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Saike 10 flow tested from an initial rate of 92 bo/d to 42 bo/d between 2-6 May 2020 for an average of 54 bo/d, from 747-749.5m in the Akusu Group. The oil exploration well was spudded on 28 March 2020 and was drilled to a TD of 923m MD in the Proterozoic Akusu Group on 8 April 2020. The objective of Saike 10 was to explore the hydrocarbon potential of the Saike High Structure, Tarim Basin. Saike 10 is in the Zhongman Petroleum and Natural Gas Group operated Wensu Block in the Tarim Basin.

Saike 10 in the Zhongman Petroleum and Natural Gas Group operated Wensu Block in the Tarim Basin flow tested from an initial rate of 92 bo/d to 42 bo/d between 2-6 May 2020 for an average of 54 bo/d, from 747-749.5m in the Akusu Group.

The long-awaited Intracampos Bid Round is now scheduled to open 30 Apr ’18, the latest delay owed to governmental changes. will officially open on 1 Mar ’18, with 8 blocks on offer (namely Araza Este, Charapa, Chanangue, Espejo, Iguana, Panayacu Norte, Perico and Sahino) and a focus on central-SE fields currently dormant or requiring further explo/appraisal. Promotional meetings are planned and bid presentations due 10 July, with PSC signatures to take place on 22 Aug ’18.

Ecuador (Putumayo B.) Charapa

In early July 2020, Ecopetrol America acquired 25% WI from operator Chevron USA in four Mississippi Canyon blocks: MC 411, MC 412, MC 587 and MC 588, sited in the Louisiana Coastal Basin. The transaction is effective as of 1 January 2020. All four blocks were originally offered as part of Lease Sale 254 on 22 March 2017 and subsequently awarded to Chevron USA on 1 August 2017. Following completion of the transaction, equity in MC 411, MC 412, MC 587 and MC 588 is now shared between Chevron USA (75% WI + Op) and Ecopetrol America (25%).

United States (GOM B.), blocks MC 411, MC 412, MC 587 and MC 588, Ecopetrol America acquired 25% WI from operator Chevron USA.

Inpex's partner Shell is planning to divest its 35% participating interest (PI) in the Masela PSC, located in Timor Sea. As reported by local media on 5 July 2020, quoting SKK Migas's Deputy for Operations, Inpex and Shell are in discussion for the former to take up the PI, and at the same time Inpex could continue to look for a new partner to join the PSC. The block contains the Abadi field which is under development phase. The operator last finalized in mid-June 2020 two contractors for the subsea umbilicals, risers, and flowlines FEED work. Likewise, the operator also received approval from the Regional Governor of Maluku for the land acquisition implementation stage. The land area, that covers approximately 27 hectares, will host a port to be utilized for movement of goods, equipment, spare parts, as well as building the onshore LNG (OLNG) plant. The Abadi project was initially envisioned by Inpex as a Floating LNG (FLNG) development due to the remote location of the field, in deep water and away from existing infrastructure. However, in March 2016, the President of Indonesia instructed the operator to change the FLNG scheme to an OLNG development, in order to maximize the benefit for local communities. Inpex received approval for the revised Abadi POD on 12 July 2019. The project will require an investment of approximately USD 18-20 billion. Concurrently with POD approval, the Ministry of Energy and Mineral Resources also granted a seven-year additional time allocation for the current PSC plus a 20-year extension, moving the contract expiry date from 2028 to 2055. The seven-year period is to compensate for the time spent studying the previously proposed offshore LNG proposal, while the 20-year extension will allow for the realization and full monetization of the project, ensuring sufficient financial conditions for the participants. Background Information The Masela PSC was originally awarded to Inpex (100%, operator) in 1998. On 24 July 2011, Inpex signed an agreement to farm-out 30% participating interest in the Masela PSC to Shell. Official approval of the deal was reported on 8 December 2011. Shell’s involvement in the Prelude FLNG project in offshore Australia played a role in its selection as a partner. Farm-in opportunity for non-operating interest in the block continued to exist after the farm-out to Energi Mega Persada in November 2009. In 2013, Energi Mega Persada decided to exit the block, subsequently the 10 % PI by the company was taken over by Inpex and Shell, each added extra 5% to their existing share.

Indonesia (Bonaparte B.) Masela op. by SHELL (35%), INPEX (34%), JOGMEC (31%), Shell is planning to divest its 35% participating interest (PI) in the Masela PSC, located in Timor Sea.

