 6201, 6202, 6204, 6205 and 6301 on offer. On 19 February 2018 the Jardfeingi announced that one application had been received from the round (unnamed company or location). On 26 April 2018, Jardfeingi reported that following processing of the application and further discussion, the applicant made the decision to withdraw it.

The Jardfeingi has confirmed that it is aiming to launch its 5th Licensing Round in July 2019. The company is looking to run the round in conjunction with the UK 32nd Round also due to launch in July 2019.

ConocoPhillips used the “Leiv Eiriksson” S/S to drill an exploration well in PL 917 targeting the Enniberg prospect. 25/7-8 S lies just 6 km southeast of the Busta well (in adjacent PL 782 S - see separate article), which was drilled immediately prior to this well, on the first fault terrace out of the basin. Enniberg was spudded on 13 November 2019 and had potential, pre-drill recoverable reserves, according to partner Lundin, of 69 MMboe. Its objectives were the Lower Jurassic Nansen Formation at 2,856 m and the Upper Triassic Eiriksson Formation at 2,885 m. TD was reached at 3,250 m and on 9 January 2020 the well was abandoned. Results are expected imminently. 25/7-8 S is located just 2 km northeast of Conoco’s 1997 dry hole 25/7-4 S. This well had a Paleocene Hermod Sandstone target in a stratigraphic trap. The sands were present but there were no indications of hydrocarbons. Interest in PL 917 is held by ConocoPhillips Skandinavia AS (40% + operator), Lundin Norway AS (20%), Suncor Energy Norge AS (20%) and Var Energi AS (20%).

025/07-08 S (Enniberg) in PL 917 P&A results are expected imminently, its objectives were the Lower Jurassic Nansen Fm at 2,856 m and the Upper Triassic Eiriksson Fm at 2,885 m.

AIM-listed Diversified Gas & Oil, a leading independent US based gas and oil producer focused on the Appalachian Basin, has announced that the Company has completed its acquisition, previously announced on 9 February 2018, of certain oil and gas leaseholds, wells, working interests, licenses, related equipment and other assets from CNX Gas Company. The conditions of the sale and purchase agreement have been met in full, with the Asset Acquisition being effective from 1 January 2018.Also as previously announced, DGO paid a cash consideration for the Assets totalling US$85.0 million from its existing facilities. Inclusive of the acquisition of these Assets and those purchased earlier this month from Alliance Petroleum, the Company estimates its total net working interest production now exceeds 28,000 boed, and that its net working interest of proved, developed and producing ('PDP') reserves approximate 173 MMboe.Importantly, the Company's borrowing base under its credit facility led by KeyBank National Association increases to $200 million from its current $140 million level, providing the Company significant liquidity to pursue additional acquisition opportunities without the need for additional equity capital and without exceeding its commitment to maintain a leverage profile. As previously announced, the credit facility significantly reduced the Company's interest rate from nearly 10% on amounts outstanding under its previous facility agreement to approximately 4.5% on current borrowings under this credit facility.CEO Rusty Hutson commented:'While 2017 was undoubtedly a remarkable year for DGO, the month of March 2018 has produced the most transformative catalysts to our business since admission to AIM.  Over the past 30 days, we have nearly tripled our net daily production, more than tripled our PDP reserves and halved our cost of borrowing.  As of today, we are one of the largest production companies on AIM and have a diverse and impressive acreage position underpinned by a substantial proven reserve base with minimal decline rates.  We are making positive headway with the integration process of the recently completed Alliance assets and expect a similarly smooth integration of these CNX assets.Collectively, our two latest acquisitions combined with our syndicated credit facility create long-term value for shareholders and fulfil our commitment to a progressive per-share dividend.  Importantly, our progress in 2018 and significant borrowing capacity under our credit facility places us in a position of financial strength to continue our pursuit of high-quality growth opportunities while maintaining our commitment to low leverage.'Original article linkSource: Diversified Gas & Oil

Diversified Gas & Oil, a leading independent US based gas and oil producer focused on the Appalachian Basin, has announced that the Company has completed its acquisition,

Diamond is offering equity and possibly operatorship in EP-371,  3,675 sq km wholly-owned in the Canning Basin. It contains the 1988 Crimson Lake oil discover, and Valhalla, Valhalla North and Asgard shale gas fields. Contact: Taisei Furukawa, [email protected], or Jeff Feltham, [email protected].

Australia, EP 371

Sinochem has sold its 40% in the Belida field/block in S. Sumatra to Sele Raya, arguing that low production no longer justified its presence here. Invenire Petrodyne (14%) has likewise pulled out, Sele Raya now sole holder of the 666-sq km block.

Indonesia (Salawati B.), Sinochem has sold its 40% in the Belida field/block in S. Sumatra to Sele Raya.

Santos Ltd was awarded production license PL 1051, located in the Cooper- Eromanga Basins, on 7 November 2019. The license has been awarded for a period of five years and is scheduled to expire or be renewed on 6 November 2024. Santos applied for the licence, which covers an area of around 91 sq km, in July 2018, and replaces the previously held PL 208, which expired on 7 July 2018. PL 1051 contains the Hebe field, which was discovered in January 2004 and commenced production later the same year. PL 1051, which covers 91 sq km was awarded on 7 November 2019. Participants in the license are Santos Ltd (28.125% interest and operatorship), Vamgas Pty Ltd (5.625% interest), Santos Petroleum Pty Ltd (18.75% interest), Delhi Petroleum Pty Ltd (22.5% interest) and Lattice Energy Ltd (25% interest).

Australia, PL(A) 1051

As announced on 19 September 2018, Global Petroleum (Global) signed a petroleum agreement to acquire the Walvis Sub-basin Block 2011A. The block covers some 5,800 sq km and is located adjacent to the east of Global’s PEL 029 (Block 1910B and 2010A). The 2014 Repsol operated Welwitschia-1A well is located in the western portion of the acreage. Welwitschia-1A targeted Upper Cretaceous sands on the crest of a large structure but did not encounter a reservoir. Global believes there to be significant prospectivity in the deeper Albian carbonates which were not tested with the well but also believe additional prospectivity exists in the upper Cretaceous/Tertiary reservoirs on the eastern flank of the Welwitschia structure. Work Programme Commitments: Initial Exploration Period Years 1 and 2 Undertake geological, geochemical and geophysical and related studies of all the data, including a gravity and magnetic study as well as a source rock and basin modelling study. Licence the existing 2010-vintage 3D seismic data survey, and all 2D seismic data of reasonable quality and reprocess it. Initial Exploration Period Years 3 and 4 If the Company elects to continue into years 3 and 4 , then additionally the Company will acquire and process two thousand (2,000) square kilometres of 3D seismic data in the Eastern Area. If the Company elects not to enter into years 3 and 4, the Block shall be relinquished. First and Second Renewal Exploration Periods The Company will then have the right to enter into the First and Second Renewal Periods of two years each by committing to the relevant work programmes set out in the Petroleum Agreement.   The block is operated by Global Petroleum Namibia Limited (a subsidiary of Global Petroleum Limited) with an 85% interest. Partners are National Petroleum Corporation of Namibia (Proprietary) Limited with a 10% stake and Aloe Investments Two Hundred and Two (Pty) Ltd with a 5% stake. Background information The block formed part of PEL0010 which Tower Resources plc had reapplied for, but is assumed to have been rejected.

Global Petroleum (Global) signed a petroleum agreement to acquire the Walvis Sub-basin Block 2011A. The block covers some 5,800 sq km and is located adjacent to the east of Global’s PEL 029 (Block 1910B and 2010A). The 2014 Repsol operated Welwitschia-1A well is located in the western portion of the acreage. Welwitschia-1A targeted Upper Cretaceous sands on the crest of a large structure but did not encounter a reservoir.

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

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

Committed well in Abu Sennan block, Abu Gharadiq Basin, drilled 21 Oct – 22 Nov '19, TMD 4,030m (Alam El Bueib), 50m net oil pay in fresh, undepleted reservoir, tested 7,027 + 3,851 bo/d resp. from U&L intvs, on stream 2 Jan '20 at 3,000 b/d on 1/2" choke. KE (op), partners Global Connect, Rockhopper (selling out to United O&G) + Dover Investments.

Egypt (Abu Gharadiq B.) ? op. by UNITED EN (25.0%, DOVER PT 28.0%, GLOBAL CON 25.0%, UNITED OG 22.0%) in Abu Sennan block

By October 2018, Kuwait Energy had concluded drilling operations in its West El Khalig 1X NFW. Results are not yet available. The well was spudded in mid-Q3 2018 by the Egyptian Chinese Drilling Company #6 rig, and reached a TD of 1,326m. Total well costs were ~US$ 12 million. West El Khalig was drilled on the Umm El Yusr development lease (DL) of the Area A EPSA, onshore western Gulf of Suez. The well lies ~2km NW of General Petroleum Company's (GPC) 1980 El Khalig 4 Miocene oil discovery (TD 2,033m) and ~2km north of the Umm El Yusr Field. It is the third NFW drilled on the licence in 2018, following the North El Khalig 1X well in July 2018 and the January 2018 South Kheir 1X ST Miocene Kareem sandstone oil discovery on the adjacent Kheir DL.The "Area A" EPSA comprises six contiguous DLs. It is operated under an Exploration & Production Service Contract with state-entity GPC. Under the terms of the rare risk-service agreement, contractors/IOCs carry all the cost of exploration activity. If a development lease is granted and production commences, then contractors are paid a service fee related to output, with the state (in the form of GPC), entitled to 100% of production. Kuwait Energy (70% WI) and Petrogas (30% WI) signed the agreement in 2013. GPC holds the concession rights with 100% equity. In September 2018, Chinese-firm United Energy Group (UEG) signed a deal to acquire Kuwait Energy. As of 31 December 2018, the deal has not been concluded.

Kuwait Energy had concluded drilling operations in its West El Khalig 1X NFW. Results are not yet available.

In early February 2019, Arabian Gulf Oil Co. (Agoco) plugged and abandoned the exploration well A1-59/3 in Area 059 (Block 3) with dry results. The well was spudded on 20 October 2018 with the DECS-26 rig with a planned TD of 2,484 m. Arabian Gulf Oil Co. is the operator of the Area 058 (Block 3) with the 100% of interest. The company is fully owned by the National Oil Company (NOC).

A-001-059/3 (Arabian Gulf Oil Co. (Agoco) 100%) in Area 058 (Block 3), P&A dry.

