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28 March 2019, the Turkmennebit state concern and the Areti International Group of Companies have signed a Memorandum of Understanding to co-operate in the development of the Uzynada onshore gas-condensate discovery. Under the MoU, Areti will be studying the field data provided by Turkmennebit for about a year, and will then start negotiating a service contract. Areti International currently holds an E&P contract for the neighbouring offshore Block 21. The company has held the block since 2009, however, little exploration work has been reported since. The Uzynada discovery is located close to the Caspian coast and Block 21. It was discovered by well no. 7 in May 2017. The well has been drilled to 7,150 m and is the first super-deep well in Turkmenistan. It flowed gas with condensate at rates of 17.1 MMcf/d and 1,200 b/d, respectively, from the interval of 6,689-6,695 m. Uzynada is key in understanding the potential prospectivity of Block 21. Turkmenistan only offers service contracts onshore, while E&P contracts are possible for offshore Caspian blocks, on a direct negotiations basis. Background Information A PSA for Block 21 was originally signed with Itera, a Russian gas producing and distributing company, in September 2009. Having sold its gas business to Rosneft in 2013, Itera was rebranded as Areti. Due to lack of offshore E&P experience, Itera invited Zarubezhneft of Russia as the operating partner with 51% interest in the project in 2011. However, Zarubezhneft quit in 2013, having failed to obtain Turkmen authorities permission to farm into the PSA. According to Areti, it was planning to drill a first exploration well in the West Erdekli prospect close to the coast, in 7-15 m of water, with a planned TD of 6.0-6.5 km. The company estimates the block’s undiscovered resources at 700 billion cubic metres (24 Tcf) of non-associated gas. In 2011, Itera completed a geochemistry survey of the Block 21 contract area as well as a 2D/3D seismic acquisition programme. The latter programme was carried out by Sevmorgeo, a Russian service company. The survey covered the entire block’s territory including the transitional zone. The geochemistry survey was carried out by Pangea, also a Russian service company.

Turkmennebit and Areti Intl Group of Co’s signed an MoU over future co-operation in the devt of the Uzynada onshore gas-condensate discovery near the Caspian coast, towards which a service contract could be negotiated by Areti.

A newly formed WA company has acquired the undeveloped Equus gas project off the North West from US energy company Hess with a view to supplying domestic gas to the State. Privately-owned Western Gas said the timing was right to develop the field given the Australian Energy Market Operator had warned of the risk of a shortfall of WA domestic gas after 2021. Hess last year put on hold the development of Equus, located in the western fringes of the Carnarvon Basin and estimated to contain about two trillion cubic feet of gas. Western Gas executive director Andrew Leibovitch said that was enough gas to supply one-quarter of the State’s domestic demand for more than 20 years. He said Equus was development-ready with exploration and appraisal already completed and engineering activities at an advanced stage. The Equus gas project is located in WA-390-P. Click here for full article Source: The West Australian

Newly-formed Western Gas has reportedly acquired from Hess 4 permits and a retention lease from Hess, comprising 11 gas-cond fields including the 2 Tcf undeveloped Equus gas project in WA-70-R.

Shell has acquired DNO’s 20% interest in PL 811 under a deal reported by the NPD on 9 December 2018. The transfer is effective from 30 November 2018. PL 811 covers an area of 352 sq km over parts of blocks 7/9, 7/12 and 8/7. DNO picked up the licence as part of its acquisition of Origo Exploration Holding AS on 29 June 2017 (announced on 4 May 2017). DNO’s acquisition of Origo in 2017 marked the company’s return to the NCS after a six year absence. DNO took Origo’s seven NCS licences (plus four in the UK), together with all licence commitments and obligations with effect from 31 March 2017, its management and staff and the office in Stavanger. The new company was named DNO Norge AS. Origo announced in February 2017 that it was looking for new investors or buyers for either its assets or the entire company after its major investors Riverstone and GNRI were investing elsewhere.   Interest in PL 811 is divided between Spirit Energy Norway AS (40%), A/S Norske Shell (20%), Aker BP ASA (20%), Faroe Petroleum Norge AS (20%).

Norway, PL 811

In August 2019, Esh El Mellaha successfully tested the Rabeh North 1 new field wildcat in the West Esh El Mellaha (Dev) block, Gulf of Suez Basin. The well encountered oil in the Upper Cretaceous Matulla and Duwi formations. The well which was spudded on 17 June 2019 reached TD in the Paleozoic basement at 2,136 m. The West Esh El Mellaha (Dev) block is operated by Esh El Mellaha, a JV between EGPC (50%) and Lukoil (50%) since September 2001. It covers an area of 47 sq km and includes 2 discoveries (Wadi El Sahl North 1 and Tanan 1) and 3 producing fields (Rabeh, Rabeh East and Tawoos), all found between 1997 and 2000.

North Rabeh 1X nfw (Eshpetco = Lukoil 25%, Tharwa 25% and EGPC 50%, carried) in W. Esh El Mallaha block, oil discovery.

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

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

Aspect Energy's subsidiary Hungarian Horizon Energy (HHE) drilled NFW Burus 2 on the Lakocsa concession during February 2018. It encountered water wet sands and has been completed to support water injection. The well was assumed to be targeting early Pannonian and Miocene intervals with a PTVD of around 2,000m and was drilled from a location 23km ESE of Gorgeteg-Babocsakelet gas field. Lakocsa spans 350 sq km in Baranya County and within the Pannonian Basin. It lies adjacent to the Croatian border and was awarded in February 2016 following the Hungarian 3rd Licensing Round. Aspect completed acquisition of a 255 sq km 3D seismic survey during January 2017 and drilled three earlier exploration wells on the block, 3-5 km N/NW of Burus 2 during Q4 2017 (Pettend Kellet 1, 2 & 3). Aspect Energy operates Lakocsa with 100% equity, held via Hungarian Horizon Energy Ltd.<P />

Aspect Energy's subsidiary Hungarian Horizon Energy (HHE) drilled NFW Burus 2 on the Lakocsa concession during February 2018. It encountered water wet sands and has been completed to support water injection.

NZOG is looking to farmout PEP 55794 (Toroa), 9,835 sq km in the Great South Basin, once the acquisition of Woodside’s 70% is cleared  (ref. DEA 22 Feb ’18). The farmout would be in parallel to that of PEP 52717 in the Canterbury Basin, shared with Beach (also farming-out). Contact: [email protected].

NZOG is looking to farmout PEP 55794 (Toroa), 9,835 sq km in the Great South Basin, once the acquisition of Woodside’s 70% is cleared (ref. DEA 22 Feb ’18). The farmout would be in parallel to that of PEP 52717 in the Canterbury Basin, shared with Beach (also farming-out). Contact: [email protected].

208/94 Przeworsk block enclaved within the 35/96/p Bialobrzegi-Przeworsk permit, Carpathian Foredeep in SE Poland, compl. gas at TD 550m late last year, target Sarmatian-Badenian.

Poland (Outer Carpathian Foredeep (North Carpathian B.)) Przeworsk

In a quarterly report issued 21 July 2020, 88 Energy stated it was continuing discussions with nearby lease owners to monetize existing discovered resources in the vicinity of the company's Yukon leases on the North Slope of Alaska.  88 Energy holds 100% working interest in leases covering 15,235 ac (62 sq km) west of the Arctic National Wildlife Refuge (ANWR). The leases contain the Cascade prospect, a Brookian turbidite fan play estimated to hold 86 MMbo of net mean prospective resources. The prospect is interpreted to have been intersected in a downdip location by well Yukon Gold 1 well which was drilled by BP in 1993 and encountered two oil saturated sands in the Canning formation. There is a recent (2018) 3D seismic survey over the prospect. A discovery at Cascade could be tied back to infrastructure at the nearby Point Thompson field. Permitting activities are continuing while 88 Energy seeks a partner for a possible future drilling campaign.

(Alaska - North Slope b.), 88 Energy stated it was continuing discussions with nearby lease owners to monetize existing discovered resources in the vicinity of the company's Yukon leases on the North Slope of Alaska. 88 Energy holds 100% working interest in leases covering 15,235 ac (62 sq km) west of the Arctic National Wildlife Refuge (ANWR). The leases contain the Cascade prospect, a Brookian turbidite fan play estimated to hold 86 MMbo of net mean prospective resources. The prospect is interpreted to have been intersected in a downdip location by well Yukon Gold 1 well which was drilled by BP in 1993 and encountered two oil saturated sands in the Canning formation.

Talon Petroleum is searching for farm-in partners to fund a well to drill the Rocket prospect in licence P2392 (blocks 28/8b & 28/9b) in return for significant equity. The prospect is located in the Central Graben near the Catcher Area where Palaeocene aged Cromarty Sandstone reservoirs are trapped stratigraphically to form the AVO anomaly supported Rocket prospect. Encounter estimate Rocket to hold most likely STOIIP of 68 MMbo with an upside of 150 MMbo. The well cost is estimated at GBP 7 million. Talon acquired the previous licence holder Encounter Oil on 15 May 2019 and announced that it had received strong interest from potential partners and is confident in securing partners in the near term. As of 21 July 2020 the opportunity was confirmed to be still available and it recently signed a confidentiality agreement with new parties to commence a data room technical review. Talon did not disclose which of its two farm-in opportunities were being reviewed. The Cromarty B1 Sands are expected to be present at the Rocket prospect with the sands having similar characteristics to the Bonneville field 4 km to the east of the prospect. Encounter estimate net to gross to be within the region of 90 metres, porosities of 32% and the sands are interpreted to be ponded in the hanging wall of the N-S fault system. A salt high in the north and east creates a drape structure providing dip closure. In the west and south dip closure is formed from a combination of an upthrown closure and a stratigraphic pinch-out at the base of the depositional slope. The crest of the structure lies at 3,050 feet with a maximum closing contour of 3,400 feet. The API is estimated to range between 24° and 31° with GOR’s of 200-300 scf/stb. The licence was awarded on 1 October 2018 in the 30th Seaward Licensing Round. Interest in P2363 is held solely by Talon Petroleum Ltd (100% + operator). For further information please contact: Matt Worner 0061 429 522 924 [email protected]

(Central Graben Province) P2392 op. by TALON (100%), Talon Petroleum is searching for farm-in partners to fund a well to drill the Rocket prospect in licence P2392 (blocks 28/8b & 28/9b) in return for significant equity. The prospect is located in the Central Graben near the Catcher Area where Palaeocene aged Cromarty Sandstone reservoirs are trapped stratigraphically to form the AVO anomaly supported Rocket prospect. Encounter estimate Rocket to hold most likely STOIIP of 68 MMbo with an upside of 150 MMbo. The well cost is estimated at GBP 7 million.

Finder Exploration Pty Ltd is looking to potentially farm down its remaining interest in EP 483 and TP/25 permits, located in the Barrow Sub-basin. On 5 September 2018 Sapura Energy Bhd reported that it had signed a farm-in agreement with Finder to acquire 70% interest and operatorship in EP 483, TP/25, AC/P61 and WA-412-P. Finder will retain 30% working interest. Finder is also considering offering a potential farminee access to the remainder of its Australian portfolio. Finder has conducted data gathering and reviews on the acreage, but is looking to discuss a potential deal for interest in the permits with any interested parties. The permits will be considered as one in any potential deal with the split representing a transition from coastal, state waters of Western Australia (within 3 nm of land) to territorial waters (within 12 nm of land/islands - the Serrurier and Bessieres islands). Finder will be potentially offering material equity of a negotiable value, as well as operatorship, in return for funding of part of a work programme. In October 2015 Finder received approval to alter the work commitments in both permits. In EP 483 the commitment to drill the first exploration well in the fourth term was replaced by 3D seismic processing of 140 sq km of data. Finder will delay the exploration well until the sixth term in 2018/19. In TP/25, Finder altered the commitments in terms four, five and six, which effectively delays the first exploration well from term four to term six. Finder will instead conduct seismic processing of 140 sq km 3D seismic data at a cost of AUD 200,000 in term four. Environmental studies have been added to the fifth term at a cost of AUD 50,000.  Subsequently, in February 2018, an extension to term five and six was granted, giving Finder an additional 12 months to conduct the required work within these terms. This has resulted in the first wells being required between January 2019 and January 2020 in both permits. Finder has highlighted the Eagle Prospect for potential drilling, which lies in the centre of TP/25. The prospect is located in shallow water within the Mungaroo Formation at around 2,500 m below surface. Interpretation of the Numbat 3D seismic reveals a trap size of around 33 sq km within which, Finder reports the potential for mean gas-in-place of 2 Tcf. To date, around 4,000 km of 2D seismic processing has been completed with the interpretation underway. Deeper new potential play levels have been identified within the permits from the previously acquired 2D seismic data sets. Finder will be processing the Numbat MC3D data which was acquired between 13 May and 3 June 2015 by Searcher Seismic. EP 483 and TP/25 are surrounded by oil and gas discoveries, including the Tubridgi, Roller, Skate fields and Coaster discovery to the south east of EP 483 and the Corowa discovery to the north-west of TP/25. Finder reports that the permits are prospective for structural oil plays, with several leads outlined. A number of possible commercial development options are available in the case of a discovery which could provide fast commercialization of hydrocarbons located. EP 483 and TP/25 cover a combined area of 1,076 sq km. Once the farm-down to Sapura Energy is complete, Finder will hold 30% interest through its subsidiary company Finder No 3 Pty Ltd. Companies interested in pursuing this opportunity should contact: Shane Westlake, CEO Finder Exploration Pty Ltd, 9 Richardson Street, West Perth, WA 6005. Tel: +61 8 9327 0128 Email: [email protected]

Finder Exploration Pty Ltd is looking to potentially farm down its remaining interest in EP 483 and TP/25 permits, located in the Barrow Sub-basin.