According to local reports in late-September 2018, the subsidiary company of CAPSA, Capex, has reached the total depth (TD) of 4,100 m (13,451 ft) on the Agua del Cajon 1033 outpost well on its 100%-held Agua del Cajon block in mid-August 2018. The well was spudded in early June 2018 with objectives in the Lotena Formation and unconventional Lajas Formation. Agua del Cajon block covers 353 sq km of land in the Huincul Uplift area of the Neuquen Basin. The outpost well was drilled to appraise the Agua del Cajon field which has produced over 21 Bscfg and 8 MMbo since 1971, predominantly from the Lotena Formation sandstone. The field also produces from several unconventional reservoirs including Vaca Muerta and Quintuco shales and tight reservoirs of Los Molles and Lajas formations. The Neuquen Province government granted a 35 year concession for unconventional hydrocarbons in the block to Capex in April 2017. The company reportedly plans to invest over USD 126 million in conducting a pilot project targeting gas from the Vaca Muerta Formation shale through 2021. The pilot project will include the drilling of 35 wells over four years, which can expand to 240 wells with total investment of over USD 1.5 billion, if results are positive. Background Information Capex has been the 100% operator on the Agua del Cajon block since January 1991, with the producing Agua del Cajon field on improved recovery since early-1999.

Argentina Capex SA reached TD on Agua del Cajon 1033 outpost, Agua del Cajon block, Neuquen Basin

W-C part of Mississippi Canyon block 434, OCS lease G35971, WD 2,134m, target Norphlet play, cleared to plug 23 Jan ’19 after only 2 weeks ops suggesting tech probs, Pacific Sharav DS. A new drilling permit was issued yesterday for replacement well MC 434-2. Chevron (op), partner Total.

United States, G35971

M44-B2-1 / block 4845, Zagros Fold Belt in District X, SE Turkey, spudded mid-Jan ’19, believed completing at TD 3,385m, shows in the target Mardin + Bedinan fm’s. * TransAtlantic Exploration Mediterranean International Pty Ltd (TEMI)

Blackeye 1 (TransAtlantic Petroleum 100%) in M44-B2-1 / block 4845, Zagros Fold Belt in District X, SE Turkey, believed completing at TD=3385m, shows in the target Mardin + Bedinan fm’s.

CalEnergy has acquired Zennor's 11% stake in P1242 on 21 Jul '20. The 53-sq km licence covers blocks 47/5b + 48/1a and contains the Platypus gas field, PDO for which is awaiting approval. Dana Petr (op), partners CalEnergy + Parkmead.

(Anglo-Dutch B.) CalEnergy acquired 11% from Zennor in the P1242 block op. by KNOC (59%)

The NPD confirmed on 25 July 2018 that DEA has acquired 13% interest in PL 211 and PL 211 B from Total with effect from 27 June 2018. PL 211 was awarded in the 15th Round and covers a 242 sq km area over parts of blocks 6506/6 and 6507/4. PL 211 B is located immediately south, covering 37 sq km over parts of blocks 6506/9 and 6507/7, and was awarded in APA 2006. The licences contain the large Victoria gas discovery made by Mobil’s 6506/6-1, drilled in 2000, and appraised by current operator Total in 2009. The discovery is HPHT and has Middle and Lower Jurassic reservoirs in a four-way dip-closed domal structure. Victoria is one of the largest undeveloped discoveries on the Norwegian Continental Shelf and prior to Total drilling this appraisal, the NPD estimated that it held recoverable reserves of approximately 3.1 Tcf of gas. However, the reservoir is complex and the reserves range has subsequently been lowered to 706 Bcf-2.12 Tcf recoverable gas. Interest in both licences is now split between Total E&P Norge AS (57% + operator) and DEA Norge AS (43%).

DEA has acquired 13% interest in PL 211 and PL 211 B from Total with effect from 27 June 2018.

Source has acquired a 10% stake from Equinor in PL 878, 361 sq km over part-blocks 30/2 + 30/3 north of Oseberg. A well is planned shortly on the Atlantis prospect. Partners now Equinor (op), Wellesley + Source.

Equinor (->70% op. Wellesley 20%) transferred 10% of its previous 80% operated stake in PL 878 to Source Energy.

VIM 21 block, Lower Magdalena, TMD 2,12m (1,638m TVD), 9m gas pay in the target Porquero sst, ops concluded Dec '19, Pioneer 53 rig.

Arandala 1 nfw. (Canacol 100%) on the VIM 21 Block, 9m gas pay in the target Miocene Porquero sst.

Canadian Husky proposes to acquire fellow MEG Energy in a cash-and-share deal valued at CAD 6.4 bn, including the assumption of ab. CAD 3.1 bn debt. A combined company would be headquartered in Calgary, ad result in total upstream production of >410,000 boe/d, refining + upgrading capacity ab. 400,000 b/d.  MEG’s board will consider and evaluate the Husky offer if and when received.