Premier spudded appraisal well 42/28d-14 on Tolmount East on 8 August 2019. The well targeted the Tolmount East structure located in block 42/28d (P1330). The company used the “Valaris 123” J/U to drill the well. On 17 October 2019 it was announced that the well had penetrated a 241 ft gas bearing section of high quality Leman sands with a net-to-gross of 71%, porosity of 16% and gas saturation of 82% and no gas-water contact was found. The reservoir was successfully cored with 216 ft being recovered. The well data will be pulled into the 3D dataset as Premier looks to fast-track Tolmount East to be tied into the Greater Tolmount Area project. The results of this well have positive implications for further upside in the area including Tolmount Far East and the Mongour discovery. On 20 November 2019 it was confirmed that the rig left location that day. Tolmount was discovered with well 42/28d-12 in 2011. The well encountered a gas column in excess of 200 ft (61 m) within the Permian Leman Sandstone. The well tested and flowed at a rate of 50 MMcfg/d. Tolmount is a simple structural prospect which was mapped at Top Rotliegend level, the overlying Silverpit Formation and Zechstein evaporites provide top seal and gas charge is from the underlying Carboniferous coals. Interest in licence P1330 is held by Premier Oil E&P UK Limited (50% + operator) and Dana Petroleum (E&P) Limited (50%).

42/28d-14 (Tolmount East) pos. appr. (Premier op. 50%, Dana Petr. 50%) in P1330, Silverpit Platform, 73m gas zone in the Rotliegend Leman sands, net-to-gross ratio 71%, 16% porosity, gas saturation 82%, GWC encountered. To be susp. as a future producer, WD ca. 15m.

In late August 2017, Apache Corporation abandoned the Kalabsha West Anhuret 1 (Ie010-2) exploration well in the West Kalabsha exploration block at a TD of 5,108 m after recovering oil shows. The well was spudded on 23 July 2017 using the “EDC-54” land. It had a planned TD of 5,225 m and the Alam El Bueib 1, Alam El Bueib 3G and Alam El Bueib 3C units as the objectives, The West Kalabsha exploration block is operated by Apache Oil Egypt (67%) and Sinopec International Petroleum E&P Corp (33%).

Kalabsha West Anhuret 1 (Ie010-2)operated by Apache Oil Egypt (67%) and Sinopec International Petroleum E&P Corp (33%)in West Kalabsha exploration block P&A at a TD of 5,108 m after recovering oil shows.

ENEVA suspended with oil and gas shows the 4-ENV-WTIANGUAR-MA (4-ENV-010-MA) new-pool wildcat (NPW) in the PN-T-048 block during early-January 2020. ENEVA filed an oil and gas show report for the well with the ANP on 30 December 2019. This is the second appraisal well in the block to file an oil and gas show report. It is unusual in that most of the wells in the Parnaiba Basin only have gas shows. The NPW was spudded on 6 December 2019. The NPW has a proposed total depth (PTD) of 2,722 m. The Devonian Cabecas Formation and the Mississippian Poti Formation are the primary targets. The NPW is located in the north-central area of the block approximately 2.96 km west of the 4-ENV-SWPGN1-MA (4-ENV-006-MA) suspended with oil and gas shows in October 2019. ENEVA SA has 100% working interest in the BT-PN-004 contract, PN-T-048 block. On 8 August 2019, ENEVA SA suspended with oil and gas shows the 4-ENV-SWPGN1-MA (4-ENV-006-MA) new-pool wildcat (NPW) in the PN-T-048 block. It is assumed the operator re-entered the well for additional testing during September or early-October 2019 since the drilling operations were concluded on 1 August 2019 at a final total depth (TD) of 2,334 m. However, the ANP officially reported it was concluded on 8 August 2019 but the operator filed an oil and gas show report in mid-October. The operator filed a gas show report for the well with the ANP on 9 August 2019 and then an oil and gas show report on 17 October 2019. This represents one of the few oil shows filed for any wells drilled in the basin. The NPW was spudded on 21 July 2019. The NPW had a proposed total depth (PTD) of 2,215 m. The Devonian Cabecas Formation and the Mississippian Poti Formation were the primary targets. The NPW is located in the north-central area of the block approximately 4.4 km south south-west of the 1-PGN-FAZTIANGUAR-MA (1-PGN-001-MA) new-field wildcat (NFW) suspended with gas shows in April 2014. On 11 July 2019, the ANP approved a 4th modification to the discovery evaluation plan (PAD), modified from the 3rd modification on 19 June 2019, for the discovery evaluation plan (PAD) for the 1-PGN-FAZTIANGUAR-MA (1-PGN-001-MA) new-field wildcat gas discovery of the Eneva operated BT-PN-004 contract, PN-T-048 block. The ANP granted the operator an extension from 25 June 2019 to 4 September 2019 to drill a contingent well and stimulate the zone contingent on results or relinquish the PAD. If all commitments are completed, then the final expiry date will be 4 November 2019 extended from 4 October 2019. In mid-March 2019, ENEVA SA made a part relinquishment of the remaining valid exploration area of the BT-PN-004 contract, PN-T-048 block retroactive to 14 November 2018. The BT-PN-004 contract covered a total area of 1,455.2 sq km in two separate blocks, Block 1 of 1,057.18 sq km and Block 2 of 398.02 sq km. PGN relinquished all of the 398.02 sq km BT-PN-004 contract, Block 2 associated with the 1-OGX-FAZENDAHAVANA-MA (1-OGX-115-MA) gas discovery completed in 2013 but apparently non-commercial after plugging the 4-PGN-FAZHAVANA-002D-MA (4-PGN-026D-MA) new-pool wildcat (NPW) in early-August 2018.The remaining valid exploration area includes the entire 1,057.18 sq km Block 1 associated with the 1-PGN-FAZTIANGUAR-MA (1-PGN-001-MA) new-field wildcat gas discovery from April 2014.That discovery is yet to be appraised.

4-ENV-WTIANGUAR-MA (4-ENV-010-MA) npw in N-C part of PN-T-048 block, Parnaíba Basin onshore, oil shows report to ANP 30 Dec '19, susp. early Jan '20. PTD was 2,722m, targets Cabeças + Poti fm's.

On 1 July 2018, BP Exploration & Production was awarded Mississippi Canyon Block MC 564 (G36253), located in the Gulf of Mexico Basin. The block was originally offered as part of OCS Lease Sale 250, held in March 2018. Following official award, BP Exploration & Production is now the operator and sole interest-holder (100% WI + Op) in MC 564.

On 1 July 2018, BP Exploration & Production was awarded Mississippi Canyon Block MC 564 (G36253), located in the Gulf of Mexico Basin. The block was originally offered as part of OCS Lease Sale 250, held in March 2018. Following official award, BP Exploration & Production is now the operator and sole interest-holder (100% WI + Op) in MC 564.

A giant gas field is looking likely in the North Ustyurt Basin, Karakalpakstan in NW Uzbekistan, the well yielding unspecified (gas kick) volumes of gas on 27 Jun ‘19. The area comprises the Arslan, Surgil Quyi (Surgil Lower) and Surgil Janubiy (Surgil South) finds, now thought to be probably parts of a single gasfield east of the Surgil field per se.

Arsian 12 expl, (UzKorGasChemical 100%), a giant gas field is looking likely in the Karakalpakstan in NW Uzbekistan, the well yielding unspecified (gas kick) volumes of gas on 27 Jun ‘19. The area comprises the Arslan, Surgil Quyi (Surgil Lower) and Surgil Janubiy (Surgil South) finds, now thought to be probably parts of a single gasfield east of the Surgil field per se. All these discoveries are located east of the large Surgil field. No further details of the new discovery have so far been released. The Surgil field was discovered by UNG in 2002. Its official published reserves stand at 4,1 Tcf of gas. It has multiple clastic reservoirs in Middle-Upper Jurassic continental deposits in a depth range from 1725 to 2721 m.

SK-410B off Sarawak, TD 3,810m, 252m net gas pay, tested constrained 41.3 MMcfg/d + 246 bc/d, co’s largest discovery to date, Naga 6 JU.  Target M. Miocene Cycle V carbs / NE extent of the Lang Lebah-1 gas find (Nippon Oil, 1994). PTTEP (op), partners Kufpec + Petronas.

Lang Lebah 1RDR2 nfw, (PTTEP 42,5% op, KFPEC 42,5%, Petronas 15%) at the shallow water SK 410B block, intersected 252m of net gas pay. The well was tested in targeted M. Miocene Cycle V carbs / NE extent of the Lang Lebah-1 gas find and flowed at a completion constrained rate of 41,3 MMscf/d of gas and 246 bcond/d [0,62-inch choke]. Initial well testing was understood to have encountered H2S (TBC). Operator said the results from the well indicated a multi-Tcf find, while claiming it was the largest discovery in the company’s history. TD=3810m.

Azimuth Group's subsidiary Azinor received a Letter of Intent (LOI) from an unconfirmed party, which may farm in for non-operated equity in P2165 (Boaz), P2317 (Goose) and P2179 (Hinson), as announced on 10 December 2018. AziNor was farming out part equity in all three licences to participate in a 2019 drilling campaign. AziNor was offering 50-75% from its 100% in P2165 which covers part-block 16/8c and contains the drill ready Boaz prospect, N of the Enoch Field. Boaz has a Triassic Skaggerak Formation (Fm) reservoir, with 37% geological chance of success (CoS) and Pmean prospective resources are 242 mmboe. Azinor was farming down from 80% of its 100% stake in P2317 over part blocks 14/13a, 14b & 15b, 12km N of the producing Claymore Field. It contains the Goose prospect, a stratigraphic trap in Lower Cretaceous Scapa sandstone with Pmean prospective resources of 75 mmboe and 36% CoS. Azinor was farming down from 49% in P2179 - 21/25c which is operated by MOL (51%), and is located S of the Gannet and Guillemot complexes and W of the Annasuria Cluster. It contains the Hinson prospect which is estimated to hold 97 MMbo and 178 Bcfg P50 recoverable resources in Late Jurassic sands within a Kimmeridge Clay stratigraphic trap. Azinor recently had success with the 2018 Agar-Plantain appraisal/discovery with estimated recoverable resources of 15-50 MMboe.<P />

United Kingdom, P2179

SE part of CNH-R03-L01-AS-CS-15/2018 contract, Olmeca project area in offshore Sureste Basin, WD 19m, drilled early Jul - early Aug ’19, susp oil early Oct '19, Odin JU then to Tolteca prospect in the same block. PTD was 910m. Hokchi (op), partner Talos.

Mexico (Comalcalco Sub-basin (Sureste B.)) Hokchi

Believed in Paliyad-Kalol-Limbodra ML, onshore Cambay Basin, drilled Nov-Dec '19, TD 1,750m, some o&g (shows) after testing 'Object I'.

LM XB expl Believed in Paliyad-Kalol-Limbodra ML, onshore Cambay Basin, TD=1,750m, some o&g (shows) after testing 'Object I'.

Twinza secured sole rights to PPL 584, 680 sq km on the offshore Fly Platform around Twinza's own Pasca A field, for 6 years on 14 Feb '20.

Twinza Oil was awarded exploration licence PPL 584, located in the offshore Fly Platform. The licence covers an area of nearly 680 sq km surrounding the Pasca A field.

