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On 2 November 2019, the Argentine government granted an exploration permit for AUS-105 block to Equinor through the publication of Resolution 696/2019 in the nation’s official gazette following the preliminary award of the block in May 2019 as a result of the Argentina Round 1 offshore bid round. Work program in the first exploration period of four years consists of 3D seismic acquisition of 1,000 sq km, and 2D gravimetry and magnetometry acquisition of 2,000 km, followed by a drilling commitment for one well in the second exploration period of three years. An optional third exploration period of four years is possible, although accompanied by a 50% partial relinquishment. Equinor will operate the block with 100% participating interest. AUS-105 covers 2,118 sq km of areas, respectively, on the continental shelf of Austral Basin with approximated water depth of up to 80 m. Exploration target for the block is expected to be oil and gas in the Springhill Formation. The formation has been proven to be a producer in several gas fields in the Austral Basin, although no discoveries have been made in the area of AUS-105. Equinor won the rights for the block after submitting an offer of USD 15.2 million in Round 1 of the country’s offshore bid round that ended on 16 April 2019.  Beside AUS-105, Equinor also received 100% operatorship on the adjacent AUS-106 block, along with MLO-121 block in Malvinas Basin and CAN-108 block in Argentina Basin. In addition, the company won CAN-102 and CAN-114 in Argentina Basin in a partnership with state company YPF, as well as MLO-123 block in Malvinas Basin as part of a consortium with YPF and operator Total. Background Information The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. Granting of exploration permits from the round was originally expected to be published in early-August 2019 with signing of the permits to follow within 15 days.

Equinor has been formally awarded more rights it won in Argentina's 1st offshore round earlier this year: Austral Basin: AUS-105 (2,157 sq km) + 106 (2,283 sq km, see also DEA 5 Nov)

It is understood that United Energy Pakistan Ltd (UEPL) has discovered gas in Bago 1 new field wildcat (NFW) well within the Khipro 2568-6 EL (Lower Indus Basin) onshore block during September 2017. The company had conducted Drill Stem Test (DST) after setting 5” liner at 3,985 m depth in July 2017, but the results are currently not available. The well was spudded on 24 May 2017 using the Hilong Oil Services ‘HL-5’ land rig with a prognosed TD of 3,994 m in the Cretaceous and it reached the TD of 3,987 m by the end of June 2017. It is believed to be targeting the Cretaceous Lower Goru Formation. The company recently drilled Rahim South 1 exploratory well in the block which was temporarily suspended during late March 2017 at a depth of 3,334 m. The well was spudded on 11 February 2017 with a prognosed TD of 3,330 m. Khipro EL, located in the Sindh province, covers an area of 1,246 sq km and surrounds Bilal D&PL, Bilal North D&PL, Siraj South D&PL, Naimat Basal D&PL, Naimat West D&PL and Bobi & Dhamraki ML. The current equity split for Khipro EL stands as follows: UEPL (65%, operator), Bow Energy Resources (Pakistan) SRL (30%) and Government Holdings (Pvt) Ltd (GHPL) (5%).  

Pakistan (Indus B.) Bago 1 op. by UNITED EN (65.0%, UNITED EN 30.0%, GHPL 5.0%) in Khipro 2568-6 EL block

BT-PN-005 contract, SW part of PN-T-049 block A, Parnaíba onshore, P&A dry (no shows report) at TD 1,470m on 25 Nov ’18. Target Cabeças + Poti fm’s.

4-PGN-ANGICALA-MA (4-PGN-030-MA) (Parnaiba Gas Natural 100%) in the BT-PN-005 contract, PN-T-049 Block A, P& A, dry.

Petronas has agreed with Repsol to farmin to the Andaman III PSC from Repsol, the latter having offered up to 49%. The 8,523-sq km permit lies in shelf-deepwaters of the N. Sumatra Basin. A min. 50-day (dry) well is planned in the deepwater sector, target likely Tampur fm gas.

Petronas has agreed with Repsol (->51% op.) to farmin to the Andaman III PSC (8523km²) permit from Repsol, the latter having offered up to 49%.

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

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

Repsol has been cleared to acquire a 50.1% stake in Gazprom Neft’s Karabashskiy-6 unit, owner of the Karabashskiy-17, -18, -19, -25, -26 and -27 expl blocks in Khanty-Mansiysk AO, won in an auction last year (ref. DEA 9 Apr ’18). The companies are already cooperating in the nearby Karabashskiy 1, 2, 3, 9, 10, 78 and 79 blocks, mostly through their Evrotek-Yugra JV.

Repsol has been cleared to acquire a 50.1% stake in Gazprom Neft’s Karabashskiy-6 block. The companies are already cooperating in the nearby Karabashskiy 1, 2, 3, 9, 10, 78 and 79 blocks, mostly through their Evrotek-Yugra JV.

The bid deadline for Lebanon's 2nd offshore round has been extended from 30 Apr '20 to 1 Jun '20 as a result of the CV19 outbreak. 5 blocks are on offer (in red below): 1 (1,928 sq km), 2 (new), 5 (2,374 sq km), 8 (1,400 sq km) + 10 (1,383 sq km) [blocks in green are 2017 round awards]. Companies wishing to submit an application must form consortia comprising at least 3 members. A data room is available at the Ministry of Energy + Water in Beirut. Contact: [email protected], release here.

Lebanon, not found

S-C part of Norte de Carcará block, Santos Pre-Salt, WD 2,052m, TD ca. 6,700m, oil shows report to ANP on 26 Nov ’18 and again on 27 Dec, DST’ing underway and believed encouraging. Target Barra Velha fm, West Saturn DS. An appraisal in the E. part of the block is expected to spud towards end Jan ’19, and testing of the Guanxuma find in BM-S-008 is also on the cards. Equinor (op), partners ExxonMobil + Galp.