It was reported on 4 May 2020 that Neuquen provincial company, Gas y Petroleo del Neuquen, divested its 10% interest in the 97 sq km Aguada Federal license, Neuquen Basin. The company also resigned its mining rights in the contract expiring in 2033. It is assumed that partners Wintershall DEA and ConocoPhilips will now hold 50% each in the license. Wintershall DEA will remain as operator. The provincial government has approved the operation. The deal was completed for US$ 17.6 million but GyP cashed only US$ 5 millions as it owed investments to partners for US$ 12.6 million.In late November 2019, ConocoPhilips confirmed the closing of the farm-in by the company in the Aguada Federal and Bandurria Norte licenses. Both licenses were already operated by the German company Wintershall Dea. ConocoPhillips acquired 45% interest in the Aguada Federal license. Wintershall would hold 45% and provincial company Gas y Petroleo del Neuquen the remaining 10% WI. ConocoPhillips would hold 50% share in the 107 sq km Bandurria Norte Block and Wintershall Dea will retain the remaining 50% interest. ConocoPhillips invested US$ 300 million in this transaction along which also includes acquisition in the US Lower 48 areas. In March 2019, Wintershall announced plans to invest US$ 600 million over three years in its Vaca Muerta Shale projects and others in the Neuquen Basin. About US$ 200 million will be invested each year through 2021 in Vaca Muerta pilot programs with an eye to moving into a massive development stage, including Aguada Federal and Bandurria Norte. Aguada Federal was created by the subdivision of the original Aguada del Chanar license, previously operated by state-owned IEASA (former Enarsa). The company hooked to production the Aguada Federal 4(h) horizontal exploration well targeting the Vaca Muerta Shale after 118 bo/d and some gas were tested in August 2018. In November 2018, official reports from the Energy Secretary showed 38 bo/d and some gas produced from the Vaca Muerta with the La Caverna x-11(h) horizontal exploration well on Bandurria Norte. Wintershall in 2016 signed an agreement to increase its stake from 50% to 90% on this block. The company farmed-in with Gas y Petroleo del Neuquen in 2014.<P /><P />

Gas y Petroleo del Neuquen, divested its 10% interest in the 97 sq km Aguada Federal license, Neuquen Basin.

Beach Energy Ltd spudded the Bauer North West 1 vertical oil appraisal well in PRL 153, located in the Cooper-Eromanga Basin, on 1 October 2018.  The well was drilled by the “Saxon 183” land rig.  On 7 October 2018 the well was suspended as an oil well after reaching a total depth of 1,775 m. The well was appraising the Bauer field, which was discovered in August 2011 and has been producing since May 2012.  It was the first of one of several appraisal wells planned to be drilled at the field.  Bauer North West 1 was the 12th appraisal well to be drilled at the field and the first since a horizontal well was drilled in mid-2017. PRL 153, which covers an area of 93 sq km, was awarded on 16 December 2014.  Beach Energy Ltd holds 100% interest and operatorship, with 50% held through wholly owned subsidiary Great Artesian Oil Pty Ltd.

Beach Energy Ltd spudded the Bauer North West 1 vertical oil appraisal well in PRL 153, located in the Cooper-Eromanga Basin, on 1 October 2018. The well was drilled by the “Saxon 183” land rig. On 7 October 2018 the well was suspended as an oil well after reaching a total depth of 1,775 m.

Central Sichuan Basin, TD 5,086m, tested 11 MMcfg/d of gas from the Permian Maokou 1 fm in late Jul ’19. A month earlier 3 MMcfg/d had also been tested from the Maokou 2&3.

Tongtan 1 (PetroChina 100%) in Liangxian-Hechuan block, flow tested at a maximum rate of 10,95 MMcfg/d, following fracture stimulation, was targeting the primary objectives of the Cambrian Longwangmiao and Maokou Fm. and secondary objectives of the Xixiangchi and Xixia Fm. TD= 5086m.

Ardent Oil is looking to farm-out part of its interest in licence 11/16 (blocks 5604/27c, 5604/28a, 5604/31b and 5604/32) containing the Jarnsaxa prospect. Mean recoverable prospective resources are estimated at 130 MMbo. The licence was awarded in the 7th Danish Licensing Round in April 2016. The licence is for a six-year term split into four phases. Phase 1 (2016-2018) requires data reprocessing and technical studies to be completed followed by a drill or drop decision. Phase 2 (2019) involves drilling one exploration well to evaluate the Pre-Cambrian basement with phase 3 (2020-2021) committing to drill a second exploration well or to relinquish the licence. Phase 4 (2022) will require the second exploration well to be drilled. The data used to define Jarnsaxa consists of the PGS Broadband Geostreamer (323 km sq), Danish Megasurvey (11,180 km sq) and legacy 2D data. Well studies included relevant source rock penetrations and offshore Paleozoic penetrations from nearby wells. The Jarnsaxa structure is a thrust-fault bounded anticline deformed by later faulting episodes. Pre-Cambrian fractured basement form the reservoir objective. The basement was subject to multiple tectonic phases of contraction, strike-slip and extension. The basement would have likely been exposed subaerially and any leach zone at the basement unconformity would enhance fractured reservoir effectiveness. Late Jurassic Kimmeridge Clay equivalent source rocks in the Tail End Graben charge nearby producing fields and could source Jarnsaxa. The Stork-1 well penetrated the source rock ~5 km from the acreage and is thought to be stratigraphically placed against the fault systems bounding Jarnsaxa. Carboniferous strata from a deep Paleozoic sediment filled basin to the south could also charge the prospect. Seals from overlying Paleozoic sediment was penetrated by offset wells and is interpreted to be tight clastic and volcaniclastic sediment. Further seal potential in the typically tight Late Cretaceous pelagic chalk units over lie the Permian clastics. The depth to the crest of the structure is 2,575 m subsea. The main risks consist of fractured basement reservoir and seal effectiveness. Interest in 11/16 is held by Ardent Oil (Denmark) SA (80% + operator) and Danish North Sea Fund (20%). For further information please contact: Peter Browning-Stamp Email: [email protected]

Denmark, 11/16

The NPD confirmed on 9 May 2018 (effective from 30 April 2018) that Lundin has completed its deal to acquire Statoil’s 20% interest in PL 860. Lundin reported on 1 February 2018 that it had agreed a deal with Fortis to acquire the latter’s 10% interests in PL 539 and PL 860 and its 30% interests in PL 820 S and PL 825. This deal was reported as complete by the NPD on 20 February 2018 (effective from 15 February 2018). Lundin entered PL 539 and PL 860 in late 2017 by acquiring 10% interests from Fortis. PL 539 covers part of block 3/7 to the west of Trym and contains the 2015 Myrhauk prospect dry hole 3/7-10 S. PL 820 S lies between Jotun and Balder, covering parts of blocks 25/7 and 25/8 (below Base Paleocene) and PL 825 lies between Oseberg, Veslefrikk and Huldra covering parts of blocks 30/3 and 30/6. PL 860 covers parts of blocks 2/6, 2/9 and 3/4 to the east of Ekofisk, northeast of Valhall and the northwest of Trym and contains the 1997 oil discovery made by 2/6-5. Operator MOL is intending to drill a well on the Oppdal / Driva prospects on the Mandal High in PL 860 in Q3 2018. Oppdal is mapped to extend south into PL 539 and potential reserves for both prospects are 434 MMboe. The Myrhauk well was drilled by Premier, targeting the Upper Jurassic Ula Formation and the Middle Jurassic Bryne Formation in a three-way dip closure with up-dip pinchout. Prior to drilling, Premier put potential reserves at 10-135 MMboe with Top Reservoir expected at 3,346 m TVD. However, no Ula Formation was present and the 100 m thick Bryne Formation had 45 m of sands but contained no hydrocarbons. 2/6-5 was drilled by Saga on a structural closure mapped at Top Shetland Group on the northern part of the Mandal High. The well proved oil in a very tight Upper Cretaceous Tor Formation reservoir and also exhibited shows in the Ekofisk Formation and in Basement. Two intervals in the Tor Formation were perforated and flowed after acid stimulation, although only water with 3% oil was produced. Test permeability was just 0.4 mD.   Following the completion of both deals interest in PL 539 is held by MOL Norge AS (80% + operator) and Lundin Norway AS (20%), interest in PL 820 S is held by MOL Norge AS (40% + operator), Lundin Norway AS (30%) and Wintershall Norge AS (30%), interest in PL 825 is held by Faroe Petroleum Norge AS (40% + operator), Lundin Norway AS (30%) and Spirit Energy Norge AS (30%) and interest in PL 860 is divided between MOL Norge AS (40% + operator), Lundin Norway AS (40%) and Petoro AS (20%).

Norway (Cod Terrace (Central Graben)) Ula

Midas block, Mid Mag, TD 3,584m, tested 50 b/d of 22 API oil from the target Lisama sands over a 30-day period between Mar-Apr ’18.

Colombia (Middle Magdalena B.) Lisama

On 20 May 2020 NEO Energy, backed by private equity firm – HitecVision, announced that due to the recent market volatility it and Total have renegotiated the financial terms of a deal to respond to the current industry environment. Previous deal partner Petrogas, from the deal announced back in July 2019, is no longer part of the transaction. Through the deal NEO will acquire interest in a portfolio of assets across four producing areas in the UK North Sea which had an average production of 23,000 boe/d. The acquired assets add approx. 51 MMboe to NEO Energy with potential development upside on a number of projects. It is expected that 80 employees and contractors will move over to NEO and its expected that the deal will complete in Q3 2020. The original deal, announced on 10 July 2019, saw Petrogas NEO UK Ltd agree to acquire a package of assets for a consideration of USD 635 million. A number of the assets involved in the acquisition were acquired by Total through the USD 7.45 billion acquisition of Maersk made in March 2018. Total stated the acquisition was in-line with its portfolio management strategy, aiming to lower its break-even point through optimizing capital allocation and divesting in high technical cost assets. Total’s primary objective is to maintain the organic break-even before dividend below USD 30/b. Assets acquired Field Interest sold Operator Dumbarton 100% TOTAL Balloch 100% Lochranza 100% Drumtochty 100% Flyndre 65.94% Affleck 66.67% Cawdor 60.60% Golden Eagle 31.56% CNOOC Scott 5.16% Telford 2.36%

HitecVision-owned NEO Energy has agreed to purchase 10 producing North Sea fields from Total, after previous joint venture (JV) partner Petrogas withdrew from the proposed deal. HitecVision announced on 20 May 2020 that it has renegotiated the transaction terms to reflect current market conditions.

Shrek partner Lime Petroleum's parent company Rex International Holding published an independent QPR for the discovery on 25 March 2020. The report puts the range of recoverable resources at between 10-22 MMbo plus 25-50 Bcfg. Shrek was discovered in 2019 by PGNiG's first Norwegian operated well 6507/5-9 S. In February 2020 PGNiG and Aker BP agreed a deal whereby the latter will take over operatorship of PL 838 with a view to bringing Shrek onstream as a tie-back to its Skarv field (although PGNiG will regain operatorship once production starts). Shrek is a rotated fault block in the lower part of the Ravfallet Fault Complex, located updip and along the spill route of Skarv and Idun. It has four reservoirs – the Middle Jurassic Garn, Not and Ile formations and the Lower Jurassic Tilje Formation. Garn – up to 33% porosity, net:gross 0.89, extremely good reservoir Not – up to 23% porosity, net:gross 0.5, usually shale but reservoir in this location Ile – up to 29% porosity, net:gross 0.92, heterogeneous reservoir Tilje – up to 29% porosity, net:gross 0.8, heterogeneous reservoir An oil and gas column totalling 85 m was present in 6507/5-9 S, with 60 m of sandstone, with the GOC at 2,034 m subsea and the OWC at 2,074 m subsea. Appraisal sidetrack 6507/5-9 A confirmed the same reservoir (a 65 m section with 45 m of sandstone) and the same contacts. Estimated recoverable resources given at the time of discovery were 19-38 MMboe. Upon completion of the deal, interest in PL 838 will be divided as follows: Aker BP ASA (35% + operator), PGNiG Upstream Norway AS (35%) and Lime Petroleum AS (30%).

Shrek partner Lime Petroleum's parent company Rex International Holding published an independent QPR for the discovery on 25 March 2020. The report puts the range of recoverable resources at between 10-22 MMbo plus 25-50 Bcfg. Shrek was discovered in 2019 by PGNiG's first Norwegian operated well 6507/5-9 S. In February 2020 PGNiG and Aker BP agreed a deal whereby the latter will take over operatorship of PL 838

Summit Petroleum is offering the opportunity for interested partners to farm-in to licence P2382 (block 22/14c) containing the drill ready K2 prospect. In July 2020 the opportunity was still available. A site survey was carried out over the prospect in June 2019 and a well will be drilled when a partner in the licence is secured. The licence had a drill or drop commitment before October 2022 but in early-July 2020 it was believed that Summit had secured an 18 month extension to the licence term and the drilling commitment (before April 2024). In June 2020 Summit acquired 25% interest in the licence from partner Ping Petroleum UK, the deal saw Summit become the sole holder of the licence. The K2 prospect lies immediately southwest of the Everest gas field and northeast of Huntington and is a four-way dip closure. The prospect is thought to be separated from Everest by a saddle with both K2 and Everest having similar AVO responses which aren't seen on the saddle. The primary reservoir is the Forties Sandstone reservoir with the K2 prospect thought to hold 29 MMboe (base case resources). There is a deeper Mey Sandstone anomaly which could contain 15 MMboe recoverable resources. Other prospects exist in the block – one is Rustler and the other Rattler which exhibit DHI's and could add further resources of 58 MMboe at a later date. Planned well costs are estimated at GBP 12.8 million (dry hole) with any development having lots of options including tie-backs to Everest, Huntington, Arran, Nelson and Forties. Summit is offering a minimum of 25% interest and maximum of 40% interest and is open to negotiation. Interest in the licence is held by Summit Exploration and Production Limited (100% + operator).

United Kingdom (Central Graben Province) P2382 op. by SUMITOMO (75%), PING PT (25%). Summit Petroleum is offering the opportunity for interested partners to farm-in to licence P2382 (block 22/14c) containing the drill ready K2 prospect.