On 14 August 2020, Petrobras informed it signed an agreement with SPE Fazenda Belem S.A., a fully owned subsidiary of 3R Petroleum e Participacoes S.A., for its 100% working interest in the Fazenda Belem and Icapui production concessions, in the onshore Potiguar Basin. The transaction had a value of USD 35.2 million, with USD 8.8 million paid on the contract signature date. Another USD 16.4 million will be paid when the deal closes and the last USD 10 million will be paid 12 months after the closing of the negotiation. The deal is subject to Agencia Nacional do Petroleo (ANP) approval. Petrobras was the operator of the 307.52 sq km Fazenda Belem and the 37.27 sq km Icapui production concessions with 100% working interest. The concessions were officially awarded on 6 August 1998 as part of the ANP Round 0. The following table includes some general information about the fields: Fazenda Belem cluster - general information Field Name Field sqkm Disc Date Year Prod Start Date Avg. API gravity Avg. 2020 oil prod. (bo/d) (6/2020) Avg. 2020 gas prod. (Mcfg/d) (6/2020) Fazenda Belem (Potiguar) 411.48 1980 1980 14 804.5 34.3 Icapui 3.52 1996 1996 21 3.4 0.2 Source: IHS Markit © 2020 IHS Markit   Background Information 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. This represents about one-fourth of the fields the company offered when it announced the sale of the Topaz project in 2016 with some additions and some reductions. The company also published the marketing teaser for the proposed five packages.

Petrobras informed it signed an agreement with SPE Fazenda Belem S.A., a fully owned subsidiary of 3R Petroleum e Participacoes S.A., for its 100% working interest in the Fazenda Belem and Icapui production concessions.

Enping Sag, PRMB, WD 90m, compl mid-Jun ‘18, TD 4,002m (Pre-Tertiary basement), results n/a, Nanhai 5 SS. Target Mio-Oligocene clastics.

Enping 12-2-1d (EP 12-2-1d) nfw Enping Sag, PRMB, WD 90m, compl mid-Jun ‘18, TD 4,002m (Pre-Tertiary basement), results n/a, Nanhai 5 SS. Target Mio-Oligocene clastics.

In mid-January 2018, official reports indicated that GeoPark has completed the Uaken 1 new-field wildcat (NFW) as a gas well on the company’s 100%-held Fell block. The well was said to average 800 Mscf/d through different chokes during production testing from the seldom explored shallow Miocene-age El Salto Formation sandstone. Uaken 1 was spudded sometime in mid-2017, and reached a total depth (TD) of 3,658 m (12,001 ft) in late-2017. There are no details available regarding the original target objective of the well. The Fell block covers approximately 1,506 sq km of onshore land in the Magallanes Basin. Recent success in the block included the Ache 1 gas discovery that was drilled and completed at total depth of 2,999 m (9,694 ft) in June 2014, where it tested an average gas production rate of 9.2 MMcfg/d in the Tobifera Formation and was put on stream in the third quarter of 2015 at the producing rate of 7 MMcfg/d. In addition, the reports also suggested that GeoPark is now considering the possibility of re-entering past discovery wells in Fell block to test the El Salto formation after Uaken 1.

Uaken 1 op. by Geopark (100%) in Fell block, tested 800 000scfg/d avg. on various chokes from the El Salto fm, a stabilised flow is yet to be determined. This discovery in the shallow El Salto fm. provides additional low-cost production and creates a new gas play across the block that can be tested in identified leads and prospects.

The Queensland State Government has opened ten areas for bidding, all located in the Bowen-Surat Basin, on 1 November 2018.  The ten areas, covering a total area of 6,628 sq km, will close for bidding on 28 February 2019. The blocks, titled PLR2018-1-1 to PLR2018-1-11 (minus PLR2018-1-2, which was removed from the round – to be opened at a later date) are located across the Chinchilla-Goondiwindi Slope and Taroom Trough.  Two of the blocks (PLR2018-1-1 and PLR2018-1-4) are subject to “Australian Market Supply Conditions” which means any gas commercialised from these areas in the future must be supplied to the domestic market. Blocks are outlined to be prospective for a range of resources, including conventional oil and gas and coalbed methane (CBM). An overview of the blocks is outlined below: Block Name Start Date End Date Basin Names Block Sqkm Remarks Prospectivity PLR2018-1-1 01-Nov-2018 28-Feb-2019 Chinchilla-Goondiwindi Slope, Taroom Trough 152.86 Australian market supply condition Conventional gas and CBM PLR2018-1-3 01-Nov-2018 28-Feb-2019 Taroom Trough 1043.12   Conventional/unconventional gas PLR2018-1-4 01-Nov-2018 28-Feb-2019 Taroom Trough, Chinchilla-Goondiwindi Slope 762.85 Australian market supply condition Conventional gas and CBM PLR2018-1-5 01-Nov-2018 28-Feb-2019 Taroom Trough 1210.76   Conventional/unconventional gas PLR2018-1-6 01-Nov-2018 28-Feb-2019 Taroom Trough 441.45   Conventional oil and gas PLR2018-1-7 01-Nov-2018 28-Feb-2019 Taroom Trough, Chinchilla-Goondiwindi Slope 356.03   Conventional oil and gas PLR2018-1-8 01-Nov-2018 28-Feb-2019 Chinchilla-Goondiwindi Slope 383.52   Conventional oil and gas PLR2018-1-9 01-Nov-2018 28-Feb-2019 Chinchilla-Goondiwindi Slope 467.46   Conventional oil and gas PLR2018-1-10 01-Nov-2018 28-Feb-2019 Taroom Trough, Chinchilla-Goondiwindi Slope 977.55   Conventional oil and gas PLR2018-1-11 01-Nov-2018 28-Feb-2019 Chinchilla-Goondiwindi Slope 832.21   Conventional oil and gas

Australia, not found

Overgas started looking for interested parties to farm-in to licences Provadia and 1-18 Trakiya in May 2016. The Provadia licence is located in the eastern part of the country while the 1-18 Trakiya licence is situated in southern Bulgaria. The farm-in opportunities are likely to be on hold: according to industry sources Overgas has applied for Force Majeure related to the hydraulic fracturing moratorium imposed in 2012, which would suspend the licence commitments. However, as of 22 June 2020 there had been no response from the Bulgarian Government and as such the licences remain open. Between 2011 and 2014 Overgas conducted two 2D seismic surveys and one 3D seismic survey totaling respectively 812 km and 55 sq km in the Provadia licence. No fields are situated within the permit area. The last known drilling activity consists of Krivnya 12 which was drilled to a total depth of 2,769 m in the Lower Triassic and abandoned as a dry hole in 1984. In the 1-18 Trakiya licence, the company drilled the Trakiya 1 exploration well between 2014 and 2015. The hole reached a total depth of 1,717 m bottoming in metamorphic rocks without reaching the targeted Jurassic sediments. It was subsequently re-entered for testing and recovered only gas shows. In late 2012 Overgas conducted a 474 km 2D seismic survey in the permit. Licences Provadia and 1-18 Trakiya are wholly owned by Overgas Inc AD.

Bulgaria (Moesian Platform) Provadia op. by OVERGAS (100%) Overgas Inc AD Provadia and 1-18 Trakiya - Farm-in opportunity on hold

Hungarian Horizon Energy (HHE) is offering farm-in opportunity for the Sarkad I mining plot in southeastern Hungary. The company is intending to drill an appraisal/development well to further assess deep unconventional gas reservoir encountered in the Nyekpuszta 2 (well drilled in 2009). HHE is the sole operator of the Sarkad I block. For further information, interested parties should contact Codey James (Vice President Engineering & Operations) - [email protected]. The 65 sq km Sarkad I block is located approximately 25 km south-east of the city of Bekes, close to the border with Romania. It falls within the Bihar Sub-basin, tectonic unit of the Pannonian Basin. Background Infromation The Sarkad I mining plot was awarded to HHE on 13 September 2012 (application filed in June 2012). On 25 March 2014, HHE adjourned the area of the mining plot, enlarging it to 65 sq km. Until November 2014, JKX Oil & Gas was partnering HHE in the Sarkad I operations. Following an assets swap - JKX exchanged with HHE its 25% stake in the Sarkad I production licence for a 50% interest in the Hernad I and Hernad II exploration permits, as well as the Hajdunanas production licence/production facility - HHE became the full operator of the Sarkad I block. Nyekpuszta 2 was drilled from 31 August 2009 to late October/early November 2009. It is located some 25 km north-east of the city of Bekescsaba and 0.2 km south-west of the Nyekpuszta 1 gas discovery (TD 3,695 m) made by HHE in April 2009. The Nyékpuszta-2 well tested 1 MMcf/d of gas and 150 b/d of condensate from the top 70 m of highly overpressured Badenian (Miocene) sandstones. The farm-out offer for the Sarkad I mining plot was initially put forward in May 2014.

Hungarian Horizon Energy (HHE) is offering farm-in opportunity for the Sarkad I mining plot in southeastern Hungary. The company is intending to drill an appraisal/development well to further assess deep unconventional gas reservoir encountered in the Nyekpuszta 2 (well drilled in 2009). HHE is the sole operator of the Sarkad I block.

4/2001/Ł Soboniów-Kombornia-Rogi block, Carpathian Flysch Zone in SE Poland, susp. at TMD 2,267m (1,560m TVD) in the target Paleocene Istebna beds on 16 Oct ’17. Testing is planned. Exalo F-200 2DH-7 rig.

Dukla-3H nfw Poland, 4/2001/Ł Soboniów-Kombornia-Rogi block, Carpathian Flysch Zone susp Testing is planned.

In March 2017, Surgutneftegaz completed testing of a new exploratory well at the Rogozhnikovskiy 5 license in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Keushkinskaya Vostochnaya 972, spudded in November 2016, reached 3,100 m in January 2017. Oil flows were tested from the Tyumen Formation. Reservoir Yu5-6 perforated at 2,640-2,679 m flowed with oil at a rate of 126 b/d. Based on primary data, 2P reserves of the discovery were estimated by IHS Markit at 5 MMbbl. Rogozhnikovskiy 5 license (KhMN13144NR) covers 342 sq km in the central part of the Ural-Frolov Province and encompasses the im. N.K. Baybakova field and several prospects.  

Oil flows were tested from the Tyumen Formation. Reservoir Yu5-6 perforated at 2,640-2,679 m flowed with oil at a rate of 126 b/d. Based on primary data, 2P reserves of the discovery were estimated by IHS Markit at 5 MMbbl.

Cambay PSC, 161 sq km in the onshore Cambay Basin, Oilex is understood to be open to potential farm-in partners. The company has filed a request to the authorities to transfer GSPC’s 55% participating interest in the block (producing since 1964), following the latter’s default on PSC expenses. Contact: Joe Salomon ([email protected]).

Cambay PSC, 161 sq km in the onshore Cambay Basin, Oilex is understood to be open to potential farm-in partners. The company has filed a request to the authorities to transfer GSPC’s 55% participating interest in the block (producing since 1964), following the latter’s default on PSC expenses.