Brazil, BM-S-008

In an 11 October 2019 interview, Richard Garrard, chief technical officer of Borealis Alaska Oil (rebranded from Nordaq Energy in June 2019), laid out the company's North Slope exploration plans. The company holds 100% interest in 70 leases covering 280,633 ac (1,136 sq km) in federal land in the National Petroleum Reserve – Alaska (NPR-A) and in state land to the east. Borealis is looking for a partner to share the costs and risks associated with the proposed work. In the NPR-A, the company has identified six lower Nanushuk prospects analogous to the geologic setting of recent discoveries at the Pikka and Willow developments. Borealis refers to this area, located southwest of Willow, as the Castle Prospect Trend and is in the process of staking four drilling sites in the Castle North prospect. Tentative plans are to drill one, and perhaps two, wells to depths of about 4,000 ft (1,219 m) at Castle North during the 2020/2021 drilling season. This would be followed drilling at Castle East and Castle Central during the 2021/2022 season.  Those wells would be drilled to depths of about 4,800 ft (1463 m). A listing of Borealis' NPR-A leases can be found at the Bureau of Land Management website https://www.blm.gov/sites/blm.gov/files/OilandGas_Alaska_NPR-A_LeaseReport_September2019.pdf. Borealis' leases on state land are located south of the Badami development, in what the company calls the Great Owl Prospect Trend. Like Badami, the prospective reservoir is the turbidite sands of the Canning formation. However, the company believes that the location of Great Owl is more advantageous to the development of thicker sands and more stacked reservoirs. Borealis would like to acquire 3D seismic before proceeding further.  Both TGS and SAE have recently conducted field studies in the area in preparation for possible seismic acquisition activity next winter. A map of Borealis' state leases can be found at the Alaska Department of Natural Resources website http://dog.dnr.alaska.gov/Document/FBCC82E5A7B341E1804283B3AA8814FC/10-21-2019__North_Slope_Notification_Lessee_Map?.

Nordaq Energy Plc rebrands as Borealis Alaska and seeks partner for Castle and Great Owl exploration wells

As per ministerial decree dated 7 December 2018 Global MED was awarded the contiguous F.R 44.GM and F.R 45.GM exploration permits located in the Ionian Sea on the maritime boundary with Greece. The contracts are valid for six years divided in three exploration phases. During the first phase the company is committed to acquire 300 km of 2D seismic over the acreage (within 12 months from the award). The second phase and third phases will involve a 3D seismic survey and an exploratory well, both subject to individual environmental impact assessments (EIA). The main objective in the area is oil in the Cretaceous to Eocene carbonates of the Apulian Platform. The northern part of the acreage is adjacent to Block 02 operated by Total offshore Western Greece. Colorado-based Global MED applied for the d89F.R-.GM and d90F.R-.GM (now F.R 44.GM and F.R 45.GM) adjoining exploration permits on 17 December 2013. The as yet undrilled blocks cover 745 sq km and 749 sq km respectively, in deep waters from 400 m to 1,100 m between 22 km and 56 km off Cape Santa Maria de Leuca, which marks the southernmost end of the Lecce province, Puglia region. The company was granted environmental clearance for the 2D seismic survey in mid-2017. Global MED LLC holds a 100% interest in the F.R 44.GM and F.R 45.GM applications for exploration permits.

Global MED was awarded the F.R43.GM (Sibari-Crotone B.) and F.R 44.GM and F.R 45.GM offshore exploration permits in Ionian Sea for six years.

ENEVA SA was drilling with gas shows the 1-ENV-BL84A-MA (1-ENV-005-MA) new-field wildcat (NFW) in the PN-T-084 block during mid-July 2019. The operator filed a gas show report with the ANP for the well on 28 June 2019.   The NFW was spudded on 15 June 2019.    The NFW has a proposed total depth (PTD) of 2,447 m. The Devonian Cabecas Formation and the Mississippian Poti Formation are the primary targets.     The NFW is located in the south-western-central area of the block approximately 5.7 km east of the 2-BAC-1-M plugged and abandoned in 1988 by operator Petrobras as a stratigraphic test at a final total depth (TD) of 3,252 m. ENEVA SA has 100% working interest in the ANP Round 13, 3,064.69 sq km, PN-T-084 contract awarded on 23 December 2015.

1-ENV-BL84A-MA (1-ENV-005-MA) nfw. (ENEVA 100%) in the PN-T-084 block, P&A with gas shows.

Bozhong Depression, Bohai offshore, WD 30m, ops terminated (results n/a) in mid-Sep ’18, Bohai 5 JU. Target Tertiary.

China, Bozhong

On 9 July 2020, Petrobras announced a closing of the sale of the Pescada, Arabaiana and Dentao fields on the Potiguar Basin shelf to OP Pescada, a subsidiary of local Brazilian operator Ouro Preto. The deal, for just US$ 1.5 million, includes the Petrobras’ 65% and operator status in the fields where OP Pescada already has the other 35%. The fields had a combined production in the first half of 2020 of 260,000 bbls of oil and 6.7 MMcfg/d. The transactions is still awaiting regulatory approval.  In early June 2020, it was disclosed that Petrobras was in an active divestment process and expected to soon conclude a sale agreement for its 65% working interest in the Pescada and Arabiana gas and condensate fields. The company is in direct negotiations with working interest partner Ouro Preto on the blocks which is presumably exercising a right of first refusal to acquire the Petrobras share and operator status on fields off the coast of Rio Grande do Norte. Negotiations have been in progress since early this year. Petrobras on 12 March 2019, announced the start of its binding phase in the competitive process to divest rights on the Polo Grande do Norte concession package in the state of Rio Grande do Norte and Potiguar Basin. The divestment package included: the Agulha, Cioba, Ubarana, Oeste de Ubarana, Pescada and Arabaiana concessions. Previously, Petrobras extended the deadline for companies to register interest in a divestment bidding process for 30 shelf oil and gas concessions in a September 2017 securities filing. The fields were organized into seven packages and Petrobras had a 100% working interest in most of them except the Pescada and Arabaiana fields. On 28 July 2017, Petrobras published a brief teaser on the sale of the areas in compliance with new transparency regulations determined by the Federal Audit Court. <P />

Brazil (Potiguar B.), Petrobras announced a closing of the sale of the Pescada, Arabaiana and Dentao fields to OP Pescada, a subsidiary of local Brazilian operator Ouro Preto.