Between 1 and 10 July 2019 the NPD reported that two deals had been completed in PL 889. Firstly, DNO withdrew transferring its 20% interest to operator Neptune. Then, Concedo also left the licence and split its 40% interest equally between Equinor and Wellesley. Both transfers are effective from 28 June 2019. PL 889 covers 142 sq km over parts of blocks 6507/8 and 6507/9 to the east of Heidrun and was awarded in APA 2016. Equinor is progressing with its Heidrun Subsea Extension Phase II project which will increase production from Heidrun North Flank and tap into resources from the 2001 Alpha Horst discovery. Plans call for the installation of two new four-slot subsea templates with a total of five new wells to be drilled initially. Three injectors will be drilled on the Heidrun North Template G and will provide additional pressure support to the Heidrun North Flank. Two producers will be drilled on the Heidrun North Template H, with one of the wells targeting Alpha Horst. A new 5.5 km integrated umbilical will be installed connecting the Heidrun TLP platform to the new Template G providing power, hydraulic control and chemicals for injection. In addition, a new 2 km power umbilical will be installed between the two new templates. The well stream will be routed from the new Template H to the existing Template E. The project will aim to recover 21 MMboe with Alpha Horst accounting for around 20% of these volumes. Equinor plans to make a financial investment decision (FID) by the end of 2019 with total investments expected to be around USD 350 million. Drilling operations are due to begin in 2022 with the project expected onstream in Q4 2022. The adjacent Carmen gas discovery will also be phased into Heidrun, via the template H, once sufficient capacity becomes available. The development of Carmen will be a separate project,t with Equinor working to select a development concept by mid-2019. Following completion of the deal, interest in PL 889 is held by Neptune Energy Norge AS (60% + operator), Equinor Energy AS (20%) and Wellesley Petroleum AS (20%).

Two deals had been completed in PL 889 (142km²). Firstly, DNO withdrew transferring its 20% interest to operator Neptune. Then, Concedo also left the licence and split its 40% interest equally between Equinor and Wellesley.

DEA Deutsche Erdöl has taken operatorship and 50% of the 591-sq km CNH-A4-Ogarrio/2017 block, auctioned in a farm-out round on 4 Oct ’17. The 591-sq km Sureste Basin onshore block was taken on after signing the relevant agreement with Pemex and the CNH. Plans include a workover campaign and devt drilling as of early 2019.

Mexico (Campeche Deep Sea B.) ? op. by ENI SPA (45.0%, CAIRN EN 30.0%, CITLA 25.0%) in 7 block

Cyclone handed its remaining 33.72% in the Jingemia oilfield in L14 to RCMA Australia on 10 Sep ’18.  L14 covers 45 sq km in the Perth Basin, RCMA now 93.72% (op), partner Norwest Energy

Australia (Dongara Terrace (Perth B.)) Jingemia

Subject to authority approval, Eni (op) and partner Vitol have secured rights to WB03 (block 3), medium-deep waters of the Tano Basin. The JV also includes GNPC and a yet-to-be-disclosed local company.  WB03 lies ab. 50km SE of the John Agyekum Kufuor (JAK) FPSO serving the Sankofa field and is adjacent east to UB Resources’ Offshore Cape Three Points South block. It is also assumed to contain the Lynx-1 o&g discovery (Lukoil, 2014).

Eni (op) Vitol, GNPC and a yet-to-be-disclosed local company have secured rights to WB03 (block 3), medium-deep waters. WB03 lies ab. 50km SE of the John Agyekum Kufuor (JAK) FPSO serving the Sankofa field and is adjacent east to UB Resources’ Offshore Cape Three Points South block. It is also assumed to contain the Lynx-1 o&g discovery (Lukoil, 2014).

According to reports in late-November 2017, the government of Neuquen Province has officially awarded the Parva Negra Oeste concession to a local subsidiary of US-based Retamco Operating Inc, Retama Argentina, following the company’s winning bid for the block during Neuquen V Bid Round in September 2017. The 127.9 sq km Parva Negra Oeste block is situated in the Chihuidos High area of Neuquen Basin, adjacent to the Los Toldos I Sur block where ExxonMobil recently received approval from the Neuquen Province government for a 35 years unconventional license targeting the Vaca Muerta Formation shale. Retama’s program in the block consists of work and investments in the amount of over USD 76 million. The first four-year exploration period will be followed by an option to renew for a second four year phase afterwards. Pending positive results, 35 years of production period will follow with an additional option for a ten year extension. The company operates the block with 90% interest, as provincial company GyP Neuquen holds the remaining 10% stake, although Retama is expected to carry all of the cost during the exploration period. Each party will pay their participating interest share for the development and production phase. However, GyP Neuquen will also have the option of converting said 10% interest into a 2.5% additional royalty from gross production instead.

Argentina (Neuquen B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Parva Negra Oeste op. by RETAMCO (90.0%, NEUQUEN 10.0%) to be check.

As of 8 January 2018 MGM Energy, a wholly owned subsidiary of Paramount Resources, and 50/50 partner Shell Canada was officially awarded on 19 September 2016 a Significant Discovery License SDL 151 over the East Mackay shale oil discovery drilled by the partnership in February 2013 in the Mackenzie Plain Basin. MGM and Shell Canada will each hold a 50% working interest in the new license. The award was back dated for administrative purposes following the relinquishment of EL 474. (see related article) The 427.6 sq km SDL was carved out of the MGM operated exploration license EL 474 and is located 11 km southwest of the town of Fort Norman and 78 km southeast of the Norman Wells Field. Following the issuance of SDL 151 EL 474 was relinquished in its entirety. Three additional SDL’s were also issued in February 2016 over the discovery. Significant Discovery License in the northern territories do not carry work commitments and are issued with no expiration due to the remoteness of the area and the lack of infrastructure to bring product to market. These terms were put in place when exploration activity was just getting underway following the discovery of Prudhoe Bay Field in Alaska to encourage exploration in the remote territories of northern Canada. Several provinces in eastern Canada have revised the SDL terms to include a rental scheme which begins at issue but it remains to be seen if that will occur in the northern provinces.

Paramount Resources, and 50/50 partner Shell was awarded Licenses SDL 151 & 152, located in the Northwest Territories.

A new acreage release has been launched covering the Carnarvon + Perth basins. 79 blocks on/offshore the N. Carnarvon Basin are offered under Area L20-1, 33 tracts under Area L20-2 in the Southern Carnarvon basin, 2 blocks (6528 + 6600) under Area L20-3 in the Perth Basin, and 31 permits under Area L20-4 in the Perth Basin. Applications are invited by 19 October. Release and maps here.

(Carnarvon & Perth b.), a new acreage release has been launched: 79 blocks on/offshore the N. Carnarvon Basin are offered under Area L20-1, 33 tracts under Area L20-2 in the Southern Carnarvon basin, 2 blocks (6528 + 6600) under Area L20-3 in the Perth Basin, and 31 permits under Area L20-4 in the Perth Basin.

The BOEM has issued a final notice for Lease Sale 252, to take place on 20 Mar ’19. It will offer all available acreage in federal waters offshore Texas, Louisiana, Mississippi, Alabama and Florida, in total 14,696 blocks covering 315,655 sq km in WD 3-3,400m. More from GEPS.

The BOEM has issued a final notice for Lease Sale 252, to take place on 20 Mar ’19. It will offer all available acreage in federal waters offshore Texas, Louisiana, Mississippi, Alabama and Florida, in total 14,696 blocks covering 315,655 sq km in WD 3-3,400m

On 27 March 2018, the consortium of Shell and PEMEX, was granted a preliminary award for the 798 sq km Area 35, G-CS-04 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 consortium bid a state take of 34.86% over the minimum of 22.5% for the Area 35 block and a work units factor of 0 equivalent to no wells.  The provisional consortium working interest breakdown is estimated to be Shell, operator with 50% working interest, and PEMEX with 50% working interest. There was one other bid for the block.  The second highest bidder was the consortium of Total, BP, and Pan American who bid 30.49% state take, and 0 additional work units factor.  

the consortium of Shell and PEMEX, was granted a preliminary award for the 798 sq km Area 35, G-CS-04 block from the CNH-RO3-LO1/2017 Bid Round.

Roc has agreed to purchase a 50% interest in Ungani oilfield prod licences L20 + L21 for AUD 64 cash. Another agreement has been made for Buru’s surrounding explo licences, in which Roc will also acquire 50% for AUD 20 MM. Buru will retain operatorship.

Roc has agreed to purchase a 50% interest in Ungani oilfield prod licences L20 + L21 for AUD 64 cash. Another agreement has been made for Buru’s surrounding explo licences, in which Roc will also acquire 50% for AUD 20 MM. Buru will retain operatorship.

Source Energy has farmed-in to PL 878 with effect from 20 December 2019. The company has taken a 10% interest from operator Equinor (reported by the NPD on 10 January 2020). The licence covers a 361 sq km area over parts of blocks 30/2 and 30/3 north of Oseberg. Equinor will drill a well (30/2-5) on the Atlantis prospect to the north of the abandoned Huldra field (which also lies within PL 878). The shallow gas pilot hole for the well is expected in Q1 2020. This farm-in follows a similar one in late November 2019 when Wellesley acquired 20% in PL 878, also from Equinor. Shell was a former partner in PL 878 and exited the licence in February 2019, leaving Equinor with 100% interest. Huldra was discovered in 1982 by well 30/2-1 and it came onstream in November 2001. It is a rotated fault block structure with a Middle Jurassic Brent Group reservoir lying between 3,500-3,900 m. The reservoir was initially HPHT but compression was required to aid production from 2007. From the Huldra platform wet gas was transported to Heimdal for further processing and export and condensate was exported through Veslefrikk. Production ceased in 2014. Interest in PL 878 is divided between Equinor Energy AS (70% + operator), Wellesley Petroleum AS (20%) and Source Energy AS (10%).

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

Green Canyon block 21, WD ~400m, 62m MD / 36m VD oil pay in the target DTR10 sand, 31 API oil, devt considered via Talos’ Green Canyon 18 platform 16km away, 1st oil in 2020.  Sidertrack now planned, KOP 2,865m, re-penetrate the DTR-10 sand + attempt to reach the deeper MP target, Noble Don Taylor DS. Talos (op), partners EnVen + Otto (farmin well for 16.67% through paying for 22.22% of ops).

Bulkleit appr Green Canyon block 21, WD ~400m, 62m MD / 36m VD oil pay in the target DTR10 sand, 31 API oil, devt considered via Talos’ Green Canyon 18 platform 16km away, 1st oil in 2020. Sidertrack now planned, KOP 2,865m, re-penetrate the DTR-10 sand + attempt to reach the deeper MP target, Noble Don Taylor DS. Talos (op), partners EnVen + Otto (farmin well for 16.67% through paying for 22.22% of ops).

Mari D&PL, Middle Indus Basin onshore, TD 2,995m in early Nov ‘17, gas encountered and since tested. Target assumed Lower Goru, co. rig I.

Pakistan (Indus B.) Azadi 1 op. by MARI PT (100.0%) in Mari D&PL block

On 17 July 2018, it was announced that Turkiye Petrolleri A.O. (TPAO) had been awarded two exploration licences, E19-D3,D4 and F18-B2 on 9 July 2018. The licences have been granted a five year term with an expiry date of 9 July 2023. The licences cover a total areas of 273 sq km and 108 sq km respectively in the Thrace Basin. TPAO will be 100% owner and operator of each licence.

TPAO (100%) was awarded exploration licences, E19-D3,D4 + F18-B2.

6/16 licence / block 5603/31a, 7-week ops terminated 12 Nov '19, w.o. results, Maersk Resilient JU. Hess (op), partner Danish North Sea Fund.

Jill 1 nfw. Hess ((80% + Op) and Nordsofonden (20%) had concluded drilling at on licence 6/16 by 12 November 2019, with results yet to be reported.

EDF, through its subsidiary Edison International, has P&A dry its North West Gindi 1X NFW. The well is located in the SW of the under-explored North West Gindi PSC, located in the Nile Delta Basin. It was drilled during H1 2017 and reached a TD of 4,221m (TVD 4,070m) in the Jurassic Khatatba Formation. Operations were carried out using the Egyptian Drilling Company #9 rig. North West Gindi 1X was targeting multiple objectives in the Cretaceous and Jurassic and is the first well drilled under the concession agreement.The 1,955 sq km onshore block was awarded to the company on 13 January 2015, following the EGPC International 2013 Bid Round. Just four wells have been drilled on the block, with the previous being Dalia 1 in 2009 (Sipetrol, TD 4,438m, P&A). Edison operates the concession with 100% equity.<P /><P />

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NZP&M has launched its (delayed) 2018 block offer, now restricted to the onshore Taranaki where 2,188 sq km is available. The delay was owed to consultations and the Govt act that no offshore permits would any longer be granted. The tender closes on 28 Aug ‘19. GEPS map below, open acreage in blue:

NZP&M has launched its (delayed) 2018 block offer, now restricted to the onshore Taranaki where 2,188 sq km is available. The delay was owed to consultations and the Govt act that no offshore permits would any longer be granted.

Enauta has reportedly put the farm-out process of 2 blocks in the Para Maranhão Basin on hold. The decision stems from uncertainties regarding the date of the drilling licence preventing negotiations progress. But it is also mooted that recent discoveries in Guyana and Suriname have boosted the value of regional acreage. Involved are wholly-owned deepwater PAMA-M-265 + 337 blocks.

Enauta has reportedly put the farm-out process of 2 blocks in the Para Maranhão Basin on hold. The decision stems from uncertainties regarding the date of the drilling licence preventing negotiations progress. But it is also mooted that recent discoveries in Guyana and Suriname have boosted the value of regional acreage. Involved are wholly-owned deepwater PAMA-M-265 + 337 blocks.

Croatia has launched the Second Onshore Round on 31 October 2018, with seven blocks offered: Drava-03 (DR-03), Sava-06 (SA-06), Sava-07 (SA-07), Sava-11 (SA-11), Sava-12 (SA-12), Sjeverozapadna Hrvatska-01 (SZH-01) and Sjeverozapadna Hrvatska-05 (SZH-05), all located in the N & NW of the country. Applications close on 30 June 2019 and successful bidders will be awarded a Production Sharing Agreement (PSA) of up to 30 years, with an initial five year exploration period split into two phases (3 + 2 years), and an option to extend each exploration phase by six-months. The blocks will fall under the 2018 Hydrocarbons Law which passed during May 2018 which maintained the existing fiscal regime. The updated law also allows for open door applications to be submitted out of round. During 2014, Spectrum reprocessed 13,100km of historical 2D seismic shot across the onshore area between 1972-1997. Details at https://www.azu.hr

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SK-408, off Central Luconia Province, Sarawak, P+A results n/a mid-Dec ’15. Target Middle Miocene Cycle IV / V carbs, 1st of 3 wells planned, Hakuryu 11 JU. Sapura Energy (op), partners Shell + Petronas.