I3 Energy announced on 8 November 2019 that is had spudded a pilot well, 13/23c-11 (13/23c-A3-L2), targeting the Captain sands at its re-mapped L2 accumulation in licence P2358 on its Liberator field. The well is located to the north east of well 13/23c-9 which was the unsuccessful first pilot well drilled by i3 Energy in their 3 well programme in 2019. Following the re-mapping of the Captain sands on recently re-processed 3D data it was thought that the location of the well provided significant relief above the OWC and a good location for the future development well. On 25 November 2019 the company announced that the well has reached TD in the Valhall shale as planned and on 28 November 2019 the company announced the well was being plugged and abandoned. The well drilled through over 200 ft (67 m) of the Captain Sand reservoir, and there was a confirmed oil presence in 15 ft (4.6 m) TVD of Captain sand. The oil-water contact was found at 5,270 ft (1,606 m) TVD and pressure data indicated that there is hydrostatic pressure communication with Serenity. The oil column encountered was thinner than anticipated, and subsequently the company announced that the Liberator Phase I development would be simplified to consist of a single-well development tied-back to pre-existing infrastructure. Liberator is an oil discovery located immediately west of the Blake field. It was discovered in 2013 and has a Lower Cretaceous Captain Sand reservoir, similar to Blake. The discovery well proved 1.5 to 2.5 Darcy reservoir with a 28% porosity containing 30.3 degrees API oil with a 1.9 cP viscosity and an established water contact that mapped a potential oil column ranging from 7 m to 24 m within an elongated four way structure at approximately 1,600 m. The discovery is located in licence P1987, covering an area of 14.5 sq km and was awarded in the 27th Offshore Licensing Round and consists of just the one block (13/23d). The licence is located immediately west of the Blake field. Interest in licence P2358 is held solely by I3 Energy Ltd.

I3 Energy Ltd P2358 - 13/23c-11 - appraisal / development Pilot hole at L2 (Liberator) - Oil encountered, plugging and abandoning

OGD secured sole rights in June to the Abony V mining plot in the Nagykunság sub-basin in C-E Hungary, 22 sq km NW of Szolnok. Along with other recent awards, it lies in the former Körös contract area (DEA 13 Aug '20).

OGD secured sole rights in June to the Abony V mining plot in the Nagykunság sub-basin in C-E Hungary, 22 sq km NW of Szolnok. Along with other recent awards, it lies in the former Körös contract area

An auction is planned 10 Dec ’19 for 20-year rights to the Veselovskiy block in the Stavropol Kray, North Caucasus. Applications by 20 November. The block covers 18.8 sq km and contains the Veselovskoye gas discovery. Starting price USD 390,000. Contact: Kavkaznedra, email [email protected].

An auction is planned 10 Dec ’19 for 20-year rights to the Veselovskiy block in the Stavropol Kray, North Caucasus. Applications by 20 November. The block covers 18.8 sq km and contains the Veselovskoye gas discovery. Starting price USD 390,000.

The NPD confirmed on 1 February 2019, with effect from 31 January 2019, that Repsol has acquired Total’s 7.65% interest in PL 092 and PL 121 covering the Mikkel field. PL 092 covers part of block 6407/6 while PL 121 covers part of block 6407/5. Mikkel is located in the eastern part of the Norwegian Sea approximately 30 km north of the Draugen field. Work in the area to prove and develop gas resources via Mikkel to Asgard B is ongoing. Mikkel was discovered in February 1987 with the 6407/6-3 discovery well. The field contains remaining recoverable reserves of approximately 425 Bcfg, 12 MMbo and 41 MMb of NGL (source: NPD, December 2017). The PDO was approved in 2001 and the field commenced production in 2003. Gas is piped via the Asgard pipeline system to Karsto, condensate is piped via an existing line to the Asgard C storage ship for export. Gas compression has been utilised at the field since 2015 to accelerate and prolong gas production from the field. Following completion of the deal interest in PL 092 is divided between Equinor Energy AS (37.45% + operator), ExxonMobil Exploration and Production Norway AS (40%), Var Energi AS (14.9%) and Repsol Norge AS (7.65%) and interest in PL 121 is split between Equinor Energy AS (57.45% + operator), ExxonMobil Exploration and Production Norway AS (20%), Var Energi AS (14.9%) and Repsol Norge AS (7.65%).

Norway (Trondelag Platform) Draugen

On 19 December 2017, Pluspetrol announced the acquisition by GeoPark of the 179 sq km Aguada Baguales, the 238 sq km El Porvenir and the 138 sq km Puesto Touquet blocks in the Neuquen Basin. The deal was closed for US$ 52 million and is subject to official approval. As reported by GeoPark, the blocks produce a combined 2,700 boe/d, 70% liquids and 30% gas. GeoPark also estimates proven and probable (2P) oil and gas reserves of approximately 12-14 million barrels of oil equivalent and 3P reserves of approximately 18-20 MMboe and approximately 15-30 MMboe in prospective exploration resources plus additional potential in the Vaca Muerta Shale. GeoPark is returning with more strength to the local market after divesting some assets in the Santa Cruz province, Austral Basin. Pluspetrol is the third leading hydrocarbon producer in Argentina and intends to concentrate activity on its strategic assets like the Centenario Block, the former Petro-Andina Resources licences, the Vaca Muerta assets and its Peru holdings.

Argentina, El Porvenir (CNQ-15 M)

In early-May 2019, state company ANCAP officially launched a new biannual open round process called Uruguay Open Round with six blocks offshore and five blocks onshore. In addition to areas that were previously offered in the last Uruguay Round 3 offshore round in 2018, the new licensing round also offers parcels that cover several recently relinquished offshore blocks in the south, along with onshore blocks in the north which cover areas that previously have been offered in their own open round process since 2014. The exploratory period reportedly will have a term of up to 11 years, with no drilling commitment in the first and second phase (the first six years), then followed by 30 years of exploitation period with possibility of a ten-year extension. The round will be open continuously, with offers opened at the end of the month in May and November of every year. Interested companies will need to qualify one month prior to the deadline for the submission of bids and submit a bid with their proposed work program for the first exploration period, profit oil split with the Uruguayan government, and ANCAP’s association percentage. In offshore, Uruguay Open Round will be offering six new blocks with water depths ranging from 50 m to over 4,000 m in the Pelotas, Rio Salado, and the margin of Argentina Basin. These blocks covered all 17 of the former bid blocks from the last Round 3 bid round, in addition to areas that were recently relinquished by Total (Area 14) and Shell (Area 8, 9, and 13). OFF-1 block includes a couple of plugged & abandoned wells drilled by Chevron in 1976, while OFF-6 block includes the most recently drilled Raya 1 well that was P&A’d by Total in 2016. Uruguay Open Round (offshore) Block Name Main Basin Area (sqkm) OFF-1 Rio Salado Basin 14,581 OFF-2 Pelotas Basin 11,151 OFF-3 Pelotas Basin 13,265 OFF-4 Rio Salado Basin 10,000 OFF-5 Pelotas Basin 16,848 OFF-6 Pelotas Basin 16,519   Meanwhile for onshore, ten available open areas in Chaco-Parana Basin that have been offered in an open round since 2014 were combined and rearranged into five new blocks for this new licensing round. Each of the new onshore area included at least one P&A’d new-field wildcat well from the 1930’s and the 1980’s, except ON-3 block which had no NFW wells and only stratigraphic wells from 2012 and 2013. Uruguay Open Round (onshore) Block Name Main Basin Area (sqkm) ON-1 Chaco-Parana Basin 5,021 ON-2 Chaco-Parana Basin 4,424 ON-3 Chaco-Parana Basin 4,668 ON-4 Chaco-Parana Basin 3,862 ON-5 Chaco-Parana Basin 2,914   More information regarding the Uruguay Open Round can be obtained by contacting ANCAP at [email protected] . Background Information According to reports in June 2018, Uruguayan Minister of Industry, Energy and Mining was considering an open round process to offer the country’s offshore blocks after the Uruguay Round 3 offshore round was declared with no bids received. Meanwhile, the country also has been offering opportunities on its onshore blocks through an open door round process since 2014, although no offers have ever been received since it was launched.

In early-May 2019, state company ANCAP officially launched a new biannual open round process called Uruguay Open Round with six blocks offshore and five blocks onshore.

Pursuant to the acquisition announcement in August, Santos has now completed the takeover of Quadrant Energy with effect 1 Jan ’18. The deal is valued at USD 2.15 bn plus potential contingent payments related to the major Dorado oil find. Acreage involved is mainly in the North Carnarvon Basin off WA, ref. DEA 22 Aug ’18 for block details.

Santos has now completed the takeover of Quadrant Energy with effect 1 Jan ’18. The deal is valued at USD 2.15 bn plus potential contingent payments related to the major Dorado oil find.

Voices in the street indicate that Rohöl-Aufsuchungs AG (RAG) is seeking to divest its domestic exploration and production assets located in central Austria. Industry buzz suggests that the company is intending to retain the producing assets with further work obligations, as well as its gas storage business. It is understood that the process of strategic realignment, started already with the divestiture of the company’s Germany business in late 2017, includes also the assets in Hungary and Romania. In central Austria, near the city of Salzburg, the company is holding the contracts Upper Austria (5,587 sq km), Salzburg (555 sq km), as well as a series of oil, gas and oil/gas producing assets. There were rumours suggesting that Austria’s other exploration and production corporation, OMV, was to acquire parts of the assets of RAG.

Austria, Upper Austria

Perenco and the authorities signed last week PSCs over the Ezila, Onémbé and Evaro blocks in the Ogooué Maritime province, North Gabon sub-basin. The blocks total 5,161 sq km and contracts run 8 years.

Perenco and the authorities signed last week PSCs over the Ezila, Onémbé and Evaro blocks in the Ogooué Maritime province. The blocks total 5,161 sq km.

Teplovskiy Yuzhnyy licence, Khanty-Mansiysk AO, W. Siberia, TD 3,037m in July, 4 tests run in the Tyumen + Achimovo fm's, max. 142 bo/d.

Teplovskaya Yuzhnaya-913 nfw Teplovskiy Yuzhnyy licence, Khanty-Mansiysk AO, W. Siberia, TD 3,037m in July, 4 tests run in the Tyumen + Achimovo fm's, max. 142 bo/d.

SE part of Green Canyon block 432, OCS lease G32504, sidetrack of GC 432 2S0B1 in WD 1,067m, hc in multiple horizons, target subsalt M. Miocene. Original hole PTD 9,754m, Deepwater Asgard DS.  Murphy (op), partners BHP + Anadarko.

United States (Deep GC 432 002S0B1 (Samurai-2) (Murphy 50% op. BHP 50%) in G32504, hc in multiple horizons, target subsalt M. Miocene.

Equinor and Sonangol have agreed to cooperate for exploratory efforts mainly in the lower Congo Basin and identify potential joint investments in the country.

Equinor and Sonangol have agreed to cooperate for exploratory efforts mainly in the lower Congo Basin and identify potential joint investments in the country.