On 23 April 2020, Tullow reported having signed a Sale and Purchase Agreement (SPA) with Total in which Tullow agreed to sell its entire interest in the Tilenga and Kingfisher projects (Lake Albert project) as well as in the East African Crude Oil Pipeline (EACOP) project to Total for USD 575 million. In addition, conditional payments will be made to Tullow linked to production and oil price, which will be triggered when Brent prices are above USD 62 / bbl. The deal is expected to be completed in 2H 2020 with an effective date of 1 January 2020. This will mark the end of Tullow's upstream and midstream projects in Uganda. CNOOC still has pre-emptive rights to acquire 50% stake on the same terms and conditions as Total. Considering the volatility in the oil market induced by the coronavirus disease 2019 (COVID-19) in March 2020, the Final Investment Decision (FID) for the Kingfisher and the Tilenga projects may be delayed to 2023. Before the crisis, the FID was expected in June 2022 with first oil in 2026. Before the deal, interest in the Tilenga and Kingfisher projects – which includes 10 licences – were held by Total, Tullow and CNOOC with 33.33% interest each: Operated by Total             Exploration Area 1/1A (Lyec)             PL7/2016 (Jobi-Rii)             PL8/2016 (Gunya)             PL6/2016 (Ngiri) Operated by Tullow             PL3/2016 Nsoga             PL1/2016 (Kasamene-Wahrindi)             PL4/2016 (Ngege)             PL2/2016 (Kigogole-Ngara)             PL6/2016 (Mputa-Nzizi-Waraga) Operated by CNOOC             PL1/2012 (Kingfisher) The project could potentially also include the Mpyo (Total) and Jobi East (Total) licences (production licenses still to be granted). Tullow’s farm-out deal in the Tilenga and Kingfisher projects to Total and CNOOC had been terminated by the Ugandan authorities on 29 August 2019 following the expiry of the Sale and Purchase Agreements (SPAs). This decision was a result of being unable to agree the tax treatment of the transaction with the government which was a condition to completing the SPAs. The authorities and the partners could not agree on the availability of tax relief for the consideration to be paid by Total and CNOOC as buyers. On 31 October 2019, oil firms' representatives met with President Yoweri Museveni to discuss key issues still hindering the FID. In February 2019, press reported that Tullow agreed to pay USD 167 Million in capital gains tax to the Uganda Revenue Authority (URA). Tullow was in dispute with the Government over USD 300 Million Capital Gains Tax that Government claimed following the farm-down deal between the three partners. However, Tullow argued that the transaction was not taxable as Tullow planned re-investing the money in Uganda.

Tullow reported having signed a Sale and Purchase Agreement (SPA) with Total in which Tullow agreed to sell its entire interest in the Tilenga and Kingfisher projects (Lake Albert project) as well as in the East African Crude Oil Pipeline (EACOP) project to Total for USD 575 million.

Shell signed an agreement to sell its 22.22% participating interest in the Bongkot and satellite gas fields straddling the B15, B16, B17 and G12/48 concessions in the Malay Basin, offshore Gulf of Thailand, on 31 January 2018. The deal that is worth USD 750 million is expected to be finalized by the second quarter of 2018, subject to the completion of certain conditions as prescribed in the agreement. PTTEP is the operator for the Bongkot project and its operating interest will increase from 44.45% to 66.67%, after the asset acquisition. Total E&P is the other partner with 33.33% equity. Earlier on 31 October 2017, Shell had mutually agreed with Kufpec to cancel the Sale and Purchase Agreement worth USD 900 million for the assets in Thailand. It is understood that the cancellation was due to disagreements on certain sale terms that could not be resolved within Shell’s and Kufpec’s time frame. The sale price was lower than the original offer of USD 1.2 billion, possibly due to weak oil prices. The Bongkot complex, including the main Bongkot field and the Greater Bongkot South development, is a major contributor to domestic production, with approximately 1,100 MMcfg/d and 27,800 bc/d in November 2017, an increase to the Q3/2017. According to PTTEP, the average sales volume for Thailand in Q4/2017 increased to 5% from Q3/2017, primarily from the Bongkot complex. The average selling price in Q4/2017 also increased to 41.74 USD/boe (Q3/2017: 38.78 USD/boe).

Thailand (Malay B.) Bongkot

N. part of Block XII, Upper Kura Basin of E. Georgia, sidetrack of existing wellbore to TD 2,700m (Eldari fm target), log data confirms 78.8m combined pay intv in target zones 9, 14 + 15, o+g shows noted throughout, stimulation planned.  Rig then to T-39 location for sidetrack project.

Georgia (South Caspian B.) ? op. by FRONTERA (100.0%) in Block XII

In early August 2019, Divine Inspiration Group (DigOil) – partner of Efora Energy in the local company Semliki Energy - confirmed being seeking a new partner for its Block III. The company is planning an exploration well in the northern part of the licence. The 3,217 sq km onshore licence is located in the Nord-Kivu province, eastern Democratic Republic of Congo (DRC), East African Rift System. Block III is crossed by the Semliki River and lies between Lake Albert and Lake Edward adjacent to Ugandan border. In May 2019, the company received a validity extension for its licence. As a result, the exploration phase is set to expire on 26 January 2020. Interest in the licence is held by Semliki Energy SPRL (85% + operator) and Societe National d’Hydrocarbures de la Republique du Congo (15%).

In early August 2019, Divine Inspiration Group (DigOil) – partner of Efora Energy in the local company Semliki Energy - confirmed being seeking a new partner for its Block III. The company is planning an exploration well in the northern part of the licence.