Canadian Husky proposes to acquire fellow MEG Energy in a cash-and-share deal valued at CAD 6.4 bn, including the assumption of ab. CAD 3.1 bn debt. A combined company would be headquartered in Calgary, ad result in total upstream production of >410,000 boe/d, refining + upgrading capacity ab. 400,000 b/d. MEG’s board will consider and evaluate the Husky offer if and when received.

Centrica is looking to sell its 69% part in Spirit Energy, created in 2017 by merging Centrica’s upstream segment and Bayerngas Norge.  The company is looking to focus closer on its downstream customers after what it describes as a challenging first half – to which warmer than normal weather in the UK and North America was no stranger. Spirit has interests in the UK, Denmark, Norway and the Netherlands. It is made up by Centrica, Stadwerke München, Bayerngas and TIGAS-Erdgas.

Centrica is looking to sell its 69% part in Spirit Energy, created in 2017 by merging Centrica’s upstream segment and Bayerngas Norge.

Mahu field area, Junggar Basin, tested 670 Mcfg/d + 24 bo/d from the Jurassic Sangonghe fm, a first here after the known producing Permian Wuerhe + Triassic Baikouquan fm’s.

Mahu field area, Junggar Basin, tested 670 Mcfg/d + 24 bo/d from the Jurassic Sangonghe fm, a first here after the known producing Permian Wuerhe + Triassic Baikouquan fm’s.

Further to DEA 7 Feb ’18 (initial tests): Block 10, Bhola Island on/offshore Bengal Basin, N. of Shahbazpur onshore field, by late Feb ’18 testing had reached 32.13 MMcfg/d and well declared commercial although production is not yet on the cards until an appropriate appraisal programme has been carried out. Gazprom (well op), Bapex (block op).

Shahbazpur-6 (Bhola N.-1) nfw, Block 10,testing had reached 32.13 MMcfg/d and well declared commercial although production is not yet on the cards until an appropriate appraisal programme has been carried out. Gazprom

N. of Yacheng Sag in Qiongdongnan Basin, WD 80m, drilled + compl. between  22 Oct – early Nov ’18, Nanhai 7 SS. Target Mio-Oligocene clastics.

Yacheng 13-9-1 (YC 13-9-1) nfw N. of Yacheng Sag in Qiongdongnan Basin, WD 80m, drilled + compl.Target Mio-Oligocene clastics.

Rondon 2A-1 block, Llanos Basin, P&A at TMD 3,307m in Dec ’18, tested. PTVD was 3,230m, target L. Carbonera fm + U. Cretaceous. Oxy (op), partner Ecopetrol

Colombia (Maracaibo B.) Carbonera

Nur D&PL, Indus onshore, TD 2,975m, susp. after testing early Jul ’18, w.o. results, CCDC rig 31. Target Lower Goru fm.

Nur West 1 (OGDCL 100%) in Nur D&PL block, susp after tests, results n/a, Target Lower Goru fm. TD=2975m.

Oranto is seeking to dilute its 100% stake in the Ngassa Shallow and Ngassa Deep Play (406 sq km) licence, ahead of embarking on 2D seismic surveying (200km commitment), and airmag by BGP.  The block covers 406 sq km in WD

Uganda, Ngassa Deep Play

On 28 November 2019, Petrobras issued a press release indicating it signed a sales agreement with PetroRio Jaguar Petroleo Ltda for its 30% working interest in the Frade production concession. PetroRio will own 100% working interest in the contract once all formal approvals are granted for the Petrobras 30% working interest acquisition. The terms of the deal are that PetroRio pays Petrobras USD 100 million in two tranches, USD 7.5 million on contract signature and USD 92.5 million upon formal governmental approvals. There is also a USD 20 million contingency payment related to a possible new discovery in the field. Petro Rio Jaguar Petroleo Ltda operator has acquired working interest over several years from Frade Japao Petroleo Ltda with formal approvals on 1 November 2019, and Chevron Brasil Upstream Frade Ltda on 2 May 2019. PetroRio formed two new operating subsidiary companies for the acquisitions. Petro Rio Jaguar Petroleo Ltda for the 51.7391% working interest formerly held by Chevron and PetroRio White Shark Petroleo Ltda holding the 18.2609% working interest formerly held by Frade Japao Ltda. On 25 March 2019, PetroRio issued a press release indicating it closed on the acquisition of the 51.74% working interest held by Chevron Brasil Upstream Frade Ltda in the Frade production concession. PetroRio formed a new operating subsidiary for this acquisition Petro Rio Jaguar Petroleo Ltda. The new contract equity breakdown is Petro Rio Jaguar Petroleo Ltda operator with 51.74% working interest and partners are Petrobras with 30% interest, and Frade Japao Petroleo Ltda, holds the remaining 18.26%, pending the sale of its working interest to PetroRio that will give it 70%. PetroRio indicated this transaction adds approximately 11 Mbo/d to its production base and 43 MMboe in 2P reserves. It also is studying the possibility to drill a pre-salt prospect to a proposed total depth (PTD) of 4,500 m in 2020. On 30 January 2019, PetroRio issued a press release indicating it signed a share purchase agreement to acquire the 51.74% working interest held by Chevron Brasil Upstream Frade Ltda in the Frade production concession. With the October 2018 acquisition of the 18.26% in Frade Japao, PetroRio will be the operator with a 70% working interest in the contract once all formal approvals are granted. The remaining partner is Petrobras with 30% working interest. PetroRio reported that remaining 2P reserves in the Frade Field are 57.8 MMbo. The deal value has yet to be officially reported but is speculated to be in the USD 500 million range. On 22 March 2017, the ANP granted operator Chevron approval for a partial modification of its Frade development plan approved previously by the agency on 9 December 2016. The agency made modifications to several of the conditional requirements for the granting of the advanced 16-year extension with possible additional extensions. On 9 December 2016, the ANP approved an advanced 16-year extension for the Chevron operated Frade production concession in the Campos Basin. The contract now has a final expiry date of 31 December 2041 which was extended from the original expiry date of 30 July 2025. Previously the ANP approved a modified development plan for the contract on 30 March 2016.