The Ministry of Hydrocarbons, Energy and Mines (Ministère des Hydrocarbures, de l’Energie et des Mines) is the licensing authority. Contracts are signed by the state, as represented by the Minister of Hydrocarbons, Energy and Mines. The Directorate General of Hydrocarbons (Direction Générale des Hydrocarbures) is responsible for the supervision of petroleum operations. Interested parties should contact: Ministère des Hydrocarbures de l’Energie et des Mines Direction Générale des Hydrocarbures Directeur : Moustapha BECHIR Tel : +222 422 101 28 E-mail : [email protected]   It is also possible to contact the Socété Mauritanienne des Hydrocarbures et du Patrimoine Minier (SMHPM). Department of Exploration and Promotion Director : Lemrabott Taleb As of June 2020, it is understood that the blocks listed in the table below were available for licensing. Sixty five blocks were available. There were no changes in the list compared to the previous one. Total open acreage amounts to 770,668 sq km of which 681,508 is onshore and 89,160 is offshore.  Open blocks       Block Name Area (sq km) Situation Block Basin C-1 3,056 offshore Senegal (M.S.G.B.C.) Basin C-2 3,874 offshore Senegal (M.S.G.B.C.) Basin C-3 7,352 offshore Senegal (M.S.G.B.C.) Basin C-5 11,153 offshore Senegal (M.S.G.B.C.) Basin C-9 7,589 offshore Senegal (M.S.G.B.C.) Basin C-16 9,014 offshore Senegal (M.S.G.B.C.) Basin C-20 10,175 offshore Senegal (M.S.G.B.C.) Basin C-21 14,819 offshore Senegal (M.S.G.B.C.) Basin C-23 6,349 offshore Senegal (M.S.G.B.C.) Basin C-30 3,147 offshore Senegal (M.S.G.B.C.) Basin C-32 2,475 offshore Senegal (M.S.G.B.C.) Basin C-33 2,546 offshore Senegal (M.S.G.B.C.) Basin C-34 2,472 offshore Senegal (M.S.G.B.C.) Basin C-35 1,824 offshore Senegal (M.S.G.B.C.) Basin C-36 3,316 offshore Senegal (M.S.G.B.C.) Basin C-4 9,037 onshore Senegal (M.S.G.B.C.) Basin C-24 8,479 onshore Senegal (M.S.G.B.C.) Basin C-25 10,946 onshore Senegal (M.S.G.B.C.) Basin C-26 11,043 onshore Senegal (M.S.G.B.C.) Basin C-27 11,760 onshore Senegal (M.S.G.B.C.) Basin Onshore Block 11 15,133 onshore Senegal (M.S.G.B.C.) Basin Ta-01 10,428 onshore Taoudeni Basin Ta-2 13,476 onshore Taoudeni Basin Ta-3 14,354 onshore Taoudeni Basin Ta-4 11,746 onshore Taoudeni Basin Ta-5 11,510 onshore Taoudeni Basin Ta-6 11,725 onshore Taoudeni Basin Ta-7 14,384 onshore Adrar Sub-basin (Taoudeni Basin) Ta-8 14,033 onshore Adrar Sub-basin (Taoudeni Basin) Ta-9 12,141 onshore Taoudeni Basin Ta-10 14,456 onshore Taoudeni Basin Ta-11 13,579 onshore Hodh Sub-basin (Taoudeni Basin) Ta-12 13,286 onshore Hodh Sub-basin (Taoudeni Basin) Ta-13 14,556 onshore Taoudeni Basin Ta-14 11,502 onshore Taoudeni Basin Ta-15 10,418 onshore Taoudeni Basin Ta-16 12,664 onshore Taoudeni Basin Ta-17 13,213 onshore Taoudeni Basin Ta-18 20,105 onshore Taoudeni Basin Ta-19 20,720 onshore Taoudeni Basin Ta-20 21,608 onshore Taoudeni Basin Ta-21 16,507 onshore Hodh Sub-basin (Taoudeni Basin) Ta-22 21,622 onshore Taoudeni Basin Ta-23 17,612 onshore Hodh Sub-basin (Taoudeni Basin) Ta-24 20,667 onshore Hodh Sub-basin (Taoudeni Basin) Ta-25 21,156 onshore Taoudeni Basin Ta-26 15,664 onshore Taoudeni Basin Ta-27 18,144 onshore Taoudeni Basin Ta-28 13,487 onshore Taoudeni Basin Ta-29 12,503 onshore Taoudeni Basin Ta-30 5,583 onshore Adrar Sub-basin (Taoudeni Basin) Ta-31 15,095 onshore Taoudeni Basin Ta-32 10,250 onshore Taoudeni Basin Ta-33 12,197 onshore Taoudeni Basin Ta-34 9,179 onshore Taoudeni Basin Ta-35 14,066 onshore Eglab-Reguibat Massif Ta-36 14,945 onshore Adrar Sub-basin (Taoudeni Basin) Ta-37 19,272 onshore Adrar Sub-basin (Taoudeni Basin) Ta-38 9,341 onshore Adrar Sub-basin (Taoudeni Basin) Ta-39 8,899 onshore Adrar Sub-basin (Taoudeni Basin) Ta-40 10,530 onshore Taoudeni Basin Ta-41 11,511 onshore Eglab-Reguibat Massif Ta-42 11,594 onshore Taoudeni Basin Ta-43 11,958 onshore Taoudeni Basin Ta-44 13,423 onshore Taoudeni Basin

Mauritania, not found

SuperNova is understood to have secured rights to block 7C, outboard of the company's offshore 7B. Award is pending ratification, after which partners would be sought:

SuperNova is understood to have secured rights to block 7C, outboard of the company's offshore 7B.

ATP 2030-P, 365 sq km in the Roma Shelf, Bowen-Surat Basin, was granted on 2 Oct ‘18 for 6 years. It had been offered as PLR-2016/17-1-2 in 2017.

Armour Egy has been awarded ATP 2030-P (365km²) in the Roma Shelf, it had been offered as PLR-2016/17-1-2 in 2017.

Southern extn of field in L1/L2, N. Perth Basin, TMD 3,744m, tested max. 90 MMcfg/d (avg 89.6 MMcf/d) on 96/64” choke, WHFP 2,395 psi over a 23-minute period from between 3,370-3,420m MD in the Kingia sst, one of the best achieved onshore Australia. Well now shut-in for pressure measurements. As a result, no further testing is required prior to the FID for Waitsia Stage 2 devt. Waitsia-4 also completes the Waitsia sub-surface work programme. AWE (op) 50%, partner Origin.

Australia (Perth B.) Waitsia 4 op. by AWE (50.0%, ORIGIN EN 50.0%) in L 01 block

On 16 April 2018, Perenco completed the purchase of Chevrons interest in the No 177 concession (DRC Offshore). The interest in the concession are as follows: Perenco operates its offshore concession via its offshore subsidiary Muanda Int'l Oil Co Ltd (MIOC) with a 67.72% interest. Partner Teikoku Oil (DRC) Co Ltd, a subsidiary of Inpex, holds 32.280%. The DRC Offshore concession covers some 737 sq km within the Lower Congo basin. The entire concession is located offshore, water depths range from 0 m to roughly 50 m. The Concession plays host to eleven fields (GCO, GCO South, Libwa, Lubi, Lukami, Mibale, Misato, Moko, Motoba, Mwambe and Tshiala). As of end December 2017, combined production from that aforementioned fields was averaging 11,198 bo/d. Background information As announced on 6 December 2017, after a lengthy delay Perenco and partners in the No 177 concession (DRC Offshore) have agreed with Government on a 20 year extension. The validity of the Concession has thus been extended until 21 November 2043.

Perenco took over Chevron’s 17,7% interest in the shallow-water No 177 concession (aka DRC Offshore). Perenco operates the 737-sq km block under its Muanda Int'l Oil Co sub now with 67,72%, partner Teikoku.

Dragon has picked up Enel’s 30% interest in the Tinrhert Nord / 223B, 235B, 244D block, Berkine Basin of SE Algeria, and becomes sole holder of the 2,907-sq km block in the process.

Dragon has picked up Enel’s 30% interest in the Tinrhert Nord / 223B, 235B, 244D block, Berkine Basin of SE Algeria, and becomes sole holder of the 2,907-sq km block in the process.

Zhu 1 Depression, PRMB, South China Sea, WD 110m, ops terminated 15 May ’19, no results, HYSY 943 JU. Target Miocene clastics.

Panyu 19-1-1d (PY 19-1-1d) nfw Zhu 1 Depression, PRMB, South China Sea, WD 110m, ops terminated 15 May ’19, no results, Target Miocene clastics.

P2358, Moray Firth, WD 40m, pilot hole TD 1,773m (Valhall fm), MWD suggests target U. Captain sand not intersected (pinch-out likely), although L. Captain present. Borgland Dolphin SS.

United Kingdom (Inner Moray Firth B. (Moray Firth Province)) Captain

On 1 November 2017, Shell Offshore was awarded two Alaminos Canyon blocks: AC 685 (G36106) and AC 729 (G36107), situated in the Burgos-Rio Grande and East Texas Coastal basins. Both blocks were originally offered as part of Western Gulf of Mexico Lease Sale 249, held on 16 August 2017, and are expected to expire on 31 October 2027. Following official award, Shell Offshore is now the operator and sole interest-holder (100% WI + Op) in AC 685 & AC 729.

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Neptune Energy Norge, operator of production licence PL 889, is in the process of concluding the drilling of wildcat well 6507/8-10 S. The well was drilled about 10 kms east of the Heidrun field in the Norwegian Sea and 215 kms west of Brønnøysund. The objective of the well was to prove petroleum in Lower Jurassic reservoir rocks (the Tilje and Åre Formations). The well encountered the Tilje Formation with a thickness of about 150 metres, with sandstones totalling about 100 metres with good to very good reservoir quality. The Åre Formation was encountered with a thickness of about 195 metres, with sandstone layers totalling around 100 metres with good to very good reservoir quality. No traces of petroleum were proven. The well is dry. Data acquisition has been performed. This is the first exploration well in production licence PL 889, which was awarded in APA 2016. Well 6507/8-10 S was drilled to a measured depth of 2399 metres and a vertical depth of 2311 metres under the sea surface, and was terminated in the Åre Formation in the Lower Jurassic. Water depth at the site is 324 metres. The well will now be permanently plugged and abandoned. Well 6507/8-10 S was drilled by the West Phoenix drilling facility, which will now drill production wells on the Fenja field in production licence 586 in the Norwegian Sea. Original article link Source: NPD

6507/08-10 S (Grind) nfw. (Neptune op, Equinor + Wellesley), 1st well in PL 889 E. of Heidrun, P&A dry at TMD=2399m (Åre fm). Targets Tilje + Åre fm's. WD=324m.