Serica Energy plc announced on 5 November 2018 that it has signed a sale and purchase agreement to acquire further interest in the Bruce and Keith fields along with the associated infrastructure. Under the agreement Serica will take a 16% interest in the Bruce field and a 31.83% interest in the Keith field from BHP Billiton Petroleum Great Britain Limited (BHP) for a cash consideration of GBP 1 million to be adjusted for working capital and 40% of post-tax cashflows. This deal follows two previously announced transactions between Serica and BP and Serica and Total to acquire interest in the Bruce, Keith and Rhum fields. The transactions have an effective date of 1 January 2018 and completion of the BHP deal is subject to regulatory approval and the completion of the deal with BP. BHP will retain liability of the costs of decommissioning facilities and wells already in place. All three deals between Serica and BP, Total and BHP are expected to complete on 30 November 2018. Also on 5 November 2018 Serica announced that all the conditions relating to the licence of the Rhum field issued by the U.S. Office of Foreign Assets Control (OAFC) have now been met. This means that all benefits relating to the Iranian Oil Company (IOC) from the Rhum field (which IOC is a partner) will be held in escrow for such a period as US scantions apply and ensure that neither IOC directly or any indirect parent company of IOC will derive any economic benefit from the Rhum field. IOC will also have no decision making powers with regards to Rhum. On 9 October 2018 Serica announced that it, along with BP, received a conditional licence and assurance from the UK Office of Foreign Assets Control (OFAC) relating the UK North Sea Rhum field. The licence will allow US or US-owned entities to provide goods, services and support involving the Rhum field. Also, non-US entities providing goods, services and support will not be exposed to US Secondary sanctions. Therefore, production from Rhum can now continue unaffected. The newly awarded licence is available until 31 October 2019. The initial deal between BP and Serica was announced in November 2017 in which it agreed to sell 36% interest in the Bruce field, 34.84% interest in the Keith field and 50% interest in the Rhum field to Serica. Under the terms of that deal Serica was to pay an initial consideration of GBP 12.8 million along with a share of cash flows over the next four years, a consideration equivalent to 30% of BP’s post-tax decommissioning costs and several contingent payments of future asset performance and product prices. BP expects to receive an overall payment in the region of GBP 300 million. In addition to the interest approximately 110 staff working for BP on the Bruce assets are also expected to make the transition to Serica. BP is to retain a 1% interest in Bruce to oversee its future operational and financial performance. In an update on 22 May 2018 Serica confirmed that amidst the decision by the US Government to withdraw from the Joint Comprehensive Plan of Action (JCPOA) and reintroduce US Sanctions on Iran, the company remains committed to complete the deal with BP which is partnered by the Iranian Oil Company (U.K) Limited in the Rhum field. The second deal involved Serica and Total. Under the deal, Serica was to acquire a further 42.25% interest in the Bruce field and a further 25% interest in the Keith field. Initial consideration for the interests is USD 5 million payable on deal completion then a deferred consideration of USD 15 million to be paid in three USD 5 million instalments, payable every 8 months following completion of the acquisition and subject to continued production from the nearby Rhum field. Total will retain a 1% interest in the assets. Bruce is a middle Jurassic gas, condensate, oil field discovered in 1974 by Hamilton Brothers Oil Co with well 9/8-1. It is a complex structure comprising three reservoirs - Bruce sandstone (oil and gas condensate), Statfjord sandstone (oil and gas condensate), and Turonian limestone (gas condensate). Appraisal drilling was largely unsuccessful until 1981. The field was not developed until 1990 and was developed using two bridge-linked platforms D and PUQ. It was brought onstream on 19 May 1993. During Phase II of the Bruce development a third platform was added to accommodate additional gas compression facilities. This CR platform, is bridge linked to the two original Bruce Field Platforms. Improved recovery commenced in 1997 with produced water being re-injected into the reservoir. The Keith field was discovered initially in 1983 by well 9/8a-8 which was drilled as a Bruce outpost. The field was not brought onstream until 2000. It has been developed as tie-back to Bruce. The Rhum field was discovered in 1977 with well 3/29-2 by a Joint Operating Agreement between BP and Iranian Oil. It was not initially developed due to the HP/HT nature of the reservoir. In 2002 the field development plan was submitted to the then Department of Trade and Industry. It was developed as a subsea tie-back to the Bruce field with two production wells and the completion of an appraisal well. Production commenced in 2005. Following completion of the deal, interest in Bruce (lying in licences P90, P209 and P276) will be held by Serica Energy plc (94.25% + operator), Marubeni Oil and Gas (U.K.) Limited (3.75%), Total E&P UK Ltd (1%) and BP Exploration and Operating Company (1%). Interest in Keith (P209) will be held by Serica Energy plc (91.67% + operator), Marubeni Oil and Gas (U.K.) Limited (8.33%) and Total E&P UK Ltd (1%). Interest in Rhum (P198, P566 and P975) will be held by Serica Energy plc (50% + operator) and Iranian Oil Company (U.K.) Limited (50%).

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

On 27 June 2019, the Federal Agency for Subsoil Use held an auction for two blocks in Nenets Autonomous Okrug (Timan-Pechora Basin). Zapadno Sibirskaya Neftegazovoya Kompaniya (a fully owned Fund Energy subsidiary) and Rusvietpetro (a Joint Venture between Zarubezhneft 51% and PetroVietnam 49%) emerged as the winners. The winners will obtain 25-year E&P licenses including a seven-year exploratory stage. The Vorgamusyurskiy Vostochnyy block covers 409 sq km. No exploratory wells have been drilled in the area. Hydrocarbon resources (category D1) are estimated at 82 MMbbl of oil. The starting price amounted to RUB 20.816 million (USD 0.33 million). Zapadno Sibirskaya Neftegazovoya Kompaniya offered RUB 22.90 million (USD 0.36 million). The Yareyyaginskiy Zapadnyy block covers 100 sq km in the Khoreyverskaya depression and encompasses the Yareyyaginskoye Zapadnoye oil discovery with 3P reserves estimated at 34 MMbbl. One exploratory well has been drilled in the area. Hydrocarbon resources (category D0) of deeper reservoirs at the discovery are estimated at 25 MMbbl of oil. The starting price amounted to RUB 270.558 million (USD 4.2 million). Rusvietpetro offered RUB 297.61 million (USD 4.62 million).