On 28 November 2019, Petrobras issued a press release indicating it signed a sales agreement with PetroRio Jaguar Petroleo Ltda for its 30% working interest in the Frade production concession. PetroRio will own 100% working interest in the contract once all formal approvals are granted for the Petrobras 30% working interest acquisition.

KG-DWN-98/2 block, KG deepwater, WD 341m, susp at TD 2,750m, new pool o&g discovery, tested 597 bo/d + 0.463 MMcfg/d on 1/4” choke from 2,654-2,666m and 2,370 bo/d + 2.2 MMcfg/d on 1/2” choke from 2,448-2,265m, both in the Godavari fm. Olinda Star SS released 13 May ’18.

KGD-982NA-M 6-(AE) (ONGC 100%) in KG-DWN-98/2 block, WD=341m, new pool o&g discovery, tested 597 bo/d + 0,5 MMscfg/d [1/4” choke] from 2654-2666m and 2370 bo/d + 2,2 MMscfg/d [1/2” choke] from 2448-2265m, both in the Godavari fm.

Roc Oil and Smart Oil have signed a PSC with CNOOC for block 22/04 and the Weizhou 10-3W oilfield in the Beibu Gulf of South China Sea, WD 40-80m. - 22/04 (80 sq km): Roc 65%, Smart 35% joint optrs, CNOOC has the right to participate up to 51% in the event of a commercial discovery. - Weizhou 10-3W (18 sq km): Roc 35%, Smart 25%, joint optrs for the devt ops, CNOOC 40%.

Roc Oil (35%) and Smart Oil (25%) have signed a PSC with CNOOC (has the right to participate up to 51% in the event of a commercial discovery) for block 22/04 and the Weizhou 10-3W oilfield in the South China Sea, WD 40-80m.

Mirpur Khas 2568-7 EL, Lower Indus onshore, P&A dry at TD 2,614m in late Feb ’19, ZPEC-33 rig. Target Lower Goru. UE (op), partners Bow Energy, SRL, Zaver + Govt Holdings.

Chang 1 (UEPL 65% op, Bow Energy 30%, GHPL 5%) in Mirpur Khas 2568-7 EL block, P&A, It is understood that the well was unsuccessful in finding the hydrocarbons.

Believed appraisal to GS-29 1 field in GS-29 Extn ML, KG offshore, WD 90m, susp at 197m in October after mech. Props, Sagar Bhushan DS. PTD is/was 3,326m.

India (Krishna-Godavari B.) GS-29 AM op. by ONGC (100.0%) in GS-29 Extn ML block

On 31 July 2020 Equinor agreed to sell 40.8125% of its interest and transfer operatorship of licences P234 (block 3/28a), P493 (block 3/28b), P920 (3/27b) and P977 (blocks 9/2a and 9/3a) to EnQuest. A sale and purchase agreement has been signed between the two companies for the licences that host the Bressay heavy oil field. The sale is for an initial consideration of GBP 2.2 million (as a carry against 50% of Equinor's net share of costs) and a further consideration of GBP 11.48 (USD 15 million) will be payable when the Bressay field development plan is approved. The deal is estimated to complete in Q4 2020. Located northeast of Kraken field, the Bressay field was discovered in 1976 with heavy oil and a small gas cap in the Upper Paleocene Teal Sands. The heavy oil has an average API of 12° and a viscosity of 550 cP. An environmental statement was submitted for the field in June 2013 which described the development via 70 development wells, with operations commencing in 2016, first oil in 2018 and peak production was anticipated to take place between 2022 and 2025. However, by November 2013 the development was stated to be delayed and in August 2016 the concept selection was deferred because of market conditions and the need to simplify the development concept. A number of development scenarios are still under consideration, one involves a tie back to Kraken field. Interest in the licences P234, P493, P920 and P977 is held by EnQuest Heather Ltd (40.8125% + operator), Equinor (UK) Ltd (40.8125%) and Chrysaor Ltd (18.375%).