Tecpetrol tested heavy oil in its new-pool wildcat, Pendare Norte-1H, in early-mid February 2018 on its CPO-13 Block, located in the Llanos Basin. According to local sources, the well produced around 503 bo/d of 13.8deg API oil during initial testing of the basal sands of the Carbonera Formation. In total around 646 bf/d was tested with a sediment and water cut of 22%. The well reached its planned total depth of 1,481m in late January 2018 after being spudded in mid-January 2018. A horizontal section was drilled in the well around 600m to the south. The well is located around 3-4km north of the Pendare Field which produces oil from the Carbonera C7 Formation. It was discovered in mid-2012 with the Pendare-1 NFW, confirming that the Quifa-Rubiales/Cano Sur trend extends into CPO-13. Tecpetrol has conducted a successful horizontal appraisal/development well programme in 2017. In mid-2017, around 50% of the block was relinquished upon entry to an eighteen month first extension period (with one NFW as a commitment), leaving a north east portion where Pendare Norte-1H was drilled from and a southern portion. The commitment has been met by the drilling of the La Pluma-2H NFW that tested around 960 bo/d of 13.4deg API oil from basal sands presumably of the Carbonera Formation on the southern portion of the block. The well was spudded on 26 December 2017 a few kilometres south of the Pendare Field and reached its PTD of 1,350m on 4 January 2018. A horizontal section of unknown length was drilled in the well which was deviated around 600m to the south. Tecpetrol is planning to drill another NFW, the Tapara-1H, in the first half of 2018 on the block. Tecpetrol holds 100% WI in the block.

Pendare Norte 1H, app. by Tecpetrol (op. 80%, PetroNova 20%) in the CPO 13 block, produced around 503 bo/d of 13.8deg API oil during initial testing of the basal sands of the Carbonera Formation. In total around 646 bf/d was tested with a sediment and water cut of 22%.

Companies interested in the hydrocarbon sector of Côte d’Ivoire should contact the Société Nationale d’Opérations Pétrolières de la Côte d’Ivoire (Petroci). Mr. Ibrahima Diaby Director-General Immeuble les Hévéas 14, boulevard Carde BP V 194 Abidjan Côte d’Ivoire Tel: +225 20 202 500 Fax: +225 20 216 824 Email: [email protected]

Companies interested in the hydrocarbon sector of Côte d’Ivoire should contact the Société Nationale d’Opérations Pétrolières de la Côte d’Ivoire (Petroci). Mr. Ibrahima Diaby Director-General Immeuble les Hévéas 14, boulevard Carde BP V 194 Abidjan Côte d’Ivoire Tel: +225 20 202 500 Fax: +225 20 216 824 Email: [email protected]

Bass Oil announced on 13 November 2018 the signing of a Heads of Agreement with Azipac for the acquisition of 100% interest and operatorship in the North Madura PSC, located in shallow water East Java Basin. The deal is contingent to the signing of a detailed sale and purchase agreement and reception of the necessary regulatory approvals. The PSC has a remaining commitment of one exploration well plus two contingent wells in case of success. The Reog prospect has been identified as the top drilling candidate. According to Azipac, the prospect, located in the western part of the PSC, could contain up to 1.3 Tcfg within three stacked carbonate buildups of the Kujung Formation. The prospect is located 3 km east of the Ujung Pangkah field (Pangkah PSC) which has produced 9,000 bo/d and 44 MMcfg/d in 2017. Drilling of the Reog prospect is expected in 2019. Upon completion of the deal, Bass will likely seek a farm-in partner in the PSC to offset exploration risk and share drilling cost. Earlier in 2018, Azipac estimated a cost of approximately USD 8 million for the well. The seismic commitment in the block was fulfilled with a 400 sq km 3D seismic survey acquired in the block in late 2017, using the “PGS Apollo” S/V as part of a multi-client survey project that also covered Petronas Carigali’s North Madura II and Ketapang PSCs. The purpose of this survey was to assess the potential of the deeper reservoir. According to AziPac, the under-explored Ngimbang clastics could provide further upside in the area. The exploration period for the North Madura PSC is due to expire in May 2020 following a four-year extension effective on 18 May 2016. Background Information The North Madura block was offered on 30 November 2009 as part of the Second Petroleum Bidding Round 2009 under the direct offer mechanism. The block was awarded to AWE (50%, operator) and Black Platinum Energy (50%) on 18 May 2010. Mitra Energy then farmed-in and acquired 25% interest from Black Platinum on 9 June 2011. Firm commitments for the first three years of exploration include G&G studies (USD 0.4 million), and drilling of one exploration well (USD 8 million). Signature bonus for the block was USD 1 million. The block covers an area of approximately 1,850 sq km following partial relinquishment in 2016 and comprises two separate areas in shelf water. It is adjacent to Pertamina’s West Madura Offshore PSC, which includes Poleng and KE 6 oil fields and KE 5 gas field and to Petronas Carigali’s Ketapang PSC, which includes the Bukit Tua oil and gas field. Several sub-blocks were previously covered by the Pangkah PSC, currently operated by Saka Energi. AziPac initially entered the block in October 2015, acquiring a combined 50% interest from Mitra Energy (25%) and North Madura Energy Limited (25%), a wholly-owned subsidiary of Black Platinum Energy. In 2016, operator AWE divested its 50% interest to Azipac which became sole interest holder in the block. The company then commenced to seek a farm-in partner for the block. The previous exploration activity in the block was a 350 km 2D seismic survey in September 2014. No wells have been drilled to date under the North Madura PSC. AWE was planning to drill wildcat Dyah 1 in late 2015, however the plan did not go through. Dyah is likely a carbonate prospect likely located northeast of the Ujung Pangkah field, near the Reog prospect.

Bass Oil has a HoA to acquire a 100% interest from Azipac in the North Madura PSC in coastal shallow waters off Java.

Corallian is once more offering equity in the 121-sq km P2396 / block 29/7b containing the 45 MMboe 1977 Curlew oil discovery. Talon farmed-in with 10% in 2018 in exchange for part-funding the planned Curlew-A appraisal, WD 93m, PTD 2,700m, GBP 9.7 MM, planned 2021 if new farmout successful. Currently Corallian (op), partner Talon.

United Kingdom (Central Graben Province), P2396 operated by CORALLIAN (90%), TALON (10%), Corallian is once more offering equity in the 121-sq km P2396 / block 29/7b containing the 45 MMboe 1977 Curlew oil discovery.

Eni has acquired Shell’s 32.5% interest in the Evans Shoal gasfield, and become operator of the surrounding, 1,754-sq km NT/RL7 retention lease in the N. Bonaparte Basin. Approvals are all in place and partnership has therefore become Eni (op) 65%, Petronas 25% and Osaka Gas 10%.

Australia (Bonaparte B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: NT/RL7 op. by SHELL (32.5%, ENI SPA 32.5%, PETRONAS 25.0%, OSAKA GAS 10.0%) to be check.

OOC is reportedly looking into a possible sale of a quarter of its 40% in the Khazzan tight gas project in the S. of BP-operated block 61. The sale, if implemented, could fetch USD 1 bn or more, with interest reportedly being shown by Chinese, Indian and Middle Eastern companies. EoI’s are invited by July.

Oman OOC is reportedly looking into a possible sale of a quarter of its 40% in the Khazzan tight gas project in the S. of BP-operated block 61. The sale, if implemented, could fetch USD 1 bn or more, with interest reportedly being shown by Chinese, Indian and Middle Eastern companies. EoI’s are invited by July.

According to industry sources, Total made a non-commercial oil discovery in the Jamm 1XB new field wildcat well in the Rufisque Offshore Profond (ROP) block, deep waters of the MSGBC Basin. The rig moved off location around 6 August 2019. No further details are known yet. Available information indicates that around 25 June 2019, Total had to interrupt drilling operations at its Jamm 1XB well. The interruption was reportedly due to a problem with the BOP. Once the problem was solved, drilling resumed and the well reached TD. Industry sources suggested that Total has spudded Jamm 1XB on 16 April 2019. As of early June, drilling operations were ongoing. The location is in the central part of the northern portion of the block in around 2,000 m of water. Likely targets are Upper Cretaceous turbidite channels/fans on the lower slope. The hydrocarbon type to be expected could be rather oil than gas as the location falls into a compartment of the basin where Cairn made its oil discoveries. This compartment may have a lower geothermal gradient than the adjacent one to the north where Kosmos made several gas discoveries. As of 4 April 2019, the “Pacific Santa Ana” drillship was sailing in Mauritanian waters en route for Senegal where it is expected to spud an exploration well for Total. In early March 2019, industry sources suggested that Total plans a well in the ROP block. Operations could start as early as April 2019. Following the interpretation of the 3D seismic survey completed in June 2018 by Total, suitable prospects were identified and one of them will now be drilled. The ROP block covers 10,357 sq km and is undrilled. The block is located between Kosmos Teranga and Yakaar gas discoveries in the north and Cairn’s FAN-1 oil discovery in the south, in water depths ranging from 100m to 3,000m. It lies on the Upper Cretaceous slope and basin floor fan play fairways and holds a considerable exploration potential. In August 2018, Petronas acquired a 30% stake in the ROP block from Total who remains operator with a 60% interest. Petrosen, the state company has the remaining 10%.

Jamm-1XB nfw (Total 60% op, Petronas 30%, Petrosen 10%) in Rufisque Offshore Profond (ROP) block, MSGBC deepwaters, reportedly P&A non-comm. oil, targets assumed U. Cretaceous turbidites.

On 30 April 2020 Carnarvon Petroleum Ltd increased its interest holding in exploration permit WA-155-P, located in the North Carnarvon Basin, to 70% and took operatorship of the permit. Joint venture partner Skye Exploration Pty Ltd decreased its holding, from 71.5% to 30%. Carnarvon reported that it is aiming to mature the prospect to enable future farm-out of interest. A number of prospects, primarily within the Triassic Mungaroo, have been identified within the permit. The primary prospect, the Belgravia Prospect, has been outlined. Carnarvon reported, in May 2020, that the prospect could be part of a much larger structure, that it has identified as the Jurabi-Belgravia-Swell (JBS) structure, part of which lies in WA-155-P. Both the Swell and Jurabi wells, drilled in 2017 and 1982 respectively, exhibited low porosity, though Carnarvon reports the larger JBS structure could have a better average porosity. The top Triassic at Belgravia is thought to be around 4,500 m. If a significant commercial gas discovery was made there would be the option for a standalone development, or tie-back to the existing northwest shelf LNG projects. The permit already contains the Outtrim oil discovery, which was made in 1984. WA-155-P, which covers an area of 289 sq km was awarded on 1 March 1981. With the interest change complete, participants in the permit are Carnarvon Petroleum Ltd (70% + Operator) and Skye Exploration Pty Ltd (30%).

Carnarvon (Skye Explo->30%). has taken over operatorship of WA-155-P while increasing its interest to 70% ('Outtrim project').

The BLM is calling for nominations on blocks within the NPR-A until 22 Jul ’19. The intention is to head into a possible 2H ’19 o&g lease sale, too early for more.

The BLM is calling for nominations on blocks within the NPR-A until 22 Jul ’19. The intention is to head into a possible 2H ’19 o&g lease sale, too early for more.