Russia, not found

AUREP is the Department responsible for the promotion of petroleum exploration under the Ministère des Mines of Mali. As of March 2016, AUREP had finalized a new division of the country in exploration acreage blocks. The old open block limits and denominations are not valid any more. The release of the new block limits was contingent on the new petroleum bill to be passed into law. The list of new acreage blocks became available in late-November 2016, it is presented below. In the west of the country, the new blocks are smaller than the previous ones. In fact the old blocks were divided in two in this area. The amount of available seismic data has doubled between 2004 and 2014, this has translated into a better understanding of the geology of the various sedimentary basins in the country. Therefore it was possible to design new block limits that take into account the improved basin definition. A new block, N° 29, was added in the far south of the country. AUREP stands for AUtorite pour la REcherche Petroliere. Interested parties should contact: Ahmed Ag Mohamed Directeur, AUREP Tel: +223 788 046 67 Email: [email protected]   The available blocks as of June 2020 are understood to be as listed below. There are thirty-nine open blocks. There was no change from the previous list. Total open acreage amounts to 850,451 sq km all onshore.   Open blocks       Block Name Area (sq km) Situation Block Basin Block 1A1 21,156   Hank Sub-basin (Taoudeni Basin) Block 1A2 34,279   Hank Sub-basin (Taoudeni Basin) Block 1B1 14,876   Hank Sub-basin (Taoudeni Basin) Block 1B2 14,932   Hank Sub-basin (Taoudeni Basin) Block 2A 10,842   Hank Sub-basin (Taoudeni Basin) Block 2B 10,890   Hank Sub-basin (Taoudeni Basin) Block 3A 10,506   Taoudeni Basin Block 3B 12,843   Hank Sub-basin (Taoudeni Basin) Block 4A 10,733   Taoudeni Basin Block 4B 10,797   Taoudeni Basin Block 5A 29,965   Taoudeni Basin Block 5B 29,782   Taoudeni Basin Block 6 23,600   Taoudeni Basin Block 7 39,991   Taoudeni Basin Block 8A 16,556   Taoudeni Basin Block 8B 19,267   Taoudeni Basin Block 9A 19,120   Taoudeni Basin Block 9B 24,223   Taoudeni Basin Block 10 37,566   Taoudeni Basin Block 11 33,141   Iullemmeden Basin Block 12A 32,557   Taoudeni Basin Block 12B 21,063   Nara Graben (Taoudeni Basin) Block 13A 42,863   Taoudeni Basin Block 13B 27,748   Taoudeni Basin Block 14 20,250   Iullemmeden Basin Block 15 17,090   Iullemmeden Basin Block 16A 16,972   Taoudeni Basin Block 16B 15,553   Taoudeni Basin Block 18 19,793   Nara Graben (Taoudeni Basin) Block 19 13,991   Taoudeni Basin Block 21 22,244   Taoudeni Basin Block 22 22,115   Taoudeni Basin Block 23 14,311   Taoudeni Basin Block 24A 29,053   Taoudeni Basin Block 24B 31,010   Taoudeni Basin Block 26 24,036   Pharusian Fold Belt Block 27 20,340   Mantass Depression (Iullemmeden Basin) Block 28 8,498   Taoudeni Basin Block 29 25,898   Taoudeni Basin

Mali, not found

On 16 May 2018, the Federal Agency for Subsoil Use held an auction for two blocks in Orenburg Oblast (Volga-Ural Province). Gazprom Neft submitted the highest bids for both blocks. The winner of the auction will obtain 25-year E&P licenses. Details of the offer are as follows: The Savitskiy block covers 904 sq km in the Buzuluk Depression and encompasses the Yablonevskiy and Larionovskiy prospects with combined oil resources estimated at 41 MMbbl. Hydrocarbon resources (category D1) of the block are estimated at 145 MMbbl of oil and 103 Bcf of gas. The starting price amounted to RUB 96.65 million (USD 1.56 million). Gazprom Neft offered RUB 1,894 million (USD 30.5 million). The Pokhvistnevskiy block covers 592 sq km in the Buzuluk Depression and encompasses the Latypskoye and Zhukovskoye Severnoye discoveries, not registered by the State due to small sizes. Hydrocarbon resources (category D1) of the block are estimated at 70 MMbbl of oil and 96 Bcf of gas. The starting price amounted to RUB 10.25 million (USD 0.17 million). Gazprom Neft offered RUB 507.375 million (USD 8.18 million).

Gazprom Neft was awarded Savitskiy (904km²) & Pokhvistnevskiy (592km²) block located in Orenburg Oblast.

On 27 March 2018, Premier with 100% working interest was granted a preliminary award for the 391 sq km Area 11, AS-B-57 block and 392 sq km Area 13, AS-B-60 block from the CNH-RO3-LO1/2017 Bid Round.  The final official contract signature award is to take place within 90 days or 1 July 2018. The company bid 29.47% state take over the minimum of 22.5% for the Area 11 block and 34.73% state take for the Area 13 block. The company bid 0 in additional work units factor equivalent to no exploration wells. There were no other bids for the two blocks.

Premier with 100% working interest was granted a preliminary award for the 391 sq km Area 11, AS-B-57 block and 392 sq km Area 13, AS-B-60 block from the CNH-RO3-LO1/2017 Bid Round.

Tullow has signed up for a 35% interest + operatorship from Discover in the latter’s offshore blocks 35, 36 + 37. Tullow will also part-carry Discover for 3D seismic + 1 well. The transaction is subject to govt approval. Discover has also signed to acquire the issued share capital of Bahari Resources, its 40% partner in the 16,063-sq km PSC.