Malaysia (Central Luconia Province) Remujung 1 op. by SAPURA EN (40.0%, SHELL 30.0%, PETRONAS 30.0%) in SK-408 block

On 15 April 2019, Energean Oil & Gas PLC announced that it had made a “significant” gas discovery at the Karish North 1 exploration well in the Karish (I/7) lease. The well has been drilled to a TD of 4,880 m and encountered high quality reservoir in the B and C sands with a gross hydrocarbon column of up to 249 m. Energean has made initial gas in place estimates of between 1 Bcf and 1.5 Bcf. The well was subsequently deepened to evaluate the D4 horizon and is believed to have completed operations in early May 2019. Karish North 1 was spudded on 15 March 2019 and had expected gross drilling costs of USD 25 million. The well was drilled by the “Stena DrillMAX” drillship which will now batch drilling three development wells at the field. Energean also has the option to drill six additional wells under its contract with Stena. Once completed, Karish North 1 will be tied back to the Energean FPSO at the Karish field. An Independent Competent Persons Report submitted by Netherland Sewell & Associates, Inc. in January 2018 estimated gross recoverable unrisked prospective resources of 1.3 Tcfg (33.5 Bcm) and 16 MMb light oil for the Karish North prospect. On 22 March 2018, Energean’s Board of Directors approved the Final Investment Decision to proceed with the Karish and Tanin field development project, located in the offshore Tanin (I/16) and Karish (I/17) leases on 22 March 2018. On 29 January 2018, Energean announced that it had signed a drilling contract with Stena Drilling to undertake a development drilling programme at the Karish field. The main development of Karish will entail the drilling of three development wells and installation of a Floating Production, Storage and Offloading (FPSO) unit. Total estimated capex for development is USD 1.3 to 1.5 billion. First gas from the field is expected in 2021. Energean completed the acquisition of the Tanin (I/16) and Karish (I/17) leases on 22 December 2016. Energean, through subsidiary Energean Israel, is now 100% owner and operator of both leases. Each of the Tanin (I/16) and Karish (I/17) leases covers an area of 250 sq km and is valid for an initial 30 year period from 11 August 2014 until 10 August 2044 with the potential for extension.

Karish North 1, (Energean 100%) near-field exploration well in Karish block in Mediterranean, currently at 4800m,“significant” gas discovery, high quality reservoir in the Miocene B + C sands, up to 249m gross hc column, 27m core recovered to surface, initial GIP estimate 1-1.5 Tcfg, further evaluation required to refine resource potential and determine the liquids content. The well will now be deepened to evaluate the D4 horizon. Karish North will be commercialised via a tie-back to the Energean Power FPSO, 5,4km away.

Further to DEA 22 Jul '20: Block 114, Song Hong Basin, WD 95m, TD 3,658m, significant hc find, 110m pay in several Miocene intv's, 2 mini DSTs run, est 7-9 Tcfg in place + 400-500 MMbc, well to be P&A'd. Target was Miocene Phu Chu sst, Borr Saga JU. Additional drilling + testing are planned at Ken Bau as well as wider basin drilling + seismic (Eni has adjacent block 116). Eni (op), partner Essar.

Vietnam (Song Hong B.) 114-KB 2X op. by ENI SPA (50%), ESSAR (50%) in Block 114, WD = 90 m

P2312 / blocks 3/16a + 17a, TD 1,830m, P&A'ing dry at TD 1,830m, Stena Don SS. Target Heimdal sst. Nautical (op), partners Suncor + DNO (farmin pending completion).

003/17a-03 (Chimera) nfw. (Nautical op. 45%, Suncor 40%, DNO 15%) in P2312 / blocks 3/16a + 17a, P&A, dry at TD=1830m. Target Heimdal sst.

2nd in 3-well campaign in R3/R4 PSC area, Agadem Basin in SE Niger, 24-day well to TMD 2,469m, 22m net light oil reservoir determined in the target Eocene Sokor Alternances (E1 & E2 reservoirs, good to excellent quality), suspending for future testing, GWDC rig 215 to Kunama-1 spudding later this month.

Niger (Termit Trough - Chad B.) Sokor

Wushi 23-5-3d (WS 23-5-3d) was suspended on or around 19 February 2020, having intersected oil in the target reservoir. The deviated oil appraisal well was spudded in late January 2020, using the “Kantan 2” jack-up. Wushi 23-5-3d was likely targeting the Weizhou and Liushagang formations with the objective of appraising the southerly extension of the Wushi 23-5 discovery. Wushi 23-5-3d is in the CNOOC operated Weizhou 12 Block in the offshore Beibuwan Basin.

Wushi 23-5-3d (WS 23-5-3d) was suspended on or around 19 February 2020, having intersected oil in the target reservoir. The deviated oil appraisal well was spudded in late January 2020, using the “Kantan 2” jack-up. Wushi 23-5-3d was likely targeting the Weizhou and Liushagang formations with the objective of appraising the southerly extension of the Wushi 23-5 discovery. Wushi 23-5-3d is in the CNOOC operated Weizhou 12 Block in the offshore Beibuwan Basin.

Alkane has acquired a 50% interest in PEDL 130 from Egdon Resources. PEDL 130, 45 sq km in Nottinghamshire, contains the Clipstone + Bilsthorpe Colliery CBM projects. Partnership now Egdon (op), Alkane.

United Kingdom (East Midlands Platform (Anglo-Dutch B.)) Bilsthorpe Colliery

Confirmation DEA 30 Jan ’19: Oman launched its 2019 round as planned on 17 February, closing 30 May ’19. Six blocks are up for grabs as EPSAs, namely onshore 58 (Qatbeet, 4,560 sq km in the South Oman Salt sub-basin + Ghudun-Khasfah High), block 70 (Mafraq, Ghaba Salt sub-basin), and new 73 + 74 (Ghudun-Khasfah High, South Oman Salt sub-basin), 75 + 76 (Ghudun-Khasfah High), carved out of block 6. Blocks 43B and 71 (Habhab field) are also available under direct negotiations.

Oman launched its 2019 round as planned on 17 February, closing 30 May ’19. Six blocks are up for grabs as EPSAs, namely onshore 58 (Qatbeet, 4,560 sq km in the South Oman Salt sub-basin + Ghudun-Khasfah High), block 70 (Mafraq, Ghaba Salt sub-basin), and new 73 + 74 (Ghudun-Khasfah High, South Oman Salt sub-basin), 75 + 76 (Ghudun-Khasfah High), carved out of block 6. Blocks 43B and 71 (Habhab field) are also available under direct negotiations.

According to BHP’s Operational Review for the year ended 30 June 2019, its Bele 1 New Field wildcat (NFW), Block 23 (a), was plugged and abandoned (P&A) with hydrocarbons encountered. This discovery alongside Hit-Hat-1, Block TTDAA-14 and Tuk-1 in the Block 23 (a) have “established additional volumes around the Bongos discovery” - evaluations are ongoing. On 17 April 2019 BHP reported in its Operations Review for the nine months ended 31 March 2019, that it had encountered hydrocarbons in the Bele 1 NFW which drilling was still in progress. The interest holders are the operator BHP with 70% and BP holds the remaining 30%. The well was spudded on 2 March 2019 in 2,102 m water depth using the Transocean Drillship Deepwater Invictus, which will be in location for 60-days. It reached total depth of 13,064 ft (3,982 m). According to local sources, BHP plans two-three wells appraisal program in its deep-water blocks: TTDAA 5, TTDAA 14, and 23 (a). Details have not been released. Preliminary estimates of the combined unrisked gas resource potential of the blocks TTDAA 5, TTDAA 6, TTDAA 28 and TTDAA 29 are in the range of 2.4-23.6 Tcf and the unrisked crude oil resources are in the range of 428-4,200 MMbo. Hi-Hat-1 NFW was spudded on 20 May 2019, in 1,782 m water depth and reach total depth (TD) of 12,480.31 ft (3,804 m).  The proposed total depth (PTD) was 3,688 m (12,100 ft) with the main objective in the Pliocene. This is likely to be the appraisal well for Bongos 2 NFW, located in the Trinidad Basin. The well which was plugged and abandoned (P&A), with three gas zones and at least one zone being gas/condensate was spud on 20 July 2018 in 1,910 water depth using the Transocean Drillship, Deepwater Invictus, and it reached total depth (TD) of 5,151 m in October 2018. It replaced Bongos 1 NFW which encountered mechanical problems. The rig was moved to well location on 18 July 2018, and it was expected to stay for approximately 90 days. The operator acquired in 2014 17,700 sq km 3D seismic over seven blocks, included the TTDAA 14. The interest holders are BHP with 70% and the remaining 30% with BP TT. Plans for the well were first reported in late February 2018. Background Information The operator planned to drill two wells – Bele 1 and Tuk 1. Trinidad and Tobago Marine Advisory Notice announced the arrival of the drillship in late February 2019 for the operator’s three wells program, including the Hi Hat-1 – likely to be the appraisal well for Bongos 2 NFW, TTDAA 14 Block. BHP drilled two wells in this block Burrokeet 1 and 2 As of mid-January 2017, due to mechanical problems BHP plugged and abandoned (P&A) the Burrokeet 1 NFW. The well was spudded on 5 August 2016, with a proposed total depth (PTD) of 8,534 m (28,000 ft) and it reached 3,337 m (10,948 ft). The main objective was in the Eocene, in a water depth of 1,923 m. BHP P&A its Burrokeet 2 NFW. The well reached a total depth (TD) of 7,347 m (24,105 ft) in mid-December 2016. It was spudded on 18 August 2016, in 1,923 m water depth. As of early May 2018, BHP was still interpreting the acquired 17,700 sq km of 3D seismic shot over seven blocks including the Block 23 (a). The acquisition conducted by PGS began in Mid-March 2014 and it is estimated that it was completed in mid-November 2014. On 17 April 2014, local sources confirmed that BP farmed out a majority interest to BHP Billiton in deep-water blocks TTDAA 14 and 23(a). BP on 25 July 2011 reported that it was awarded two deep-water exploration and production blocks in Trinidad and Tobago, doubling the company’s acreage holdings in the country. BP was awarded a 100% interest in the blocks 23 (a) and TTDAA 14, both of which are in deep-water frontier acreage of Trinidad’s eastern coast. The contracts were awarded as production sharing contracts. Block 23(a) is located about 300 km NE of BP’s Galeota Point operations base. The block covers 2,600 sq km in water depths averaging 2,000m.

Bele 1, Tuk 1 (hc disc) in Block 23 (a) targeting Pliocene reserves, TD=3982ms and 4511m respectively, WD around 2000m and Hi-Hat 1 (hc disc) was drilled in Block 14, also targeting Pliocene reserves, TD=3804m end WD=1782m. "These 3 discoveries in our Northern licences have established additional volumes around the Bongos disc. and evaluations are ongoing" operator said.

Range Resources reported on 30 April 2019 that the company is looking for a potential buyer to take over its interest in Perlak KSO, located onshore in the North Sumatra Basin. The decision to divest was made after considering the lack of continuous sustainable production from the Perlak oil field, after effort was made to carry out a workover programme. The joint venture commenced a well workover programme in the Perlak oil field by reactivating one well, POG-D, in early July 2018. The well was tested to produce 145 barrels of light and high-quality oil in a multiple-reservoir zone over a period of two weeks, with a total of 117 hours of intermittent pumping period. Further study was planned to be carried out to determine the stable pumping rate. The company then started its next operation at the second well, POG-E. The well encountered downhole obstruction and the process of removing the blockage was reported to be ongoing. In September 2018, Range reported that production from the two initial wells was below expectations, therefore the operator would continue with a reduced work programme until the end of the year. Workover operations continued with the reopening of two more wells, one in Q4 2018 and one in January 2019. However, the operator encountered difficulties due to poor conditions of the casings of the old wells and complexity of the wellheads. Other wells originally identified for this work program were Perlak 261, Perlak 258, Perlak 233, Perlak 224, Perlak 222, and Perlak 21. On 21 March 2018, the company reportedly received approval from Pertamina for the 2018 work programme, which is aimed at restoring production from the oil field. The plan included the reopening of seven to ten existing wells and workovers on two existing wells, all of which were previously on production. In addition, geological, geophysical and integrity studies were to be conducted. Range expected to recommence production from the field by mid-2018, targeting total production rates of approximately 200 bo/d from the workover programme. Any produced oil would have been trucked to a receiving point in Pangkalan Susu field, located approximately 160 km from the field, and sold to Pertamina. The total estimated expenditure for the 2018 programme was USD 6 million, exceeding the minimum expenditure of USD 0.55 million as initially agreed upon. The Perlak KSO was awarded by Pertamina to local joint venture PT Aceh Timur Kawai Energi in 2017. Joint venture partners are PT Aceh Timur Energi dan Mineral (PT ATEM), with 51% interest, and PT Lubuk Kawai Raya (PT Lukar), with 49%. PT Lukar is a 78%-owned subsidiary of PT Hengtai Weiye Oil and Gas. In October 2017, Range Resources completed the acquisition of 60% stakes in Hengtai, earning a 23% indirect interest in the Perlak KSO. PT ATEM is a business entity controlled by the East Aceh local government. Upon completion of a three-year work programme in September 2020, PT ATEM’s participation in the KSO will be reduced to 10% with Lukar’s interest increasing to 90%. This will result into Range increasing its indirect interest in the KSO to 42%. The Perlak field has produced approximately 50 MMbo and 64 Bcfg until the early 1940s. According to a third-party evaluation commissioned by Range Resources as of August 2017, the field holds remaining resources of approximately 13 MMbo and 47 Bcfg. Background Information The Perlak field was discovered by Royal Dutch around 1900. The field produced until the 1940’s when it was shut-in due to WWII. According to Range Resources, over 300 wells have been drilled in the field and approximately 50 MMbo have been produced, from reservoirs shallower than 1,000 m. Prior to Range’s entry, the field was operated by Pacific Oil and Gas under an earlier KSO agreement with Pertamina. The field was brought back on production in May 2011 from two wells producing light oil (53°API) at rates of 180 bo/d and 100 bo/d respectively. The Perlak KSO was terminated by Pertamina in April 2013 due to failure by the operator to meet the agreed obligations. Local media reports in early October 2016 indicated that PT Lubuk Kawai Raya and the East Aceh regional administration signed a Memorandum of Understanding for the rights to operate the Perlak field. The minimum work programme for the first three years of operations in the Perlak KSO calls for a total expenditure of USD 3.8 million. The first year programme (due for completion by September 2018) involves G&G and reservoir studies, well surveying and one well workover, for a total value of USD 0.55 million. The second year (by September 2019) includes 3D seismic data evaluation and three well workovers, for a total value of USD 1 million. The third year (by September 2020) includes G&G and reservoir studies, plus drilling one well, for a total value of USD 2.25 million.