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

Rey is on the lookout for a partner in EP 487 (Derby), 5,058 sq km onshore Canning Basin, up to 50% available and possibly operatorship. This emerged after a deal with Doriemus was cancelled last August (DEA 5 Aug '19), aimed at contributing to the work programme term and/or providing working capital. Contact: StanleyFu@reyresources.com.

Rey is on the lookout for a partner in EP 487 (Derby), 5,058 sq km onshore Canning Basin, up to 50% available and possibly operatorship.

On 17 December 2019, the Federal Agency for Subsoil Use held an auction for three blocks in Yamalo-Nenets Autonomous Okrug (Western Siberia). Rosneft and Gazprom Neft emerged as the winners of the auction. The companies will obtain 25-year E&P licenses with a seven-year exploratory stage. The Kharampurskiy Zapadnyy block covers 898 sq km in the Nadym-Taz Province and encompasses the Kharampurskoye Zapadnoye oil discovery with 3P reserves estimated at 31 MMbbl and seven prospects with combined resources estimated at 43 MMbbl of oil and 82 Bcf of gas. Seismic coverage amounts to 1,300 km. Six wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 100 MMbbl of oil, 3.743 Tcf of gas and 69 MMbbl of condensate. The starting price amounted to RUB 402.826 million (USD 6.5 million). Rosneft, competing against its subsidiary, won the auction with the starting price. The Mitikyakhskiy 1 block covers 1,188 sq km in the Nadym-Taz Province and encompasses several prospects with combined resources estimated at 139 MMbbl of oil, 2.776 Tcf of gas and 93 MMbbl of condensate. Seismic coverage amounts to 2,069 km. Two wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 485 MMbbl of oil, 325 Bcf of gas and 10 MMbbl of condensate. The starting price amounted to RUB 539.81 million (USD 8.7 million). Rosneft, competing against Gazprom Neft, won the auction with the starting price. The Yamburgskiy Severnyy block covers 2,101 sq km in the Nadym-Taz Province and encompasses a part of the Mitiyakhskaya prospect with resources estimated at 11 MMbbl of oil, 206 Bcf of gas and 7 MMbbl of condensate. Seismic coverage amounts to 2,994 km of 2D data and 151 sq km of 3D data. One well has been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 750 MMbbl of oil, 22.461 Tcf of gas and 370 MMbbl of condensate. The starting price amounted to RUB 353.833 million (USD 5.7million). Gazprom Neft, competing against Rosneft, won the auction with the starting price.

Rosneft won Kharampurskiy Zapadnyy (898km²) in the Nadym-Taz Province and Mitikyakhskiy 1, (1188km²) in the same area.

OGDC has secured the Chabaro D&PL serving the 2017 Chabaro-1 gas-cond discovery in the Lower Indus Basin effective 18 Apr ‘19. The 9-sq km lease was excised from the Khewari EL in the Khairpur district of Sindh. OGDC (op), partner GHPL.

OGDC has secured the Chabaro D&PL serving the 2017 Chabaro-1 gas-cond discovery in the Lower Indus Basin effective 18 Apr ‘19. The 9-sq km lease was excised from the Khewari EL in the Khairpur district of Sindh. OGDC (op), partner GHPL.

In early March 2018, SDX Energy encountered gas in its Sidi Al Harati 2 (SAH 2) appraisal/development well, located on the Sebou Central exploration permit in the Gharb Basin. The well encountered 5.2m of net gas pay in two intervals in the Miocene Guebbas and Hoot formations. SAH 2 was spudded in late February 2018, using an XCD Drilling rig. It reached a TD of 1,304m. SDX is now planning to test and complete the well, before moving the rig to the Lalla Mimouna permit to drill the LNB 1 NFW.SAH 2 is understood to have been an appraisal/development of the 1985 SAH 1 discovery, drilled by Petrofina. It reached 1,499m TD, encountering gas in the Miocene. In June 2014, Circle Oil also made a Miocene gas discovery in the Sidi Al Harati West 1 (SAHW 1), located ~1.5km SW of SAH 1. It was tied into production in 2015. SAH 2 forms part of the company's nine-well campaign in the country, following the acquisition of Circle Oil's Moroccan assets in January 2017. The Sebou Central permit contains 16 Miocene sandstone discoveries, with just eight of the fields currently producing. Gross production across the permit averages just 5.1 MMcfg/d. SDX is aiming to increase output by 50% during the course of the development campaign. The company operates Sebou Central with 75% equity, in partnership with ONHYM (25%, carried).