16

PEMEX plugged and abandoned dry the Pox 101EXP new-field wildcat (NFW) in the AE-0007-2M-Amoca-Yaxche-05 entitlement block during mid-January 2019 after reaching a final total depth of 2,374 m.  The operator plans to drill a side-track the Pox 101AEXP to replace the original wellbore. The NFW was spudded on 17 October 2018. The well had a proposed total depth (PTD) of 6,540 m and the primary targets were the Cretaceous and Jurassic formations. The NFW was expected to traverse a 530 m allochthonous salt canopy at this location to reach the objectives. The well was drilled by the “West Titania” J/U in a water depth of 94 m. The NFW is located in the west central area of the block approximately 6 km east north-east of the 2003 Pox 1 new-field wildcat plugged and abandoned dry after extensive testing in 2009 in the westerly adjoining AE-0005-2M-Amoca-Yaxche-03 entitlement block. The drilling permit for the well was granted on 8 August 2018. The NFW has prospective resources estimated to be 109 MMboe. SENER awarded the AE-0007-2M-Amoca-Yaxche-05 entitlement block to Pemex 100% through Ronda 0 on 27 August 2014. The block covers an approximate area of 232.35 sq km.

Pox 101EXP (NFW) (Pemex 100%) in AE-0007-2M-Amoca-Yaxche-05 entitlement block, The well had a proposed total depth (PTD) of 6540 m and the primary targets were the Cretaceous and Jurassic formations. P&A dry.

Details are emerging around ANP's plans for a 17th round. 128 blocks totalling 64,100 sq km will be made available across 5 basins in 1Q '20, bid deadline likely in 3Q. Preliminary info suggests 16 blocks in the Campos Basin, 8 in the Para-Maranhão, 74 in the Pelotas, 13 in the Potiguar and 17 in the Santos.

Brazil, not found

Palermo Aike block, Magallanes Basin in Santa Cruz, TMD 2,247m, testing of the Springhill curtailed on CV19-related personnel + equipment issues, Eagle w/o rig redeployed to well w/o + maintenance, initially in the Chorillos block. Roch (op), partner Echo Egy (carried by Petrolera El Trebol thru this well).

Campo Limite X-1001 (CLix) nfw Palermo Aike block, Magallanes Basin in Santa Cruz, TMD 2,247m, testing of the Springhill curtailed on CV19-related personnel + equipment issues, Eagle w/o rig redeployed to well w/o + maintenance, initially in the Chorillos block. Roch (op), partner Echo Egy (carried by Petrolera El Trebol thru this well).

Some kind of hc find was made late last year in block 86, Eastern Province SE of Riyadh, the well being drilled + suspended between Oct-Dec ’18 after flaring gas. It lies in an under-explored sector of the country.

Saudi Arabia (Some kind of hc find was made late last year in block 86, Eastern Province SE of Riyadh, the well being drilled + suspended between Oct-Dec ’18 after flaring gas. It lies in an under-explored sector of the country.

Exxon has acquired Suncor’s 35% in EL 1134, 2,089 sq km in the Flemish Pass Basin. Exxon is now sole holder:

ExxonMobil (->100%) has acquired Suncor’s 35% working interest in offshore exploration license EL 1134 (2089km²).

In December 2017, Gazprom Neft Khantos completed testing of a new exploratory well in the Zimniy Zapadnyy license in Khanty-Mansiyskiy Autonomous Okrug (Western Siberia). Zimnyaya Zapadnaya 1, spudded in late March 2017, reached 3,050 m in late July. Oil flows were tested from the Cherkashinskaya Formation (Neocomian), which is the main play in the southern part of the Ural-Frolov Basin. Reservoir AS12 perforated at 2,570-2,595 m flowed with oil at a rate of 23 b/d. The interval 2,507-2,541 m (AS11) tested oil at a rate of 52 b/d. Reservoir AS9 perforated at 2,263-2,308 m flowed with oil at a rate of 332 b/d through a 6 mm choke. Based on primary data, 2P reserves of the discovery were estimated by IHS Markit at 12 MMbbl. Zimniy Zapadnyy license (KhMN03069NR) covers 1,240 sq km in the southern part of the Ural-Frolov Basin and encompasses several prospects.  

Russia (West Siberian B.) Zimnyaya Zapadnaya 1 op. by GAZPROM (100.0%) in Zimniy Zap. block, Reservoir AS12 perforated at 2,570-2,595 m flowed with oil at a rate of 23 b/d. The interval 2,507-2,541 m (AS11) tested oil at a rate of 52 b/d. Reservoir AS9 perforated at 2,263-2,308 m flowed with oil at a rate of 332 b/d through a 6 mm choke. Based on primary data, 2P reserves of the discovery were estimated by IHS Markit at 12 MMbbl.

Effective 1 October 2017 Hilcorp Alaska LLC was officially awarded 14 tracts covering about 76,682 acres (310 sq km) off Alaska’s south-central coast from the Cook Inlet Lease Sale 244 held by the Bureau of Ocean Energy Management (BOEM) on 21 June 2017. The company placed high bids in the amount of USD 3,034,815 and was the sale’s lone bidder. Sale 244 was the thirteenth and final OCS lease sale held under the 2012-2017 Five-Year Program. It offered some 1.09 million acres (4,410 sq km) for leasing and consisted of 224 blocks that stretched roughly from Kalgin Island in the north to Augustine Island in the south. Each bid went through a 90-day evaluation process to ensure the public received fair market value before a lease was awarded. All materials and statistics for Lease Sale 244 are available at: http://www.boem.gov/ak244. Hilcorp Official Awards               Contract Company Name WI Bonus USD Acre Sqkm Lease Sale Award Date Basin   Y02434 Hilcorp Alaska 100 $62,208.00 5,184.26 20.98 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02435 Hilcorp Alaska 100 $37,416.00 3,118.47 12.62 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02436 Hilcorp Alaska 100 $68,376.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02437 Hilcorp Alaska 100 $142,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02438 Hilcorp Alaska 100 $111,606.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02439 Hilcorp Alaska 100 $313,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02440 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02441 Hilcorp Alaska 100 $203,319.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02442 Hilcorp Alaska 100 $111,606.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02443 Hilcorp Alaska 100 $256,500.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02444 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02445 Hilcorp Alaska 100 $474,582.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02446 Hilcorp Alaska 100 $152,019.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet   Y02447 Hilcorp Alaska 100 $152,019.00 5,698.24 23.06 BOEM Sale 244 1-Oct-17 Cook Inlet    Totals     $3,034,815.00 76,681.62 310.32         Source: IHS Markit               © 2017 IHS  