Range Resources Ltd Perlak KSO - Planning to divest its 23% working interest

Neptune Energy Norge, operator of production licence PL 882, has completed the drilling of wildcat well 34/4-15 S and appraisal well 34/4-15 A. The wells were drilled about 10 kms northwest of the Snorre field and 160 kms west of Florø in the northern part of the North Sea. The primary exploration target for well 34/4-15 S was to prove petroleum in reservoir rocks from the Middle Jurassic Age (the Rannoch Formation). The secondary exploration target was to prove petroleum in reservoir rocks from the Late Jurassic Age (Intra Draupne Formation sandstone). An oil column of about 80 metres was encountered in the primary exploration target in the Rannoch Formation, 50 metres of which are sandstone with generally moderate reservoir quality. The oil/water contact was not encountered. A sandstone layer of a few metres was encountered in the secondary exploration target in the Intra Draupne Formation, with poor reservoir quality and traces of petroleum. The primary objective of well 34/4-15 A was to delineate the discovery in well 34/4-15 S in the Rannoch Formation. The secondary exploration objective was to prove petroleum in reservoir rocks from the Late Jurassic Age (Intra Draupne Formation sandstone). An oil column of about 80 metres was encountered in the primary exploration target in the Rannoch Formation, 17 metres of which are reservoir sandstone of generally poor reservoir quality. The oil/water contact has not yet been determined. An oil column of about 100 metres was encountered in the secondary exploration target in the Intra Draupne Formation sandstone, 55 metres of which are in sandstone of poor to moderate reservoir quality. Preliminary estimates place the size of the discovery in the Rannoch Formation between 5 and 14 million standard cubic metres (Sm3) of recoverable oil. Preliminary estimates place the size of the discovery in the Intra Draupne Formation sandstone between 1.6 and 5 million standard cubic metres (Sm3) of recoverable oil. The discovery will be considered for tie-in to nearby infrastructure. The wells were not formation-tested, but extensive data acquisition and sampling were carried out. These are the first and second exploration wells in production licence 882. Production licence 882 was awarded in APA 2016. Wells 34/4-15 S and 34/4-15 A were drilled to respective vertical depths of 3430 and 3573 metres below sea level and respective measured depths of 3571 and 3844 metres, below sea level. The wells were terminated in rocks from the Early Jurassic Age (the Drake Formation). Water depth at the site is 283 metres. The wells will now be permanently plugged and abandoned. The wells were drilled by the Deepsea Yantai drilling facility, which will now proceed to drill production wells in production licence 153 on the Gjøa field in the northeastern part of the North Sea, where Neptune Energy Norge AS is the operator. See also, Neptune Energy announcement: Neptune Energy confirms significant discovery at Dugong well Original article link Source: NPD

(Viking Graben Province), 34/4-15 S (Dugong) explo well, in PL 882, operated by Neptune (40%), CONCEDO (20%), IDEMITSU (20%), PETROLIA (20%). The volumes are estimated to be in the range of 40 – 120 million barrels of oil equivalent (boe). Previously, Neptune confirmed that hydrocarbons have been found in the reservoir which lies between 3,250 m and 3,400 m.

On 17 February 2018, Hungarian Horizon Energy Group (HHE) completed drilling wildcat Bürüs 2 in the Lakócsa concession in southwestern Hungary. The well encountered water-wet target horizon and was abandoned. HHE is the sole operator of the Lakócsa permit. Bürüs 2 was likely spudded in early February 2018. The 355 sq km Lakócsa block is located in the Baranya and Somogy political provinces, along the border with Croatia, within the Somogy-Drava Sub-basin, tectonic unit of the Pannonian Basin. The well had a planned final depth estimated at 1,800-2,000 m, targeting the Lower Pannonian and Miocene successions (details unavailable). Background Information The Lakócsa concession was granted to HHE by the Minister of National Development on 15 February 2016 (preliminary award was pronounced in late November 2015). The award followed the country’s 2015 bid round. The Lakócsa contract is valid for twenty years from the effective date, with possible one, 10-year extension. The latest activity in the tract dates back to December 2017, when HHE drilled and completed with oil wildcat Pettend Nyugat 2.

Burus 2(Aspect Energy 100%) in Lakocsa concession, P&A, encountered water wet sands in the Lower Pannonian and Miocene successions.

Canacol Energy announced on 19 December 2017 that it has signed an agreement with Tecpetrol Libertador and Setecpet E&P to sell its 25% interest in the mature fields Libertador and Atacapi for USD 36.4 million. The Libertador Field produced 4 MMbo during 2016 and 1.9  Bcfg in 2015, and the Atacapi Field produced 1.3 MMbo during 2016 and 0.666 Bcfg in 2015. The buyers are existing partners in the Pardaliservices SA Joint Venture with Canacol, Schlumberger with 20%, Tecpetrol with 40% and Setecpet with 15% interest. The Integrated Specific Services Contracts (Contrato de Servicios Especificos Integrados con Financiamiento) was awarded in January 2012. The consortium Pardaliservices SA (Tecpetrol, Schlumberger, Canacol, and Sertecpet), was awarded the Libertador - Atacapi Field. Petroecuador EP remained the exclusive owner and operator of the activities in the area, with the contractor performing services under this agreement. The contracts will be valid for 15 years. During this period, the contractor should incorporate new technology in the fields in order to optimize the primary production, such as conducting seismic reprocessing, updating of simulation reservoir studies, drilling and intervention of wells, and modernization of production facilities. As of 1 August 2017 a new contract rate was applied towards the agreement signed between Petroamazonas and the consortium Pardaliservices SA (Tecpetrol, Schlumberger, Canacol, and Sertecpet) for the Libertador – Atacapi Fields. The rate will drop from USD 38.54/b to USD 25.50/b until 2020, and the consortium has also pledge a new investment of USD 140 million. Pardaliservices SA planned to invest USD 384.5 million in the next five years, to recover and increase reserves in the mature fields – the contract’s main objective. It is estimated that the production will increase from 16,200 to 16,400 bo/d, with a total reserve recovered of 14.27 MMbo. The contractors will be paid a fee for services rendered, only if there is incremental production. Petroecuador EP remained the exclusive owner and operator of the activities in the area, with the contractor performing services under this agreement. The contract will be valid for 15 years. During this period, the contractors are expected to incorporate new technology in the Atacapi-Libertador fields, in order to increase production, using data from seismic reprocessing, updating of simulation reservoir studies, by drilling new wells plus remedial work on the existing wells, and modernization of production facilities.

Tecpetrol Libertador and Setecpet E&P has acquired 25% interest in the mature fields Libertador and Atacapi from Canacol Energy for US$36,4 MM.

Uzbekneftegaz reports a commercial gas-cond discovery at some 3,600m at a location designated Nizhny Surgil (‘Surgil’) in the Ustyurt Basin. Few details are available.

Uzbekneftegaz reports a commercial gas-cond discovery at some 3,600m at a location designated Nizhny Surgil (‘Surgil’) in the Ustyurt Basin. Few details are available.

In late Jul ’18, BP signed a USD 46 million E&P agreement for the Eastern Ramadan area in the Gulf of Suez, which the company appears to have won under the name Northeast Ramadan in the EGPC’s 2016 Round. A signature bonus of USD 4 million and 3 wells (first of which is rumoured for this year) were part of the deal.

In late Jul ’18, BP signed a USD 46 million E&P agreement for the Eastern Ramadan area in the Gulf of Suez, which the company appears to have won under the name Northeast Ramadan in the EGPC’s 2016 Round. A signature bonus of USD 4 million and 3 wells (first of which is rumoured for this year) were part of the deal.

On 28 March 2019, the Federal Agency for Subsoil Use held an auction for three blocks in Samara Oblast (Volga-Urals). The winning bids were offered by Ritek, Tatneft-Samara and Techsnab. The winners of the auction will obtain 25-year E&P licenses. The Lemeshkovskiy block covers 356 sq km in the Mukhanovo-Yerovskiy Depression. Hydrocarbon resources (category D1) of the block are estimated at 40 MMbbl of oil. The starting price amounted to RUB 7.5 million (USD 0.11 million). Ritek offered RUB 602.2 million (USD 8.83 million). The Nugaykinskiy block covers 102 sq km in the south-western flank of the Tatar Dome and encompasses ten prospects with combined oil resources estimated at 26 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 14 MMbbl of oil. The starting price amounted to RUB 43.1 million (USD 0.6 million). Tatneft-Samara offered RUB 249.98 million (USD 3.48 million). The Sudarovskiy block covers 46 sq km in the Buzuluk Depression and encompasses the Sudarovskoye oil field with 3P oil reserves estimated at 0.4 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 4 MMbbl of oil. The starting price amounted to RUB 12.4 million (USD 0.19 million). Techsnab offered RUB 133.92 million (USD 2.05 million).

Ritek, Tatneft-Samara and Techsnab have awarded Lemeshkovskiy, Nugaykinskiy and Sudarovskiy block respectively.

On 30 August 2018, the ANP approved of Imetame acquiring 100% working interest in the BT-POT-16 contract, Joao de Barro production concession, from former operator Norteoleum with 50% and partner Aurizonia with 50%. In early-September 2016, the ANP reported that UTC Exploracao e Producao SA officially transferred all equity in six exploration blocks and eight production concessions to Norteoleum Exploracao e Producao SA on 1 August 2016.  All of the assets are in the onshore Potiguar Basin.  Norteoleum is a subsidiary formed in 2009 of UTC Participacoes parent company that handles the exploration and production duties for the group.  It is speculated the transfer of assets has to do with the reported possible sale of the oil and gas business by the group. On 30 August 2011, the ANP approved the change of interest holder in the BT-POT-16 contract Joao de Barro production concession, carved out of the BT-POT-16 contract in the Potiguar Basin. UTC Engenharia S.A. transferred its 50% working interest to UTC Oleo e Gas S.A. In May 2010, UTC Engenharia farmed into Aurizonia’s Joao de Barro production concession for a 50% working interest and operations. In the first two months of 2010, the concession produced on average 28 bo/d and 81 Mcfg/d. On 2 March 2006, Aurizonia was granted a Final Award from the ANP for the 3.49 sq km Joao de Barro production concession for a carve-out concession of the ANP Round 5 BT-POT-016 contract POT-T-302 block in the onshore Potiguar Basin.  Aurizonia discovered Joao de Barro with the 1-AURI-2-RN (1-AURI-2-RN) and the 3-AURI-9-RN (3-AURI-9-RN) wells.  Aurizonia was to conduct a long term production test of the two wells, expecting 800 bo/d from these wells, and will then tie in additional producers.   Aurizonia has drilled a total of six wells within the production concession area.

Imetame acquiring 100% working interest in the BT-POT-16 contract, Joao de Barro production concession, from former operator Norteoleum with 50% and Aurizonia with 50%.

Norwest is looking to its 25% stake in TP/15, 485 sq km in the coastal Perth Basin, in order to fund appraisal work, presumably to the 2017 Xanadu find (ref. DEA 25 Sep ’17). Westranch (op), Triangle, 3C Energy + Kubla Oil. Contact: [email protected].

Norwest is looking to its 25% stake in TP/15, 485 sq km in the coastal Perth Basin, in order to fund appraisal work, presumably to the 2017 Xanadu find (ref. DEA 25 Sep ’17). Westranch (op), Triangle, 3C Energy + Kubla Oil. Contact: [email protected].

EL 1156, 16km from Bay du Nord discovery in deepwater Flemish Pass Basin, WD 974m, TD ca. 4,000m, reportedly potential commercial oil find + sidetrack rumoured, in which case a tie-back to BdN is conceivable. Target possibly Tithonian as in BdN (43 API oil), Transocean Barents SS (contracted for 3 wells + 3 options). Other locations for potential drilling are Sitka O-2 (WD 840m) and Bakeapple M-35 (WD 1049m). Equinor (op), partner BP.

(Flemish Pass B.) Cappahayden K-67 nfw. (Equinor 60% op, BP 40%) in DW EL 1156 block, 16km from Bay du Nord discovery, reportedly potential commercial oil find + sidetrack rumoured, in which case a tie-back to BdN is conceivable. Target possibly Tithonian as in BdN (43 API oil), WD=974m, TD=ca. 4000m.

Debt is reportedly behind KNOC’s possible move towards selling a 30% stake in Aberdeen-based Dana Petroleum, which it currently owns 100%.  The 30% stake could be worth some USD 530 MM. Dana’s main asset is a 77% interest in the Western Isles project which came on stream late 2017.

Debt is reportedly behind KNOC’s possible move towards selling a 30% stake in Aberdeen-based Dana Petroleum, which it currently owns 100%. The 30% stake could be worth some USD 530 MM. Dana’s main asset is a 77% interest in the Western Isles project which came on stream late 2017.