Further to DEA 4 Apr ’18, PL 644/644B, WD 342m on Halten Terrace, evaluation of the 6506/11-10 (Iris & Hades) well results has led to an increase in gross contingent resources to 63 MMboe (1C) – 210 MMboe (2C) – 322 MMboe (3C). An appr well is due to spud in 1H ’19. OMV (op), partners Statoil, Centrica + Faroe.

PL 644/644B, WD 342m on Halten Terrace, evaluation of the 6506/11-10 (Iris & Hades) well results has led to an increase in gross contingent resources to 63 MMboe (1C) – 210 MMboe (2C) – 322 MMboe (3C). An appr well is due to spud in 1H ’19. OMV (op), partners Statoil, Centrica + Faroe.

Novatek won the auction on 17 Dec '19 for the Yamburgskiy Yuzhnyy, 1,590 sq km in the Nadym-Taz Province, Yamal Nenets AO, contains parts of the Urengoyskoye + Olikuminskoye o/g/c fields.  Starting price was USD 15.1 MM, won for USD 17.04 MM.

Novatek won the auction on 17 Dec '19 for the Yamburgskiy Yuzhnyy, 1,590 sq km in the Nadym-Taz Province, Yamal Nenets AO,

Sapura has made its entry into the Australian upstream by signing a farm-in deal with Finder Exploration for AC/P61, EP 483, TP/25 + WA-412-P. Sapura gets 70% + operatorship in Bonaparte AC/P61 (355 sq km), and likewise in North Carnarvon Basin EP 483 + TP/25 (total 1,076 sq km) and WA-412-P (387 sq km), Finder retains 30%. The deal remains subject to usual approvals.

Sapura Upstream has acquired 70% of portfolio of exploration permits comprising EP 483 & TP/25, WA-412-P and AC/P 61 from Finder Exploration (will retain a 30% non-operating interest).

Pursuant to a LoI in Dec ’18, Azinor has signed with Seapulse for the latter’s acquisition of non-operated interests in P2165 (Boaz prospect) and P2179 (Hinson prospect), where preparations for drilling the wells in 2020 are underway. A similar deal for P2317 (Goose prospect) is still being discussed.

Azinor has signed with Seapulse for the latter’s acquisition of non-operated interests in P2165 (Boaz prospect) and P2179 (Hinson prospect), where preparations for drilling the wells in 2020 are underway. A similar deal for P2317 (Goose prospect) is still being discussed.

Ref. DEA 13 Aug ’18 (awards):  Delonex is now understood to have not pursued block P5-A, 9,998 sq km onshore Palmeira in S. Moz., owing to legislation changes and the lengthy award process. Delonex would have operated, partners Indian Oil + ENH.

Delonex is now understood to have not pursued block P5-A, 9,998 sq km onshore Palmeira in S. Moz., owing to legislation changes and the lengthy award process. Delonex would have operated, partners Indian Oil + ENH.

Pemex's Nak 1001 deeper-pool wildcat, located in the Pilar Reforma-Akal Basin (Bay of Campeche), has been junked after the reservoir was invaded by salt water, sources indicated in August 2015. While the first interval (5,681-5,731m) was invaded by saltwater, testing is being carried out on the second interval (6,662-6,672m). In September 2014, during drilling operations, 'poor' oil shows were encountered in late Jurassic microcrystalline dolomites and anhydrites at interval 5,712-5,721m. Spudded on 2 October 2013, the Diamond Offshore Ocean Summit jack-up rig reached a TD of 6,706m (6,543m TVD) on 13 February 2015. The well is stationed in 23m water depth, approximately 2km east of the Nak 1 oil discovery.

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UOG has reached an option agreement to farm into P2264 / block 49/29c which contains the Acle prospect in the SNS. UOG can obtain 12% from each of current partners Swift Exploration (op) + Stelinmatvic in exchange for which it will pay 30% per cent of the costs of the 1st explo well. UOG will also pay GBP 20,000 cash to each partner on signing of the farm-in agreement. The option is exercisable upon a firm commitment being made to drill the well, and is valid until expiry of the 29-sq km licence, no earlier than 30 Jun ‘18.

UOG has reached an option agreement to farm into P2264 / block 49/29c which contains the Acle prospect in the SNS, obtains 12% from each of current partners Swift Exploration (op) + Stelinmatvic.

The NE sector of Statoil’s PL 248 C, part-block 35/11, has been split into 2 units PL 248 I (48 sq km, part of Grosbeak discovery) and PL 248 J (37 sq km N. of Byrding). Partner Wellesley also took over operatorship of PL 248 I by acquiring Statoil’s 30% effective 29 Dec ’17, partners Petoro + Capricorn.  Capricorn did the same in PL 248 J effective 5 Jan ’18, partners Petoro + Wellesley.

PL 248 C, part-block 35/11, has been split into 2 units PL 248 I (48 sq km, part of Grosbeak discovery) and PL 248 J (37 sq km N. of Byrding). Partner Wellesley also took over operatorship of PL 248 I by acquiring Statoil’s 30% effective 29 Dec ’17, partners Petoro + Capricorn. Capricorn did the same in PL 248 J effective 5 Jan ’18, partners Petoro + Wellesley.

Rovenskiy block (licence SRT00472NP), Saratov Oblast (Volga-Urals), tested ab. 375 bo/d from Bobrikovskiy sst (L. Carbon.).

Lisyanskaya-1 Rovenskiy block (licence SRT00472NP), Saratov Oblast (Volga-Urals), tested ab. 375 bo/d from Bobrikovskiy sst (L. Carbon.).

As of late October 2019, Sudan Petroleum Corp (Sudapet) was still looking to farm out some equity in Block 25 where it has the 100% of interest. In late 2018, a long-term production test at the Rawat Central field started with a flow rate of approximately 600 b/d of waxy oil. The produced oil was being transported by truck to the El Obeid refinery where is sold as a fuel oil for nearby factories. See here for more information.

As of late October 2019, Sudan Petroleum Corp (Sudapet) was still looking to farm out some equity in Block 25 where it has the 100% of interest. In late 2018, a long-term production test at the Rawat Central field started with a flow rate of approximately 600 b/d of waxy oil.

CPO 11, 2,588 sq km in the Llanos Basin, Parex Resources has agreed with Hupecol Meta to farm-in for a 50% operated interest, which will involve paying 100% of 2 expl wells and 108km of 2D seismic, for a total investment of USD 13 million. Anacaona-1 expl well to spud by end-year.

Parex Resources has agreed with Hupecol Meta to farm-in for a 50% operated interest in CPO 11 block, (2588km²).

In mid-November 2019 it was reported that the Gambian authorities plan to demarcate two ultra-deep water acreage blocks which will be located west of existing blocks A1 and A4. TGS was contracted to acquire a seismic survey covering 7,500 sq km in the area of interest in early 2020. The Ministry of Petroleum and Energy plans to create two ultra-deep water blocks which would be roughly twice the size of the existing offshore blocks. Block A1 is operated by BP and Block A4 is open albeit under arbitration by Petronor (formerly African Petroleum). Gambia follows Senegal who is actively promoting its ultra-deep water acreage. Petrosen currently acquires 3D seismic ahead of a bid round for ultra-deep acreage which starts in January 2020.

Gambia, Block A1

Bukhari ML (Badin I), L. Indus onshore, Sindh, suspended at TD 2,819m, tested Aug-Oct '19, ZPEC rig 33. Target L. Goru.

Malhan 1 nfw (UEPL 100%) in Bukhari ML (Badin I), onshore block, Sindh, suspended at TD=2,819m, tested. Target L. Goru. Results unreported yet.

Equinor confirmed on 8 June 2018 that it has agreed a deal to transfer 20% of its interest in PL 167 to Spirit Energy. The deal follows the announcement of the successful Lille Prinsen exploration well (16/1-29 S) in the same licence. The licence also contains the 2003 Verdandi oil and gas discovery directly above Lille Prinsen. Lille Prinsen was discovered by exploration well 16/1-29 S which had Triassic / Lower Jurassic objectives. The well encountered a 95 m oil column in the main segment (17 m was in clastic rocks of moderate to good reservoir quality) with a OWC at 1,947 m TVDSS. A separate 30 m oil and gas column was proven in the Eocene Grid Formation. Thin sandstone layers (totalling 10 m) of very good reservoir quality comprise the main reservoir with a GWC at 1,436 m TVDSS and a OWC at 1,472 m TVDSS. Volumes in this segment were not evaluated however estimated recoverable reserves for the main segment, which is considered to be commercial, range from 16-35 MMbo. The well was abandoned on 3 June 2018. Verdandi was drilled by Statoil with exploration well 16/1-6 S. Oil and gas were proven in the Eocene Grid Formation, gas was present in the Paleocene Heimdal Formation and the well reached TD at 1,997 m in the Ekofisk Formation. A sidetrack was drilled to further delineate the Heimdal Formation downdip but the reservoir was significantly deeper and thinner than expected and the well was abandoned as a dry hole. The discovery was appraised by the Lille Prinsen discovery well (16/1-29 S). It encountered a 15 m gas column in the Paleocene Heimdal Formation but no GWC was penetrated. The results were as prognosed and the estimated recoverable reserves for Verdandi remain unchanged. Following completion of the deal interest in PL 167 will be divided between Equinor Energy AS (60% + operator), Lundin Norway AS (20%) and Spirit Energy Norge AS (20%).

Equinor confirmed that it has agreed a deal to transfer 20% of its interest in PL 167 to Spirit Energy. The deal follows the announcement of the successful Lille Prinsen exploration well (016/01-29 S) in the same licence.

Murphy Exploration & Production was formally awarded Green Canyon Block GC 852 (G36447) as of 1 November 2018. The block is expected to expire on 31 October 2028. The block, situated in the East Texas Coastal Basin, was originally offered as part of OCS Lease Sale 251, which was held on 15 August 2018. The sale garnered 171 bids for 144 tracts in both shallow and deepwater from a total of 29 companies. According to officials, a total of US$ 178,069,406 was received in high bids. Following official award, equity in WR 544 is shared between Murphy Exploration & Production (40% WI + Op), Red Willow Offshore (25%), Deep Gulf Energy III (18%) and Houston Energy (17%).