United States, Y02440

Fen 3 was drilled to a TD of 6,540m MD on 27 October 2017 and was suspended in early November 2017 following completion of wireline logging where results indicated 15 intervals of gas measuring 68.9m and 4 interval of gas shows measuring 17.9m were encountered in the target formations. A total of 26.4m of cores (100% recovery) were collected. The gas exploration well was spudded on 16 April 2017 (revised from 26 April 2017) to drill to a PTD of 6,379m (PTVD 6,270m) targeting the Changxing Formation with the objective of gas resources replacement for the Puguang Gas Field. Fen 3 is in the Sinopec operated Daxian-Xuanhan Block in the Sichuan Basin and is geographically located in Sichuan Province, Dazhou City, Xuanhan County, Maoba Town, Danzi Village. <P />

Not Found

Ruche EAA (Dussafu Marine) block, WD 117m, spudded late Jul ’18, TD 3,400m (Dentale), logged 15m oil pay in the Gamba fm + 25m stacked in the Dentale, pressure data + sampling confirm. Forward plans include a sidetrack to appraise the Dentale sands updip + the lateral extent of the Gamba. Borr Norve JU. BWE (op), partner Panoro.

Dussafu Ruche Marin NE 1 (DRNEM) (BWE op 81,67%, GOC 10%, Panoro 8,33%) in Ruche EAA (Dussafu Marine) block, logged 15m oil pay in the Gamba fm + 25m stacked in the Dentale, pressure data + sampling confirm. WD=117m, TD=3 400m (Dentale)

WA-435-P, Carnarvon Basin, WD ca. 100m, TD 5,393m reached, apparent presence of hydrocarbons in the Caley member, preparing to log, GSF Development Driller-1 SS. Quadrant (op), partner Carnarvon.

Phoenix S.-3 appr WA-435-P, Carnarvon Basin, WD ca. 100m, TD 5,393m reached, apparent presence of hydrocarbons in the Caley member, preparing to log, GSF Development Driller-1 SS. Quadrant (op), partner Carnarvon.

It was announced on 19 January 2020 that Turkiye Petrolleri A.O. (TPAO) has been awarded the N39-C onshore exploration licence (Western Arabian Province) on 9 January 2020 for a period of five-year. The licence, covering an area of 617 sq km, is located towards southeast of the country and TPAO will be 100% owner and operator of the licence. TPAO had filed the application on 13 May 2019.

TPAO has been awarded the N39-B, N39-C, N39-A onshore exploration licence (Western Arabian Province) and G17-A, G17-D1,D2,D4, G17-C1,C4, G16-D, G16-C, G16-B onshore exploration licence (Thrace Basin)

AE-0052-2M-Mezcalapa-02 block, onshore Sureste Basin,  P&A dry at TD 5,571m on 24 Nov ’18. PTD was 6,600m target Cret + Jurassic.

Yagual 301EXP (Pemex 100%) deeper-pool wildcat in the AE-0051-5M-Mezcalapa-01 block, P&A dry. TD=5571m.

QP has taken a 25.5% stake from Eni in block A5-A,  5,133 sq km in deepwaters of the Northern Zambezi Basin, WD 300-1,800m. The agreement is subject to clearance by the Mozambican authorities. Partners-to-be Eni (op, formerly 59.5%), QP 25.5%, Sasol 25.5%, ENH 15%.

Qatar Petroleum has entered into an agreement with Eni (->34%, Sasol 25,5%, ENH 15%) to acquire a 25,5% share in block A5A, located in the offshore Mozambique (5133km² in WD=300 to 1800m).

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 will now be deepened to evaluate the D4 horizon. Karish North 1 was spudded on 15 March 2019 and has expected gross drilling costs of USD 25 million. It is being drilled by the “Stena DrillMAX” drillship which is also 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.

Israel, Tanin (I/16)

VIC/P74, 1,007 sq km offshore Gippsland Basin, was secured earlier today for 6 yrs. Hibiscus has 30 days to exercise a 50% farmin option.

Australia, not found

OML 28, central onshore Delta, ops terminated Aug ’18, understood to be significant find with 1.5 Tcfg + 40 MMbc in 17 reservoir intv’s. PTD was 5,000m, target HP deep gas. Hilong rig 27. Note: erstwhile designated Epu Deep-1X. Shell (op), partners NNPC, Total + NAOC.

Nigeria (Girardot Sub-basin (Upper Magdalena B.)) Delta

Rosneft reveals the discovery of the Dolgovskoye Zapadnoye oilfield in the Buzulukskiy block Orenburg (Volga-Urals). Recoverable reserves are pegged at 51 MMbo.

Rosneft has reported an oil discovery at the Buzulukskiy block in Russia's Orenburg region. The company's regional subsidiary Orenburgneft has confirmed recoverable reserves of more than 51 MMbo at the West Dolgovskoye field following the completion of exploration drilling.

Equinor spudded an exploration well targeting the Sputnik prospect in PL 855 on 18 June 2019 using the “West Hercules” S/S. 7324/6-1 was located approximately 30 km northwest of the Wisting discovery and approximately 6 km from the Gemini North discovery, drilled in 2017, in the same licence. The well was targeting sand channels in the Triassic Sto and Snadd formations prognosed at 792 m and 937 m respectively. Gas above oil was expected in the Sto Formation while just oil was expected in the Snadd Formation. It was anticipated that the oil type will be similar to that at Wisting Central. Equinor drilled to 746 m and, for a period of around two weeks, temporarily suspended the well whilst waiting for BOP repairs and maintenance to be completed. On the 31 July 2019 Equinor plugged and abandoned the well, results are awaited. 7325/4-1 was drilled in 2017 targeting the Gemini North prospect. The well had objectives in the shallow Jurassic Realgrunnen Group (743 m) and the Upper Triassic Snadd Formation (812 m). Both were expected to contain oil similar to nearby Wisting. However, instead of the anticpated oil, gas was discovered in the main objective. A 19 m gas column (no GWC) was proven in the Middle Jurassic Sto Formation, which had good reservoir quality, and a 5 m oil column was encountered in a poor quality Snadd Formation. Estimated recoverable reserves were reported to be 14 – 35 Bcfg and 0.6 – 1.9 MMbo and the find was declared non-commercial. Equinor Energy AS operates PL 855 with a 55% interest. It is partnered by OMV (Norge) AS (25%) and Petoro AS (20%).