Petro Matad reported on 9 September 2019 that Heron-1 has reached a TD of 2,960 m with oil and gas shows in the Lower Tsagaantsav Formation. The well hit the top Lower Tsagaantsav reservoir at 2,803 m, only 5 m shallower than the pre-drill prognosis. Logs data indicated a 77 m gross interval of potential reservoir between 2,803 and 2,880 m, which was predominantly sandstone interbedded with shales and siltstones. Within this interval the logs data also define better porosity and permeability reservoir in three zones with a total gross thickness of 22 m (14 m net). The well is currently in casing operation and prepared for a testing programme. Petro Matad reported on 19 July 2019 that the company has spudded Heron-1 in the Tamsag Basin, Mongolia. The well is situated at the Heron prospect which lies near the boundary between Block XIX and XX within the Block XX. The well was planned to be drilled to a PTD of 3,050 m with the objective of exploring the hydrocarbon potential of the extension of proven oil in the Tolson Uul oil field (or 19-46 oil field) that spills updip into Block XX, and is targeting the Tsagaantsav Formation of the Upper Jurassic - Lower Cretaceous clastic play within the area.  DQE International 40105 rig is used for the drilling operation. Heron prospect is one of the 5 lease line prospects in the 2018 Programme in Block XX of Petro Matad. The 5 prospects include Gazelle, Heron, Antelope, Wild Boar and Marmot, among the which, 3 high-graded prospects of Gazelle, Heron and Antelope were estimated with 50-75% chance of success. The prospects area is covered by 2D and 3D seismic and Heron prospect is estimated to contain 25 MMbo of Mean Prospective Recoverable Resource, and is the continuations of producing trends or structures on Block XIX. Adjacent infrastructure facilitates would help quick development in the event of success. Background Information Tolson Uul oil field (or 19-46 oil field) is immediately to the north of the Heron prospect in Block XIX. The field was discovered by SOCO (USA) in 1995, and brought onstream on 11 February 1998, with the first crude exported to the Aershan oil field pipeline in China by truck. Once in this pipeline, the crude is pumped to a railroad terminal on the Moscow-Beijing railroad. It is then loaded from the pipeline into tank cars and transported to the Hohhot refinery for processing. on 1 April 2005, the field was transferred to PetroChina. Two fields Tolson Uul and Tolson Uul North in the Block XIX, as of August 2014, PetroChina-Daqing had produced crude of 500 thousand tons in Block XXI and XIX, exceeding the scheduled target, according to news report in August 2014. Petro Matad was awarded PSCA Block XX in 2006. In September 2011, the company has received approval from the Petroleum Authority of Mongolia (PAM) to have a two-year extension to its Production Sharing Contract (PSC) on Block XX. All current conditions of the Production Sharing Contract remain valid during the period of the extension, which is renewable for further terms after 19 July 2013. Petro Matad is the parent company of a group focused on oil exploration, as well as future development and production, in Mongolia. The Group holds sole operatorship of three Production Sharing Contracts with the Government of Mongolia. Block XX has an area of 10,340km² in the far eastern part of the country. Blocks IV and V are located in central Mongolia. Block IV covers approximately 29,000km² and Block V approximately 21,150km². Petro Matad drilled two NFWs in 2018 with drilling objective in the Jurassic – Cretaceous Play, but the both are failed to achieve oil/gas discoveries. The first well, Snow Leopard-1, is situated in Block V in the Taats Basin, as a basin play opener, was spudded on 9 July 2018 and completed reaching a TD of 2,930 m as a dry hole on 20 September 2018. The second well, Wild Horse 1, is situated in Block IV in the Baatsagaan Basin, was spudded on 23 October and completed reaching a TD of 1,490 m as a dry hole on 26 November 2018.

Mongolia (Hailar B.) Tolson Uul

Shale gas strat well in 4/2018/p Gora block, Fore-Sudetic Monocline in SW Poland, TD 3,250m in early 2012 (San Leon), frac job over 3,413-3,414m and 3,272-3,273m in the Carboniferous resulted in only minor amounts of gas, data under evaluation. Testing of the Siciny-2 was part of Ansila 35% farmin obligation from Gemini Res.

Poland (Northeast German-Polish B.) ? op. by GEMINI RES (65.0%, ANSILA EN 35.0%) in 4/2018/p block

Eni has announced the discovery of new oil resources in the Western Desert of Egypt with a new exploration well in the South West Meleiha Concession. Production in the Concession started just one year ago and is now in excess of 12,000 bopd. Eni has announced the successful drilling of the SWM-A-6X well, in the South West Meleiha development and exploration concession located in the Egyptian Western Desert, some 130 km North of the of Siwa Oasis. The new well has been drilled close to existing production facilities and is already connected to the production network. The production from South West Meleiha Concession began in July 2019 and in just one year ramped up to 12,000 bopd thanks to the contribution of new discoveries.   The SWM-A-6X well, drilled in the Faghur basin, reached a total depth of 15,800 feet and hit 130 feet of net oil pay in the Paleozoic sandstones of the Dessouky Formation. The well is already on stream with a daily production of 5,000 bopd. Eni is successfully implementing its near-field exploration strategy in the Egyptian Western Desert through AGIBA, a Joint Venture with the Egyptian General Petroleum Corporation (EGPC) quickly turning on production of the newly discovered resources. Eni has been present in Egypt since 1954, where it is the largest producer. Eni’s current equity  production is above 300,000 barrels of oil equivalent per day. Original article link Source: Eni

(Northern Egypt B.) Eni has announced the discovery of new oil resources from SWM-A-6X well in the Western Desert of Egypt, South West Meleiha Concession op. by ENI SPA (76%), LUKOIL (24%), EGPC (0%), well is already tied back and producing 5000bpd from Paleozoic Sandstones

New Zealand Oil & Gas Ltd., via wholly owned subsidiary NZOG 2013 O Ltd., is offering equity in exploration permit PEP 55794, located in the Great South Basin. On 18 October 2018, NZOG officially increased its holding to 100% and operatorship in PEP 55794 by acquiring the 70% operated interest formerly held by Woodside Energy (New Zealand 55794) Ltd. A drill or drop decision, which includes a 50% area reduction for the former, is due before 31 March 2020. Should the permit be retained, a commitment well is due before 31 March 2021, with further contingent well due by the permit expiry date. PEP 55794 is due to expire, or be eligible for renewal, on 31 March 2029. NZOG have outlined the Kaipatiki prospect as the primary candidate for drilling. The prospect lies in the southern portion of the permit and comprises a four-way, dip closed, stratigraphic trap created by the injection of deep water sands into overlying mudstones. The prospect has been mapped over an area of approximately 160 sq km using the Toroa 3D seismic data acquired in 2015. The sand injectites are likely to originate from the Wickliffe Formation (Pakaha Group), which includes the shoreface/nearshore Kawau Sandstone Member and the informal 'Wickliffe Coastal Facies', and are sealed by intraformational basinal mudstones. Modelling suggests that the prospect is well located to receive charge from mid to Late Cretaceous syn-rift Hoiho coals which are at the onset of liquids generation and at peak oil/liquids generation over much of the permit. Mean unrisked in-place resources of 7.3 Tcf of gas and 750 MMb of condensate have been estimated for the prospect. Potential development scenarios include a gas to shore option for which mean unrisked prospective recoverable resources of 5.6 Tcf of gas and 272 MMb of condensate have been estimated. The permit contains the Toroa 1 and Tara 1 wells that were drilled in 1976 and 1978 respectively.  Both wells encountered oil and gas shows during drilling, proving the presence of a working petroleum system within the area. PEP 55794, which covers an area of 9,835 sq km in both deep and shelfal waters, was awarded in April 2014 after being applied for under the Block Offer 2013. Under NZOG’s plans announced in February 2018, it will hold 100% operated interest assuming regulatory approvals. Interested parties are required to meet a confidentiality agreement prior to being allowed access to the data room and technical presentations. Parties interested in pursuing this opportunity should contact: Dr Chris McKeown, VP E&P Tel: 0064 21 134 4953 Email: [email protected]   Lisa McCarthy, Geologist: Tel: 0064 21 064 7850 Email: [email protected]

New Zealand Oil & Gas Ltd., via wholly owned subsidiary NZOG 2013 O Ltd., is offering equity in exploration permit PEP 55794, located in the Great South Basin. On 18 October 2018, NZOG officially increased its holding to 100% and operatorship in PEP 55794 by acquiring the 70% operated interest formerly held by Woodside Energy (New Zealand 55794) Ltd.

N. part of Shijiutuo High, N. Bozhong Depression, WD 20m, ops terminated late Mar '20, Zhongyouhai 12 JU. Target Tertiary clastics.

Quinhuangdao-22-3-1 (QHD 22-3-1) nfw . part of Shijiutuo High, N. Bozhong Depression, WD 20m, ops terminated late Mar '20, Zhongyouhai 12 JU. Target Tertiary clastics.

Armour Energy secured sole rights to Roma Shelf / Bowen-Surat Basin ATPs 2034-P (457 sq km), 2035-P (12 sq km) + 2041-P (30 sq km) on 20 Dec ‘18. The permits will be effective 1 Jan ’19 for 5 years.

Armour Energy secured sole rights to Roma Shelf / Bowen-Surat Basin ATPs 2034-P (457 sq km), 2035-P (12 sq km) + 2041-P (30 sq km)

A 321-sq km contract area was granted for CBM rights near Essen in Nordrhein-Westfalen on 24 Apr ’18. The contract runs to Apr ‘23. * Thyssen Vermögensverwaltung GmbH, Patentverwertungsgesellschaft für Lagerstätten, Geologie und Bergschäden GmbH (PVG).

A 321-sq km contract area was granted for CBM rights near Essen in Nordrhein-Westfalen on 24 Apr ’18. The contract runs to Apr ‘23. * Thyssen Vermögensverwaltung GmbH, Patentverwertungsgesellschaft für Lagerstätten, Geologie und Bergschäden GmbH (PVG).

In early May 2020, Petrobras asked antitrust regulator Cade for authorization to acquire Equinor’s stake in the ES-M-596 Block in the deepwater Espirito Santo Basin. The block is operated by Petrobras currently with 50% partnering with Equinor which also has 50% on the Round 11 block. This is the fifth request by Petrobras to acquire Equinor stakes in Round 11 blocks that the company is releasing in the Espirito Santo Basin offshore. Two blocks, ES-M-671 and ES-M-743, have already been approved by Cade while all five blocks are still pending transaction approval from the ANP. Equinor will remain partnered with Petrobras and retain its interests in the ES-M-669, ES-M-527 and ES-M-594 blocks. In 2019 Petrobras revealed plans to the ANP to drill the Monai prospect on ES-M-669, with an intent to reach the Espirito Santo pre-salt which could de-risk other prospects in the basin. The first period of exploration for ES-M-669 ends in August 2020 while the first and second periods of exploration for ES-M-596 expire on 25 September 2021 and 25 September 2023 respectively.Brazilian government sources in September 2019 indicate that Petrobras new-field wildcat 1BRSA1360ESS on the ES-M-596 Block had oil shows. Previous reports had the well ending drilling operations by 14 May 2018 without oil or gas show reports and it was believed to be plugged and abandoned as a dry hole. The well had a planned total depth of 5,532m and was drilled by Odebrecht’s ODN I drillship in a water depth of 1977m. The projected objective was the Late Cretaceous Urucutuca Formation. In December 2014 a multi-client 3D seismic survey in the offshore Espirito Santo Basin called Espirito Santo Phase III completed shooting. The survey was shot by the French company CGG for a planned data acquisition of 9,605 sq km. The ES-M-596 Block was covered in the survey along with others signed in 2013 from ANP Round 11. The data was acquired by the Oceanic Champion M/V.

Petrobras asked antitrust regulator Cade for authorization to acquire Equinor’s stake in the ES-M-596 Block in the deepwater Espirito Santo Basin. The block is operated by Petrobras currently with 50% partnering with Equinor which also has 50% on the Round 11 block.

SK-410B off Sarawak, TD 3,810m, 252m net gas pay, P&A on around 15 Jul ’19 after successful tests (see DEA 27 Jun ’19), Naga 6 JU.  PTTEP (op), partners Kufpec + Petronas.

SK-410B off Sarawak, TD 3,810m, 252m net gas pay, P&A on around 15 Jul ’19 after successful tests (see DEA 27 Jun ’19), Naga 6 JU. PTTEP (op), partners Kufpec + Petronas.

Lime Petroleum agreed a deal with Equinor on 8 April 2020 to gain a 20% interest in PL 263 D and PL 263 E. The licences are located in the Haltenbanken area of the Norwegian Sea, to the east of Wintershall Dea’s Maria field, and cover parts of blocks 6407/1 and 6507/10 respectively. They contain the Jurassic Appolonia prospect which will be drilled in late 2020. Lime's parent company Rex International Holding has verified the prospect using its Rex Virtual Drilling tool. The deal is subject to government approval. PL 263 D was awarded to Equinor (then Statoil) and Spirit Energy in APA 2017. Pandion entered the licence in November 2019, taking a 20% interest from Equinor, and then Spirit withdrew in December 2019. PL 263 E was carved out from PL 263 on 1 November 2019 (a 36 sq km area immediately north of PL 263 D). Following completion of the deal, interest in PL 263 D and PL 263 E will be held by Equinor Energy AS (60% + operator), Lime Petroleum AS (20%) and Pandion Energy AS (20%).

Norway (South Viking Graben (Viking Graben Province)) Maria

PEL 639, 627 sq km in the Cooper Basin, awarded 26 Apr ’18 for 5 years. Commitments 300 sq km 3D seismic + 2 wells in 1st year, more seismic + wells beyond. This unit was offered as CO2013-A in the 2013 SA acreage release.

Australia, PEL 639

On 28 September 2018, the consortium of BP, CNOOC, and Ecopetrol was granted a preliminary award for the Pau Brasil block through the 5th PSC Pre-Salt Bid Round after being the high bidder for the block.  The consortium paid a fixed bonus of USD 125.00 million at USD 1.00 to BRL 4.00 exchange rate and has a first exploration period financial guarantee of USD 62.50 million to cover the cost of the one well drilling commitment.  The consortium offered a state take of 63.79% and won the block over the one other bid for the block by Total with 40%, CNODC with 20%, and Petrobras with 40% who bid 62.40% state take.  BP is operator and has 50% working interest and partners are CNOOC with 30% working interest, and Ecopetrol with 20% working interest in the PSC contract. The PSC contract has a seven year exploration period.  The local content is 18% for the exploration phase and 25% to 40% for the development and production phases.