SDX Energy encountered gas in its Sidi Al Harati 2 (SAH 2) appraisal/development well, located on the Sebou Central exploration permit in the Gharb Basin. The well encountered 5.2m of net gas pay in two intervals in the Miocene Guebbas and Hoot formations.

It was announced on 28 November 2019 that Arar Petrol ve Gaz Arama Uretim Pazarlama A.S has been awarded the N42-A exploration licence (Zagros Province) on 22 November 2019 for a period of five-year. The licence, covering an area of 615 sq km, is located towards southeast of the country and Arar Petrol will be 100% owner and operator of the licence. The company had filed the application on 26 November 2018.

Turkey, not found

AE-0024-2M-Okom-07, offshore Sureste Basin, 5km NNE of Wayil discovery, susp. results n/a late Nov ’18, Prospector II JU. PTD was 4,950m, target Cretaceous.

Yok 1EXP in AE-0024-2M-Okom-07, offshore Sureste Basin, 5km NNE of Wayil discovery, susp. results n/a late Nov ’18, target Cretaceous

Transaction adds a high-impact growth opportunity with scale to Beach’s exploration portfolio Beach to farm-in to giant Ironbark gas-condensate prospect in the Carnarvon Basin Ironbark located in close proximity to North West Shelf LNG Project (Rankin Trend) Subject to exercise of option, BP to participate with majority stakes in permits    Beach Energy has entered into binding agreements with Cue Exploration, a 100% owned subsidiary of Cue Energy Resources to acquire, subject to terms and conditions, equity in North West Shelf exploration permits WA-359-P and WA-409-P in the Carnarvon Basin, offshore Western Australia.  Ironbark Prospect WA-359-P and WA-409-P are adjoining exploration permits which contain the giant Ironbark gas condensate prospect. Ironbark is a Mungaroo Formation structural closure that covers an area of approx. 400 sq kms, and is defined by high-quality 3D seismic data. The Ironbark prospect is interpreted to have reservoirs of similar age to nearby giant fields such as Gorgon and Goodwyn. A discovery at Ironbark could result in a multi-Tcf gas field.  The farm-in agreement for WA-359-P and call option for WA-409-P give Beach exposure to a potentially significant gas-condensate discovery which may extend across both permits. Exploration success at Ironbark could provide significant, long-term gas volumes to feed nearby LNG plants in the coming decade. Ironbark is located less than 50 kms from the North West Shelf LNG’s Rankin platform, and is in close proximity to Pluto and Wheatstone LNG infrastructure. Ironbark’s location provides significant optionality for commercialisation and marketing. Farm-in and call option arrangements WA-359-P farm-in agreement Beach will acquire a 21% equity interest in WA-359-P in exchange for a one-off payment to Cue of $900,000 for past costs, and future payments equating to 4% of Cue’s cost of drilling the Ironbark-1 exploration well within the permit. The agreement is subject to the following conditions precedent: BP exercising its option to acquire a 42.5% equity interest in WA-359-P. BP has until  11 December 2017 to exercise its option, unless extended. Refer to announcement by Cue on 4 October 2017 for further information. Formation of a Joint Venture and associated Joint Operating Agreement with full funding for the Ironbark-1 exploration well. Permit holders obtaining an extension to the current permit expiry date of 25 April 2018, to allow satisfactory timing for planning and drilling of the Ironbark-1 exploration well. Other terms, conditions and approvals customary for transactions of this nature.  Assuming satisfaction of all conditions precedent, ownership interests in WA-359-P would be  BP: 42.5%, Cue: 36.5% and Beach: 21%. WA-409-P call option  Beach has acquired for nominal consideration a call option over a 7.5% equity interest in WA-409-P. If exercised, Beach will make future payments equating to 7.5% of Cue’s cost of drilling an exploration well within the permit (timing to be confirmed), and pay Cue a 10% royalty on all future revenue earned by Beach from the permit. The option may be exercised until 31 July 2019. Assuming exercise of the call option, ownership interests in WA-409-P would be BP: 80%, Cue: 12.5% and Beach: 7.5%.   Beach’s CEO, Matt Kay, said: 'For some time Beach has been seeking high impact exploration opportunities in Australia and New Zealand to add to its growth portfolio. We have taken a disciplined approach and the Ironbark prospect is an exciting, high impact exploration prospect. With favourable Western Australia LNG market dynamics over the coming decade, successful development of Ironbark may align with expected shortfalls in LNG feedstock. Beach is also excited to collaborate with high quality joint venture partners in BP and Cue. This transaction is another example of progress against Beach’s growth strategy, and provides an attractive risk and reward profile to support ongoing shareholder value creation.' Click here for Cue Energy's announcement  Original article link Source: Beach Energy