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PVEP, a subsidiary of the national oil and gas group PVN, has signed an agreement to transfer 5% of its drilling and executive rights, in Block 15-1/05 off the coast of Vietnam, to Murphy Oil Corp.According to PVEP, Block 15-1/05 is located in the Cuu Long Basin under the operation of PVEP-POC, a subsidiary of PVEP.The production sharing contract for Block 15-1/05 was signed on 11 April 2007 between PVN and a consortium of two contractors, namely PVEP (75%) and SK Corporation (25%).In August 2015, PVEP and Murphy Cuu Long Bac Oil Co. Ltd signed a rights transfer agreement, allowing Murphy to participate in Block 15-1/05.With the approval of PVN, PVEP and Murphy have agreed on the content of the agreement to transfer 5% of PVEP’s drilling and executive rights in the block to Murphy.On 15 March, PVEP deputy director Pham Nhu Khanh said that as oil prices have yet to recover, the development of small marginal fields is facing difficulties and requires an experienced partner such as Murphy to ensure that the project can proceed.Original article linkSource: nhandanonline

Vietnam, Block 15-1/05

Industry sources indicated in mid-November 2018 that a farm-out agreement for the Velca exploration permit between Pennine Petroleum and a yet to be disclosed company remains to be formalized. It is understood that Pennine Petroleum is facing contractual challenges with the authorities. The company opened a virtual data room in August 2018 to attract partners ahead of the drilling of an exploratory well on the Ramica prospect. Pennine Petroleum was awarded the 310-sq Velca block, located 10 km southeast of the coastal city of Vlora, on 5 December 2017 for six years. The Ramica prospect is one of the two main highs of a closed structure at the top of the Eocene to Cretaceous pelagic carbonates of the Ionian Zone. 2P prospective resource for the 7.75-sq km structure were estimated at 26.4 MMbbl of oil in May 2017 by Apex Energy Consultants. Reservoirs are expected at depths between 2,200 m and 3,400 m, with a gross pay estimated between 450 m and 750 m. Working interest in the Velca permit is shared between Pennine Petroleum Corp (90% - operator) and Alpetrol Sh.A (10%).

Albania, Velca

1st of a couple of appraisals planned to the Shpiragu oil find in block 2, onshore Ionian Zone 3km S. of Shpiragu 2, P+A at TD ca. 4,700m late Dec ’17, Hilong ZJ90DB rig. This was Hilong’s 1st well in Europe.  Borehole probs plagued drilling since spudding in mid-2016, which led to 7 sidetracks and the target Cretaceous reservoir was not reached.

Shpiragu 3 op. by Shell (100%), 1st of a couple of appraisals planned to the Shpiragu oil find in block 2, P+A, well drilled with multiple technical problems since mid-2016, which led to 7 sidetracks and the target Cretaceous reservoir was not reached. Operator just has spuded Shpiragu 4, close to Shpiragu 2.

Repsol has bought out Medco + Equinor's interests in the West Papua IV offshore block, becoming sole holder in the process at the turn of the year. The block lies over 1,227 sq km in mainy deepwaters of the Aru and Akimeugah basins:

Repsol (->100%) has bought out Medco + Equinor's interests in the West Papua IV PSC offshore block. The block lies over 1,227 sq km in mainy DW of the Aru and Akimeugah basins.

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

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

EGPC has signed a USD 1 bn E&P agreement with Shell and partner Petronas relating to drilling in the Burullus-operated West Delta Deep Marine block (4,900 sq km). Eight explo wells are planned. Burullus = Shell-Petronas-EGPC. A similar, USD 10 MM deal was signed with Rockhopper, Kuwait Energy and Dover Corp for the Abu Sennan block (715 sq km, Abu Gharadiq Basin, W. Desert) leading to the drilling of 4 wells.

EGPC has signed a USD 1 bn E&P agreement with Shell and partner Petronas relating to drilling in the Burullus-operated West Delta Deep Marine block (4,900 sq km). Eight explo wells are planned. Burullus = Shell-Petronas-EGPC. A similar, USD 10 MM deal was signed with Rockhopper, Kuwait Energy and Dover Corp for the Abu Sennan block (715 sq km, Abu Gharadiq Basin, W. Desert) leading to the drilling of 4 wells.

On 11 December 2017 it was announced that the merger between Centrica and Stadtwerke Munchen GmbH to combine Centrica’s European oil and gas exploration and production business with Bayerngas Norge AS, has completed. The newly formed incorporated European E&P company is named Spirit Energy. The deal which was announced on 17 July 2017 see’s Centrica take a 69% interest with Bayerngas Norge’s existing shareholders owning 31% of the joint venture. Spirit Energy’s plans for 2018 include progressing development projects such as Maria and Oda, appraisal drilling at the Fogelberg discovery and the drilling of a number of exploration wells. Also, in conjunction with Wintershall, the company will submit a plan for the development of the Skarfjell field. The newly formed organisation aims to create a strong and sustainable E&P business through combining Centrica’s cash generative and near-term production profile and Bayerngas Norge’s more recent production assets (to have come onstream) and the latter’s development portfolio. The strategy behind the merger was down to a number of aligning points such as the mix of producing and developing assets with both strong positions in the UK and Norway and also assets in the Netherlands, Denmark and Germany held between them. The merger creates a robust, self-financing entity with an attractive financial profile. It could generate approximately GBP 100 – 150 million of net present value expected through synergies and cost savings and portfolio optimisation. Lastly, it provides the opportunity to strengthen the entity through further consolidation and joint ventures including the potential for an initial public offering (IPO) in the medium term. Centrica was formed as one arm of British Gas following its privatisation in 1997 (the other being BG). The company holds interest in 81 assets in the UK, mainly focused on gas in the Southern Gas Basin, interest in 18 assets in Norway and a further five in the Netherlands. Bayerngas holds interest in eight UK fields, 13 Norwegian fields and two Danish assets.

United Kingdom (Central Graben Province) ? op. by CHRYSAOR H (36.0%, CENTRICA 64.0%) in Maria block

1st devt well in Absheron gas/cond field, WD 470m, TD 6,803m, spudded 19 May ‘18, to be completed in Nov ’19, Heydar Aliyev SS. 1st production has reportedly been delayed from next year until mid-‘21. Total (op), partner Socar.

ABD-001 devt 1st devt well in Absheron gas/cond field, WD 470m, TD 6,803m, spudded 19 May ‘18, to be completed in Nov ’19, 1st production has reportedly been delayed from next year until mid-‘21. Total (op), partner Socar.

Equinor completed the farm out of 4% in Barents Sea licences PL615 and PL615 B to Aker BP on 30 November 2018. PL645 partners drilled Intrepid Eagle NFW 7324/3-1 from 15 October to 12 November 2018, and made a 385-840 Bcfg discovery in moderate-poor sands. The well was drilled vertically to 1,709m MD (1,678m TVD) and encountered 30m gross (20m net) gas pay in moderate to poor Triassic Upper Snadd Formation (Fm) sands, estimated to hold 350-700 Bcfg recoverable resources. A pay zone of unspecified thickness in poor to moderate Lower Snadd sands was also estimated to contain 35-140 Bcfg recoverable resources in tight reservoir. The secondary exploration target, Lower to Middle Jurassic Sto Fm was aquiferous. OMV farmed in for 25% from Equinor on 29 June 2018. On 30 September 2016, Statoil (now Equinor) increased its share to 80%, after it acquired the equity held by partners ConocoPhillips (25%) and OMV (20%). PL615 covers 410 sq km in blocks 7324/1, 2 & 3, and 7325/1, located 40km NNE of Wisting area, and 165km ESE of Bjornoya (Bear Island). PL615 B lies adjacent to the NE and spans 568 sq km over 7425/10 & 11. PL615 was awarded in the 21st Round, effective 13 May 2011 with a two well commitment that has been satisfied by the small Atlantis gas discovery 7325/1-1 (2014, Statoil, 2,865m) and the dry Apollo NFW 7324/2-1 (2014, Statoil, 1,090m). PL615 B was issued on 21 June 2013 as part of the 22nd Round and has an outstanding firm well commitment. PL615 and PL615 B partners are now Equinor Energy AS (51% + Op), OMV Norge AS (25%), Aker BP ASA (4%) and Petoro AS (20%).

Equinor completed the farm out of 4% in Barents Sea licences PL615 and PL615 B to Aker BP on 30 November 2018. PL645 partners drilled Intrepid Eagle NFW 7324/3-1 from 15 October to 12 November 2018, and made a 385-840 Bcfg discovery in moderate-poor sands.

South Pacific Resources (SPB), a wholly owned subsidiary of Indo Pacific Energy Pty Ltd, is seeking a farm-in partner in its four Papua New Guinea exploration licences, which are located in the Papuan Basin. The farm-out process was initiated during 2015 for SPB to investigate joint venture exploration opportunities. The licences on offer are: PPL 356, 357, 366 and 367 within the Papuan Basin. The licences, which cover a combined area of approximately 5,600 sq km, were due to expire in November 2016. It is understood that SPB in continuing with negotiations with the Department of Petroleum and Energy to extend the terms or renew the licences. Under conventional terms, operators may extend the licence terms by a period of five years with an associated 50% area reduction, at the digression of the Petroleum Minister. PPL 356 and PPL 357 are located in the offshore Papuan Basin. PPL 356 is located in water depths generally less than 200 m, whereas PPL 357 extends beyond the present day shelf break into excess of 1,000 m water depth. No wells have been drilled to date in either licence. SPB reports that the area is thought prospective for gas within Tertiary petroleum systems. PPL 356 lies between the liquids rich Pasca and Uramu fields and the dry gas of the Pandora field. Target plays within the permit are likely to be on trend with the buried Miocene carbonate reefs which lay under a regional Pliocene clastic seal. PPL 357 lies to the southeast of the Flinders and Hagana dry gas fields. SPB regional studies suggest that the Pliocene, shallow marine reservoir sands could extend to the PPL 357 block. PPL 366 and PPL 367 lie in the onshore Papuan Basin. Located close the Barikewa gas field and adjacent to the Highlands’ prolific Toro Sandstone reservoirs, the permits are considered to carry low play risk by SPB for Cretaceous reservoir plays. Trap geometry is expected to be the main geological risk for the identified leads, including the Gamma River lead and Turama lead. SPB has conducted multiple studies across its licenced areas, including mapping and evaluation of the offshore Papuan Basin, quantifying the presence and effectiveness of viable source rocks in the Gulf, mapping leads from existing seismic data and has formed a commercial and technical alliance agreement with Tamarind Management Sdn Bhd for consultancy work to assess and develop the full potential of the licences. SPB entered the agreement with Tamarind on around 27 September 2016. Tamarind was to be assigned 20 million share options in South Pacific Resources as part of the agreement at various commercial and technical milestones of the assets (including unconventional exploration applications by SPB). Tamarind has been providing assistance with reviewing the commercial and strategic options, resources estimates and technical evaluations.  Partnering or farm-out activity has also been supported by Tamarind. Other activities being conducted through the partnership includes analysis for expanding the lifespan of existing fields and future decommissioning projects. PPL 358, in the Cape Vogel Basin, was also part of the farm-out offer before expiring on 22 November 2016. Oil and gas seeps have been observed, though the area is underexplored. Studies by SPB indicate that rock sequences within the permit may contain thermally mature Pre-Miocene source rocks, which would be on trend with the nearby petroleum indicators recorded from the Ocean Drilling Project, which comprised 23 stratigraphic wells in 1998. Dondonald (Rawson subsidiary) have since submitted APPL 633 over the same area. South Pacific is looking for farm-in partners to form a joint venture to explore its four, 100% owned licences.

Papua New Guinea, PPL 358