On 28 September 2018, the consortium of BP, CNOOC, and Ecopetrol was granted a preliminary award for the Pau Brasil block through the 5th PSC Pre-Salt Bid Round after being the high bidder for the block

Cooper Energy Ltd was awarded production licence VIC/L33, located in the Otway Basin, on 6 September 2019.  The licence has been awarded over the Martha gas discovery, which was made in November 2004. Work commitments for the licence have been outlined to include appraisal and exploration of the block, to determine additional resource presence and potential for development and commerciality of existing hydrocarbons. Retention lease VIC/RL11 was surrendered on 6 September 2019, to accommodate the award of VIC/L33. VIC/L33, which covers an area of 128 sq km, was awarded on 6 September 2019.  Participants in the licence are Cooper Energy (CH) Pty Ltd (50% + Operator) and Mitsui & Co Ltd (50%), held through two wholly owned subsidiaries Peedamullah Petroleum Pty Ltd (25%) and Mitsui E&P Australia Pty Ltd (25%)

Cooper Energy Ltd was awarded production licence VIC/L33, located in the Otway Basin, on 6 September 2019. The licence has been awarded over the Martha gas discovery,

Cluff Natural Resources is offering the opportunity for interested parties to farm-in to promote licence P2252 (blocks 41/5a, 41/10a and 42/1a) containing the Lytham, Fairhaven and Pensacola prospects. The licence was awarded in the 28th Licensing Round and following an extension is due to expire in November 2018. Lytham and Fairhaven are fractured Hauptdolomite prospects with a P50 prospective resources of 168 Bcf. Many similarities have been made with the Hewett field. The Lytham structure is a large low relief closure in the form of a faulted anticline. Pensacola is a large reefal build-up with P50 prospective resources of 424 Bcf and is thought to be similar to the Crosgan discovery. On 31 May 2018, Cluff announced that the OGA has waived its requirement for a farm-out to have been concluded by 31 May 2018 on licences P2248 and P2252. Therefore, both the Promote Period and the Initial Term of each licence will continue to run until 30 November 2018, subject to a drill or drop decision being made by 30 September 2018. Cluff can continue the farm out process in respect to P2248 and P2252, while also exploring various additional forms of financing which will support its aim of drilling one or more wells on these licences. Cluff Natural Resources is the sole interest holder in P2248. For further details please contact Andrew Nunn – Chief Operating Officer Tel: 0207 887 2630 & Mob: 07738846069 Email: [email protected]

United Kingdom, P2248

Melbana is considering a dilution of its 55% interest in AC/P50 + AC/P51 in the Vulcan Basin, both of which have seen their current 3rd year term extended by 12 months to May ’19 and a 4th year well commitment pushed back to the 5th year. Commitments still include G&G studies. Melbana (op), partner Rouge Rock.

Melbana is considering a dilution of its 55% interest in AC/P50 + AC/P51 in the Vulcan Basin, both of which have seen their current 3rd year term extended by 12 months to May ’19 and a 4th year well commitment pushed back to the 5th year. Commitments still include G&G studies. Melbana (op), partner Rouge Rock.ASA 10%) in PL 925,

On 21 November 2018, the CNH granted the official award after contract signature for the CNH-M5-Miquetla/2018 license contract with Operadora de Campos DWF, S.A. as operator and PEMEX as partner.  The contract was migrated from the AE-0388-2M-Miquetla exploration entitlement block and represents the fourth legacy service contract migrated to an exploration and production contract (CEE).  Operadora de Campos DWF, S.A. de C.V. is the operator with 51% working interest and non-operating partner is PEMEX with 49% working interest. The minimum work commitments for the contract include 11,209 work units for exploration activity and 14,911 work units for development activity for a total of 26,120 work units.  With and oil price of USD 55-60/bbl this equates to USD 1,000/work unit or the total work commitments are approximately equivalent to USD 26.12 million. On 19 January 2017, the CNH approved a request by PEMEX to modify Anexo 2 (Addendum 2) of its Exploration and Production entitlement to include the exploration commitments approved for the AE-0388-M-Miquetla block on 13 October 2016. This represents another step in the migration to an Exploration and Production contract (CEE). On 13 October 2016, the CNH approved a request by PEMEX to modify its exploration commitments for five modified Service Contracts including the AE-0388-M-Miquetla block Exploration and Production entitlement.  In September 2015 SENER granted PEMEX rights to all horizons instead of just the Paleocene and Upper Cretaceous productive zones in the block area.  The rights include all stratigraphic horizons to the Jurassic and also for unconventional exploration and production.  As a result, PEMEX has requested modifications to its exploration commitments for the block that includes the provisional proposal to drill one unconventional test well within the block to the Upper Jurassic Pimienta Formation.  The proposed horizontal test is the OPS-1 well.  It has a proposed total depth (PTD) of approximately 4,700 m measured depth (MD), 3,204 m true vertical depth (TVD), the Pimienta Formation objective at 2,816 m and a 1,500 m horizontal leg.  The total approved investment commitment for the block is USD 9.18 million.  The approved budget also includes re-processing existing 3D seismic, geological studies as well as the drilling of the horizontal test.  The OPS-1 well has estimated resources to be incorporated of 11.7 MMb of 33° to 38° API oil.  PEMEX has a provisional trajectory for the horizontal to be drilled in a northwest to southeast direction.  The CNH approved modifications were sent to SENER who will grant the final approvals.  If PEMEX proceeds with its planned horizontal test, it will have to have the final plans approved by the CNH.    PEMEX is the underlying titleholder to the entitlement and there was no mention of the companies involved in the Service Contract but it is assumed they will remain as partners in the CEE. The CNH suggested in its final opinion that PEMEX considers farming out to other companies in order to share risk and have companies involved with the latest technology to help it develop the unconventional potential in the country.   One of the factors in the CNH suggestion for PEMEX to farm-out was the marginal economics of the planned activity. On 11 January 2017, the CNH approved a request by PEMEX to modify the area of the adjoining AE-0388-M-Miquetla and the A-0217-M-Campo Miquetla blocks in order to exclude the Castillo de Teayo archeological site.  The AE-0388-M-Miquetla block was reduced by 1.60 sq km from 140.83 sq km to 139.23 sq km and the A-0217-M-Campo Miquetla was reduced by 1.60 sq km from 202.52 sq km to 200.92 sq km. The AE-0388-M-Miquetla block has undergone a number of modifications over the past year. On 1 September 2015, the Secretaria de Energia de Mexico (SENER) granted formal approval for the migration of the A-0388-Miquetla block production entitlement Service Contract to the AE-0388-M-Miquetla block Exploration and Production entitlement. The block covers an area of 139.23 sq km in the Tampico-Misantla Basin after modification on 11 January 2017. The Exploration and Production entitlement continues to have a 25 year total term from original granting date of 13 August 2014 but now has a new commencement date to the two phase exploration period.  The first three year exploration phase of the entitlement commenced on 1 September 2015 indicating a final expiry of 1 September 2018 and there is the possibility of a two year extension period.  Additionally in October 2016 the Exploration and Production entitlement was modified significantly with changes to the exploration commitments and rights to all geological horizons.  The entitlement is still in the final migration process to the CEE which is expected to occur by 4th quarter 2017, or two years from the initial 2015 date SENER and PEMEX reported at the start of the process.

CNH granted the official award after contract signature for the CNH-M5-Miquetla/2018 license contract with Operadora de Campos DWF, S.A. as operator and PEMEX as partner.

On 25 January 2018, the award of the Békéssámson contract in southern Hungary, pre-awarded to Vermilion Exploration in November 2017, was signed off by the Minister for National Development and thus became official. The 1,338 sq km Békéssámson area is located in the Békés and Csongrád political provinces, within the Pannonian Basin. Background Information On 13 June 2017, acting on behalf of the Hungarian State and in cooperation with the Hungarian Office for Mining and Geology, the Minister for National Development published an invitation to tender for a concession over the Békéssámson area. The tender closed on 25 September 2017. On 17 November 2017, following recommendation of the tender committee from the Hungarian Office for Mining and Geology, MOL was selected as the winner of the bid round for the prospection, exploration and production of hydrocarbons in the Békéssámson area. The company had two months (plus additional two months extension) to negotiate the final contract.

Hungary, not found

South Sumatra block onshore, P+A end Dec ’17, results n/a. PTD was 304m, targets assumed Batu Raja, possibly fractured Basement and TAF.

Cempaka 1 op. by Medco (100%) in South Sumatra PSC, P&A, results n/a.

Block 3G, deepwater Sabah, P&A results n/a 8 Apr ’19. Target assumed L. Pliocene Pink Fan sst + U. Miocene Kamunsu sst, West Carina DS.

Malaysia, Block 3G

Seacrest Capital fund, owner of Azinor Catalyst, is understood to be possibly open to sell part or all of its holding in the company, a deal which could fetch between USD 60-100 MM. Unsolicited offers have been received for it, as Azinor has prospective resources of ~600 MMboe but no production yet.

Seacrest Capital fund, owner of Azinor Catalyst, is understood to be possibly open to sell part or all of its holding in the company, a deal which could fetch between USD 60-100 MM. Unsolicited offers have been received for it, as Azinor has prospective resources of ~600 MMboe but no production yet.

Equinor has been unsuccessful with its Stalull exploration well, drilled using the “Deepsea Bergen” S/S in PL 630. 35/10-4 S penetrated a 210 m section of the Brent Group. Of this 40 m comprised sandstone reservoir rocks, however, reservoir quality was poor to moderate. A 140 m section of the Cook Formation was encountered, of which 75 m were effective reservoir rocks. Reservoir quality was moderate to good. In the Heather Formation approximately 10 m of thin sandstone layers with poor reservoir quality were encountered. The well also encountered a 17 m section of good reservoir quality sands in the Paleocene. The well was drilled to TD at 4,010 m in the Amundsen Formation and on 15 October 2018 sidetrack 35/10-4 A was kicked-off. This well targeted the Upper Jurassic, Oxfordian Gnomoria prospect. A section of poor reservoir quality sandstone layers were encountered in the Heather Formation totaling 122 m. Oil was proven although no OWC was encountered. Estimated recoverable reserves are 1.25 – 7.5 MMbo. 35/10-4 A was drilled to TD at at 3,946 m (3,430 m TVD) in the Heather Formation. The well was abandoned on 12 November 2018. The initial drilling plan stated that the 35/10-4 A well would also be drilled on Stalull, downdip, (if the main wellbore was a success) and would target the Oseberg Formation with a planned TD of 4,490 m (4,184 m TVD), and that 35/10-4 B was the sidetrack designated to target Gnomoria. 35/10-4 S lies immediately west of the small Syrah oil discovery which was made by Wintershall in 2015 with exploration well 35/11-18. A 275 m thick Middle Jurassic Brent Group section was present with light oil columns in the Tarbert Formaton (11 m) and the Oseberg Formation (3 m – the Oseberg Formation is the basal part of the Brent Group in this area of Norway). There was also an 8 m hydrocarbon column in the Upper Jurassic, Oxfordian Heather Formation. Sidetrack 35/11-18 A was drilled 450 m south of the discovery and proved gas and oil in two Heather Formation sandstones (33 m and 24 m thick). Oil was also present throughout the Brent Group (270 m thick) and there was a 46 m light oil column in the Cook Formation. The Cook and Oseberg formations were tested and exhibited good flow properties. Recoverable reserves were estimated at 6-19 MMbo. Equinor Energy AS operates PL 630 with a 60% interest. It is partnered by Wellesley Petroleum AS which holds the remaining 40%.

Norway (Oseberg Fault Block (Horda Platform)) Oseberg

Cooper Energy Ltd was awarded production licence VIC/L34, located in the Otway Basin, on 6 September 2019.  The licence has been awarded adjacent to the Halladale gas discoveries, which were made in April 2005. Work commitments for the licence have been outlined to include appraisal and exploration of the block, to determine additional resource presence and potential for development and commerciality of existing hydrocarbons. Retention lease VIC/RL12 was surrendered on 6 September 2019, to accommodate the award of VIC/L34. VIC/L34, which covers an area of 7 sq km, was awarded on 6 September 2019.  Participants in the licence are Cooper Energy (CH) Pty Ltd (50% + Operator) and Mitsui & Co Ltd (50%), held through two wholly owned subsidiaries Peedamullah Petroleum Pty Ltd (25%) and Mitsui E&P Australia Pty Ltd (25%)

Cooper Energy Ltd was awarded production licence VIC/L34, located in the Otway Basin, on 6 September 2019. The licence has been awarded adjacent to the Halladale gas discoveries,

Simwell Resources released a statement on 5 August 2020 disclosing that it has farmed-out a 70% stake and operatorship in its P2332 licence (blocks 41/3, 41/4 and 41/9) to Shell. The deal has received Oil and Gas Authority (OGA) approval. The licence covers 715 sq km and is directly west of the Shell operated P2252 licence (41/5a, 41/10a and 42/1a). Simwell was awarded the P2332 licence in May 2017 in the 29th Offshore licencing round. Simwell mapped two Carboniferous leads in the Scremerston Formation and Fell Sandstone Formation and mapped the Permian Zechstein Z3 carbonate play fairway. Simwell believe that each of the two Carboniferous leads could contain more than 500 Bcfg recoverable. The 29th round award was granted with a 3D seismic commitment that has already been satisfied by the 3D survey shot by Shell in the neighbouring P2252 licence, which also extended approximately 160 sq km into P2332. The seismic survey commenced on 1 August 2019 and it was being processed in August 2020. The P2332 licence commitments have therefore been satisfied until the drilling decision which is required before May 2023. In May 2019 Shell acquired a 70% interest in the neighbouring licence P2252. The licence hosts the Pensacola prospect which has a Zechstein reservoir target and is expected to be drilled in late-2021. Interest in P2332 is held by Shell UK Ltd (70% +operator) and Simwell Resources Ltd (30%).

(Anglo-Dutch B.) P2332, Simwell Resources has farmed-out a 70% stake and operatorship (blocks 41/3, 41/4 and 41/9) to Shell. The deal has received Oil and Gas Authority (OGA) approval. The licence covers 715 sq km and is directly west of the Shell operated P2252 licence (41/5a, 41/10a and 42/1a).

Kudirka-Kybartai block, Kirsiu Depression in S. Lithuania, drilled + susp. 1 - 28 Dec ’17, susp at TD 805m in the target Minja fm after testing oil shows from 3 horizons. Lotos LTO 600 rig.  