Australia, not found

Pertamina is reportedly proposing to operate the Rokan block in Central Sumatra, ready to take over from Chevron and continue to apply enhanced oil recovery. The 6,264-sq km block contract expires in Sep ’21 and is currently run by Chevron 100%:

Pertamina is reportedly proposing to operate the Rokan block in Central Sumatra, ready to take over from Chevron and continue to apply enhanced oil recovery. The 6,264-sq km block contract expires in Sep ’21 and is currently run by Chevron 100%:

Chevron Australia Pty Ltd was awarded retention lease WA-87-R, located in the Exmouth Plateau, North Carnarvon Basin, on 2 March 2018.  The licence has been awarded for a period of five years and will expire, or be eligible for renewal, on 1 March 2023. The licence contains the Isosceles discovery, which was made in April 2015. The discovery well was drilled as part of Chevron’s exploration programme to find gas to expand the Wheatstone and Gorgon LNG Projects and it is thought the discovery could be tied into one of these once developed.  A work programme has been assigned for the duration of the licence’s validity, with seismic interpretation to be undertaken before reservoir modelling and development concept outlines are completed.  Finally gas market analysis and options will be reviewed. The Isosceles well was drilled under the work programme for exploration permit WA-374-P.  This permit has been reduced in size as a result of the award of WA-87-R. WA-87-R, which covers an area of 160 sq km, was awarded on 2 March 2018.  Participants in the licence are Chevron Australia (WA-374-P) Pty Ltd (50% + Operator), Shell Australia Pty Ltd (25%) and Mobil Australia Resources Co Pty Ltd (25%).

Chevron (50% + Operator, Shell 25%?, ExxonMobil 25%?) was awarded retention lease WA-87-R (has been reduced in size from WA-374-P)

The previous licence holders in PL 019 F (Repsol 61%, INEOS 34% and KUFPEC 5%) have all withdrawn with effect from 31 January 2020 (reported by the NPD on 6 February 2020). Their interests have been acquired by Aker BP (55%) and DNO (45%) and Aker BP has assumed operatorship. This deal aligns the interests in PL 019 F with PL 065 which lies immediately to the west. PL 019 F (3 sq km of block 2/1 which was split from PL 019 B in December 2018) contains the southeasterly extension of Tambar which lies mostly in PL 065. Tambar was discovered in 1983 by 1/3-3. It is located on the Ula Trend at the eastern margin of the Central Trough, between Gyda and Ula and is a hanging wall trap formed by the extension and minor contraction of a late Jurassic fault array. Tambar has been developed as a tie-back to the Ula Field, some 16 km to the northwest. The development uses a remotely controlled wellhead facility without processing equipment. The field was granted a lifetime extension until 1 January 2022 by the NPD on 8 July 2016. In the original PDO, approved on 15 July 2001, the lifetime of the facility was defined as 15 years, meaning it was due to expire on 15 July 2016. In 2018 two new infill wells, targeting undrained areas in the north and south of the field as part of re-development work, were completed and initial performance exceeded pre-drill expectations. This, plus the implementation of gas lift in three existing wells, will extend the lifetime of the field from 2018 to 2028, with the potential for it to be extended again in the future. The upgrade is targeting reserves of 27 MMboe, producing an additional 4,000-6,000 boe/d, and total investments were forecast at approximately NOK 1.7 billion (USD 205 million). Interest in PL 019 F is now held by Aker BP ASA (55% + operator) and DNO Norge AS (45%).

The previous licence holders in PL 019 F (Repsol 61%, INEOS 34% and KUFPEC 5%) have all withdrawn. Their interests have been acquired by Aker BP (55%) and DNO (45%) and Aker BP has assumed operatorship.

Further to DEA 26 Feb '20, FID is hoped for mid-2020 on the 2018 Glendronach discovery in P1453, WoS, although a cloud remains from results of the appraisal drilled last year. Results were apparently below expectations, and any devt would be using a single well tied into the Edradour-Glenlivet facilities. A DST also revealed high mercury content in produced fluids, treatment of which will be required. Total (op), partners Ineos + SSE E&P.

2018 Glendronach discovery in P1453, WoS, although a cloud remains from results of the appraisal drilled last year. Results were apparently below expectations,

An auction is planned 24 Jan '20 for 25-year rights to the 108-sq km Padimeyskiy block (Padimeyskoye oil discovery) in the Nenets AO, Timan-Pechora Basin, application deadline 27 December. Starting price USD 8.16 MM. Likewise for the 711-sq km Povorotnyy block in the Komi Republic, Timan-Pechora Basin, same schedule, starting price USD 60,000. Contact: Sevzapnedra, sevzap@rosnedra.gov.ru.