Vilkupiai-1 nfw Kudirka-Kybartai block, Kirsiu Depression in S. Lithuania, drilled + susp. at TD 805m in the target Minja fm after testing oil shows from 3 horizons.

The 20.5-sq km Manasozen block in Dagestan Republic (Terek-Caspian Basin, N. Caucasus) was auctioned 24 Aug ’18, local Tekhnomarket won the 25-year rights with a USD 1,450 offer (starting price USD 1,300).

The 20.5-sq km Manasozen block in Dagestan Republic (Terek-Caspian Basin, N. Caucasus) was auctioned 24 Aug ’18, local Tekhnomarket won the 25-year rights

Nafta secured sole rights to the 260-sq km Besa block, East Slovak sub-basin in E. Slovakia, on 4 Oct ’18 for 11 years.

Nafta secured sole rights to the 260-sq km Besa block, East Slovak sub-basin in E. Slovakia, on 4 Oct ’18 for 11 years.

Rosneft announced on 18 October 2017 that it has signed the required documents with Kurdistan Regional Government (KRG) to put into force Production Sharing Agreements (PSAs) for five blocks in the semi-autonomous region. The parties had agreed the PSAs in June 2017, on the side-lines of the St. Petersburg International Economic Forum. The PSAs form part of a series of agreements between Rosneft and the KRG, aimed at widening cooperation in E&P of hydrocarbons, commerce and logistics.<P />In a statement, Rosneft said that the terms of the agreements and the basic principles of product distribution are similar to the PSAs the KRG has signed with other international oil and gas companies. The Russian company will take an 80% stake in the blocks and may pay an upfront fee of US$ 400 million for farm-in and geological information. While the five blocks have yet to be identified, Rosneft said their combined total recoverable oil reserves are estimated at around 670 MMbo. The company will conduct a geological exploration campaign and is targeting pilot production as early as 2018.

Not Found

PL 609 S. Barents Sea, TD 3,057m, 118m gas column in the Carboniferous Falk fm (Gipsdalen grp), 720m horiz section drilled in the Falk and Ørn fm’s. A first 30-day test yielded up to 7,500 bo/d on 60/64” choke, a 2nd  25-day test gauged up to 18,000 bo/d on 118/64” choke. Leiv Eiriksson SS. The current devt concept for Alta is a subsea connection to a standalone FPS. The adjacent Gohta find is considered a possible joint devt opportunity. Lundin (op), partners DEA + Idemitsu.

7220/11-05 S (Alta) pos. appr. (Lundin op, 40%, Idemitsu 30%, DEA 30%) in PL 609, was drilled 700m horizontally in the oil zone, encountering all targeted reservoir intervals (Late Permian - Early Triassic Kobbe conglomerates and Ørn carbonates), before an extended production test was carried out. The well flowed at a constrained rate of about 7500 bo/d for 30 days [60/64” choke], and then flowed at a maximum rate of up to 18000 bo/d for 25 days (118/64” choke - constrained by surface facilities).

On 30 July 2020, the Agencia Nacional do Petroleo (ANP) granted formal approval for Petrobras to transfer 100% working interest to Eagle Exploracao de Oleo e Gas Ltda for the Conceicao, Fazenda Matinha, Fazenda Santa Rosa and Querera production concessions in the onshore Tucano Basin. The approval is conditioned to both companies presenting documents with details about the decommission of the fields. Petrobras had reported on 9 March 2020 the signature of the sales agreement with Eagle Exploracao de Oleo e Gas Ltda for the Tucano Sul cluster of four producing gas fields mentioned above. The total consideration for the sale was USD 3.01 million which was to be paid in two installments, USD 602,000 on 9 March 2020 and USD 2.41 million on the official closing date of the transaction. On 9 July 2019, Petrobras published its teaser to sell the Tucano Sul cluster of four producing gas fields in the onshore Tucano Basin. Tucano Basin fields sale - general information Field Name Field sqkm Disc Date Year Prod Start Date Avg. cond. Prod. (bc/d) (Jan-May 2020) Avg. gas prod. (Mcfg/d) (Jan-May 2020) Conceicao 9.8 1967 25-Feb-1970 0.38 486.45 Fazenda Matinha 3.95 1986 05-Apr-2005 0.15 99.16 Fazenda Santa Rosa 4.58 1992 25-Oct-2005 0.45 139.39 Querera 5.4 1962 01-Jul-1962 0.00 44.13 Source: IHS Markit © 2020 IHS Markit

(Tucano B.) the Agencia Nacional do Petroleo (ANP) granted formal approval for Petrobras to transfer 100% working interest to Eagle Exploracao de Oleo e Gas Ltda for the Conceicao, Fazenda Matinha, Fazenda Santa Rosa and Querera production concessions.

Corallian and partners Baron Oil + Upland Resources have reached a confidentiality agreement with a European E&P co. for P2478 / blocks 12/27c, 17/5, 18/1 + 18/2, Dunrobin prospect) in the Inner Moray Firth. Terms call for a suspension of the farmin offer until 30 Sep '20 to allow for the suitor to complete a regional evaluation and share its data with P2478 partners. This period may be extended to 31 Dec '20 in the event a farmin be on the cards. P2478 is part of a larger Corallian offer which includes P2464 / block 3/12b (Unst gas prospect, NNS) and P2470 / blocks 11/23, 24c + 25b (several prospects + Knockinnon discovery):

United Kingdom, P2464

On 23 November 2018 Amerisur Resources reported a farmout agreement with Occidental Andina for four blocks in the Putumayo Basin. The USD 93.25 million deal includes 50% interest in each of the PUT-9, Terecay, Tacacho, and Mecaya blocks where Occidental will fully fund five exploration wells and pay 85% of the costs for a 2D seismic acquisition, estimated at USD 38 million and USD 55.25 million, respectively. Amerisur will retain operatorship and the remaining 50% interest in each block. This company deal accelerates Amerisur’s work programs in the Terecay and Tacacho blocks where the social consultations (Consulta Previa) and licensing procedures have already been completed for the 878 km 2D seismic survey to commence in Q1 2019. Consulta Previa for drilling on the Tacacho Block is anticipated to commence in Q1 2019 with drilling plans slated within a year.

Amerisur Resources reported a farmout (for 50% share) agreement with Occidental for 4 blocks Putumayo-9, Terecay, Tacacho and Mecaya blocks by funding a US$93.2 MM exploration and appraisal programme.

1st well in PL 910, NE of Yme in Egersund sub-basin, WD 99m, P&A'ing dry at TD 3,121m (Bryne fm), Scarabeo 8 SS. Repsol (op), partners Lotos + Okea.

009/02-12 (Kathryn) nfw. (Repsol 61,11% op, Lotos 22,22%, Okea 16,67%) 1st well in PL 910, NE of Yme in Egersund sub-basin, WD99m, P&A, dry, with no traces of petroleum, at TD=3121m (Bryne Fm). Encountered 130m of reservoir in the Sandnes Fm, including about 50m of sst with poor to moderate quality.

Further to DEA 20 Mar '20: The LPRA, in association with NOCAL + TGS, confirms the launch event for its 2020 Liberia Licence Round offering 9 offshore blocks in the Harper Basin off the SE coast (in deep brown below). Investors can now register for the launch event webinar scheduled 15 Apr '20 (2:00 PM - 3:00 PM BST). The round will open on 10 Apr '20 via weblink, with prequals to take place 10 Apr '20 to 31 Oct '20 via email/weblink, bid submissions to Monrovia 1 Nov '20 - 28 Feb '21, when the round closes. Contact for further info (bid docs, prequal criteria + forms, data availability): https://info.tgs.com/liberia-license-round-2020. TGS map below.

Liberia, not found

Soco has won exploitation rights to each of the Viodo, Lideka and Loubana areas within former block Marine XI, pursuant to an application filed before the Marine XI expiry in March. Award of the 25-year permits now await publication in the Gazette. Along with Lidongo awarded a year ago, Soco will operate with 40.39%, partners WNR 23%, SNPC 15%, Africa Oil 13.11%, PetroVietnam 8.5%.

Congo (Lower Congo B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Lidongo op. by SOCO EP (40.39%, WNR 23.0%, SNPC 15.0%, AFRICA OG 13.11%, PETROVIET 8.5%) to be check.Marine XI op. by SOCO EP (40.39%, WNR 23.0%, SNPC 15.0%, AFRICA OG 13.11%, PETROVIET 8.5%) to be check.

As previously announced (DEA 23 Jan '19 et al), Sénégal's 2020 licensing round was officially presented at the MSGBC Basin Summit & Exhibition in Dakar yesterday. Additional promo meetings are planned 20 Feb '20 in London, 25 Feb '20 in Houston. 12 blocks are on offer, formal invitation to bid on 31 Jan '20, deadline 31 Jul '20. Meanwhile an MC3D survey (' SN-UDO-19') is underway in ultra-deepwaters off N. Sénégal, fast-track data in 2Q '20.

Senegal, not found

Goshawk has been awarded 6-month special prospecting permit SPA 31 AO, 15,943 sq km onshore Canning Basin, on 3 Dec ‘18.  The rights are for surface exploration and were applied for in 2016 as STP-SPA-0072.

Goshawk Energy was awarded a 6 month special prospecting permit (SPA 31 AO) covering a total 15,943 sq km onshore.

On 16 April 2019 United Oil & Gas (UKOG) announced it has agreed to acquire Europa’s and Union Jack’s 20% and 7.5% interest respectively in licence PEDL 143 which contains the Holmwood prospect. UKOG will also acquire operatorship from Europa as previously announced on 14 March 2019. The deal follows UKOG’s company strategy in acquiring a majority interest in key operated assets, in the same Portland and Kimmeridge reservoir objectives that are present in the company’s Horse Hill oil field. UKOG will pay a total consideration of GBP 300,000 for Europa’s 20% interest. Europa stated that the sale is in line with its strategy of focussing on the company’s high impact portfolio in Atlantic Ireland, producing assets in the UK and pursuit of new ventures in Ireland, North Africa and North West Europe. The aggregate purchase price agreed between UKOG and Union Jack is GBP 112,500. Union Jack stated that the sale of its interest will allow the company to focus on its assets in the East Midlands, Humber Basin and East Yorkshire. The deals and transfer of operatorship are subject to approval by the Oil and Gas Authority. In September 2018 Europa announced that the Head of Estates at the Forestry Commission informed Europa that the Minister for Environment, Food and Rural Affairs decided not to renew the lease at the Holmwood exploration well site. Europa decided not to reapply for planning permission at this location. With PEDL 143 valid until 30 September 2020, UKOG and partners are investigating alternative sites from which to drill Holmwood and other Kimmeridge prospects. The Holmwood prospect is located near the northern margin of the Weald Basin and is defined as a faulted hanging wall anticline south of a northern bounding fault. Prospective reservoir intervals consist of the Portland Sandstone and Corallian Sandstone Formations with the Purbeck and Kimmeridge Clay forming seals. The source rock is interpreted to likely be Lower Jurassic which reached maturity prior to the Tertiary inversion of the Wealden Basin. It is believed that the Kimmeridge Clay did not enter the oil window in the area. Gross mean unrisked prospective resources of 5.6 MMbbl were estimated in a CPR published by Europa in June 2012. Following completion of the deals and transfer of operatorship, interest in the licence will be held by UK Oil and Gas Investments Plc (67.5% + operator), Egdon Resources U.K Limited (18.4%), Angus Energy Ltd (12.5%), and Altwood Petroleum Limited (1.6%).

United Kingdom, Europa

Sonatrach has made a gas discovery in its Ouan Farfar Sud 1 (OFRS 1) NFW. The well was drilled on the Ohanet II exploration licence in the Illizi Basin. It was spudded on 25 May 2017 and drilled to a TD of 3,670m using the Weatherford Drilling International #810 rig. The discovery lies to the south of the 2013 OFRN 1 gas discovery, and is the first well to have been drilled on the licence in 2017. Sonatrach operates Ohanet II with 100% equity.

Ouan Farfar Sud 1 (OFRS 1) op. by Sonatrach (100%) in Ohanet II exploration licence, gas discovery.

Hitherto-unreported, Cairn was awarded in July 3-year rights to 8 licences totalling 2,713 sq km as a result of the 2nd offshore round. Blocks 39, 40, 47 + 48 lie in Zone A and blocks 45, 46, 52 + 53 in Zone C, Levantine Basin. Commitments 3D seismic reprocessing over the former Arye (395), Myra (347) + Sara (348) licences (for blocks 39, 40, 47 + 48 ), and 3D seismic reprocessing over the former Shimshon (332) + Gal (202) licences (blocks 45, 46, 52 + 53). Capricorn (op), partners Pharos Egy (Soco) + Ratio Oil, 1/3 each.

Hitherto-unreported, Cairn was awarded in July 3-year rights to 8 licences totalling 2,713 sq km as a result of the 2nd offshore round. Blocks 39, 40, 47 + 48 lie in Zone A and blocks 45, 46, 52 + 53 in Zone C, Levantine Basin. Commitments 3D seismic reprocessing over the former Arye (395), Myra (347) + Sara (348) licences (for blocks 39, 40, 47 + 48 ), and 3D seismic reprocessing over the former Shimshon (332) + Gal (202) licences (blocks 45, 46, 52 + 53). Capricorn (op), partners Pharos Egy (Soco) + Ratio Oil, 1/3 each.

Acer Energy Ltd, a wholly owned subsidiary of Beach Energy Ltd, acquired a 20% increase in interest in retention leases PRL 173 and PRL 174, located in the Cooper-Eromanga Basin, on 10 September 2018. Acer Energy acquired all of previously joint venture partner Mid Continent Equipment (Australia) Pty Ltd’s interest in the permit, increasing its holding to 100% interest.  The companies had held joint interest since the award of the permits in February 2015. PRL 173 contains the Ginko and Willow fields, which were discovered in 2005 and 2016 respectively.  PRL 174 contains the Crocus 1 discovery, which was made in 2004. PRL 173 and PRL 174 cover a combined area of 154 sq km.  Acer Energy Ltd now holds 100% interest in both permits.

Australia, PRL 173

Add/ref. DEA 23 May, EGAS is offering the North Wadi El Natrun block for bids, onshore Nile Delta. This was part of the former RWE Tanta block, and is shown in blue below:

Egypt, not found