An auction is planned 24 Jan '20 for 25-year rights to the 108-sq km Padimeyskiy block (Padimeyskoye oil discovery) in the Nenets AO, Timan-Pechora Basin, application deadline 27 December.

PEMEX suspended as an oil and gas discovery the Tlamatini 1EXP directional new-field wildcat (NFW) in the AE-0006-6M-Amoca-Yaxche-04 (AE-0150-Uchukil Area A) entitlement block during mid-October 2019 according to information reported by the CNH. The NFW reached a final total depth (TD) of 3,962 m measured depth (MD) and 3,610 m true vertical depth (TVD). The well was spudded on 19 July 2019. The NFW was targeting the Lower Pliocene and Upper Miocene at a proposed total depth (PTD) of 3,952 m measured depth (MD) and 3,600 m true vertical depth (TVD). The prospect is a north-west to south-east elongated structure bounded by faults. The “Campeche 9024” J/U drilled the well in a water depth of 26m. The unrisked prospective resources are estimated to be 75 MMboe and the 58% success factor lowers it to 43.5 MMboe in risked resources. The Tlamatini prospect is located in the south-western area of the block about 10.6 km west southwest of the Pokche 1 Jurassic oil and gas discovery. The estimated drilling cost is USD 25.9 million at 1USD = 20 MXN and the estimated completion cost is USD 14.95 million. On 12 July 2019, the CNH approved a drilling permit request by PEMEX for the Tlamatini 1EXP directional new-field wildcat (NFW). SENER granted the AE-0006-6M-Amoca-Yaxche-04 entitlement to Pemex 100% through Ronda 0 on 27 August 2014 with a two-year extension granted on 27 August 2017.The entitlement expired on 27 August 2019 and was replaced by the AE-0150-Uchukil Area A that covers a modified area of 857.12 sq km. On 12 July 2019, the CNH approved a request by PEMEX to approve its exploration plan subject to recent area modifications to the AE-0006-5M-Amoca-Yaxche-04 and AE-0051-5M-Mezcalapa-01 entitlement blocks.The exploration plan was previously approved for the AE-0006-4M-Amoca-Yaxche-04 entitlement block prior to official approvals for the area modification changing the entitlement designation to 5M instead of 4M.This was necessary in order for PEMEX to receive formal approvals for a drilling permit for the Tlamatini 1EXP that now is located in the modified AE-0006 block instead of the AE-0051 block.It also moves the currently drilling Chejekbal 1EXP into the AE-0006 block.On 9 May 2019, the CNH approved a technical evaluation requested by SENER related to a request by PEMEX to modify seven entitlement blocks in the offshore and onshore Sureste Basin that included the AE-0006-5M-Amoca-Yaxche-04 and AE-0051-5M-Mezcalapa-01 entitlement blocks.

Tlamatini 1EXP nfw. (Pemex 100%) in the AE-0006-6M-Amoca-Yaxche-04 (AE-0150-Uchukil Area A), suspended as an oil and gas discovery was targeting the Lower Pliocene and Upper Miocene.

The NPD reported on 8 November 2018 that Equinor has transferred its 6.65% equity in PL 018 C and PL 018 DS to Petrolia with effect from 31 October 2018. The licences cover the same 24 sq km area over the southerly part of block 1/5 and contain the eastern extent of Flyndre. PL 018 C applies above Top Ekofisk and below Base Hidra. PL 018 DS applies from Top Ekofisk to Base Hidra. Flyndre straddles the UK / Norway border (with 7% in Norway) and was discovered in 1974 by Phillips Petroleum with Norwegian well 1/5-2. The field’s reservoir is the Paleocene Balmoral Sandstone at around 3,000 m. Flyndre started production in March 2017 using a single horizontal well as a subsea tie-back to the Clyde platform in the UK. From Clyde the produced oil and gas is exported to the Teeside and St Fergus terminals. When the field came onstream it was expected to produce up to 10,000 bo/d and was planned to remain onstream until at least 2023. However, production has been lower than forecast and pressure is declining faster than anticipated. Interest in PL 018 C is now held by Total E&P Norge AS (88.35% + operator), Petrolia NOCO AS (6.65%) and Petoro AS (5%) and interest in PL 108 DS is divided between Total E&P Norge AS (60.01% + operator), Production Energy Company AS (15%), Aker BP ASA (13.34%), Petrolia NOCO AS (6.65%) and Petoro AS (5%).

Equinor has transferred its 6,65% equity in PL 018 C and PL 018 DS to Petrolia. Interest in PL 018 C is now held by Total (88.35% + op), Petrolia (6.65%) and Petoro AS (5%) and interest in PL 108 DS is divided between Total (60.01% + op), Production Energy Company AS (15%), Aker BP (13.34%), Petrolia (6.65%) and Petoro AS (5%).