7324/06-01 (Sputnik) (Equinor 55% op. OMV 25%, Petoro 20%) in PL 855, P&A, results awaited, targeting sand channels in the Triassic Sto and Snadd Fm.

Delek Drilling reported on 21 January 2020 that the JV in the I/14 Leviathan South and I/15 Leviathan North leases is considering the possibility of adding a strategic partner to the asset. The move follows the completion of seismic reprocessing of 3D surveys that were acquired by PGS in 2009 and 2010. As a result of the reprocessing, which was performed by WesternGeco in 2019, a new isolated carbonate buildup target was defined, and two previously identified deep targets had to be reclassified and redefined as a single submarine clastic channel. As such, Delek stated that the JV would consider a partner with relevant knowledge and experience in the specification, drilling and development of an exploration target, specifically a carbonate buildup. <P />Subsequent to the reprocessing, an updated prospective resources report was prepared by Netherland, Sewell & Associates Inc (NSAI) for the identified deep Mesozoic targets. According to the assessment, dated 21 January 2020, unrisked prospective resources for the Mesozoic carbonate prospect range from 26.6 MMbo and 25.4 Bcfg, to 766.6 MMbo and 826.8 Bcfg. For the Early Cretaceous channel prospect, the estimates range from 47.3 MMbo and 45.2 Bcfg, to 813.7 MMbo and 886.8 Bcfg. The estimated geological chances of success are 18% and 19% respectively, with the primary geological risk being trap integrity.<P />Operator Noble Energy and its JV partners had previously targeted a Cretaceous prospect, when they deepened the Leviathan 1 well in 2011/12. The well had a PTD of 7,219m but drilling operations were suspended after reaching a depth of 6,517m due to high well pressure and mechanical restrictions of the well-bore design. Subsequent plans to drill another deep well in 2014/15 were postponed due to regulatory uncertainties at the time.<P />Noble Energy Mediterranean Ltd operates the Leviathan leases with a 39.66% interest and is partnered by Ratio Oil Exploration (1992) Ltd Partnership (15%) and the Delek Group through its subsidiary Delek Drilling Ltd Partnership (45.34%).

Delek Drilling reported on 21 January 2020 that the JV in the I/14 Leviathan South and I/15 Leviathan North leases is considering the possibility of adding a strategic partner to the asset. The move follows the completion of seismic reprocessing of 3D surveys that were acquired by PGS in 2009 and 2010.

Deltic Energy Plc (formerly Cluff Natural Resources Plc) is looking for interested partners to farm-in to licence P2352 (blocks 22/24f and 22/25g) which contains the Dewar prospect. Cluff was awarded 100% interest in the licence in the 30th Offshore Licensing Round. Dewar is interpreted as a Forties Sandstone target with differential compaction around the channel causing a 4-way dip closure and an AVO anomaly associated with the channel. It is estimated that the prospect holds P10 STOIIP volumes of 272 MMbo and P50 prospective resources of 39.5 MMbo. The prospect has been assigned a geological chance of success of 41%. Located in around 90 m of water, a well could be drilled with a heavy duty jack-up rig. Well costs are thought to be in the region of GBP 17 million (incl. 15 day well test). As of May 2020 it was confirmed that the opportunity is still available. Deltic Energy mention that if the prospect was successful then it could be tied back to the BP operated ETAP Central Processing Facility located approximately 5 km to the north-west of the prospect. From this the Dewar project has been estimated to have a post-tax NPV (10) of GBP 555 million and a post-tax project IRR of 123% in the P50 prospective resources case. The acreage in the licence hosts the 22/24c-11 Tesla discovery made in 2009. Tesla is an HP/HT non-commercial gas condensate discovery which was made in the Jurassic Pentland Formation. Interest in the licence is held solely by Deltic Energy Plc.

United Kingdom (Central Graben Province) P2352 op. by CLUFF NR (100%), Deltic Energy Plc (formerly Cluff Natural Resources Plc) is looking for interested partners to farm-in to licence P2352 (blocks 22/24f and 22/25g) which contains the Dewar prospect. Cluff was awarded 100% interest

ENEVA SA is assumed to have plugged and abandoned dry the 1-ENV-BL103N-MA (1-ENV-002-MA) new-field wildcat (NFW) in the PN-T-103 block in early-April 2019.  The ANP has reported no show reports filed for the well through mid-April. The NFW was spudded on 20 March 2019.   The NFW had a proposed total depth (PTD) of 2,229 m. The Devonian Cabecas Formation and the Mississippian Poti Formation were the primary targets.   The NFW is located in the central area of the block approximately 19.6 km south-east of the 1-PGN-BL103E-MA (1-PGN-028-MA) the operator plugged and abandoned in October 2018. ENEVA SA has 100% working interest in the ANP Round 13 contract awarded on 23 December 2015.

Brazil, PN-T-103

It was reported in February 2020 that United Energy Pakistan (UEP) has been awarded the Tajjal D&PL (Development & Production Lease) over the Tajjal 1 gas discovery in district Khairpur of Sindh province. The award date has been backdated to 5 October 2015. The lease, which covers 28 sq km area, has been excised from the Gambat EL. UEP holds 27.63% interest along with operatorship in the acreage, with Pakistan Petroleum Ltd (PPL) and Eni Agip Exploration & Production Ltd each holding 23.68% stake and Government Holdings (Pvt) Ltd (GHPL) holding the remaining 25% equity. The Tajjal 1 well was drilled by OMV (Pakistan) Exploration and it was reported to have encountered 21 m of net gas pay in three horizons at depths between 3,600-3,800 m on reaching a final TD of 3,845m in the Cretaceous in April 2007 - test results indicating the main interval to be capable of flowing approximately 20 MMcf/d. The actual flow potential and size of the field, however, will only be determined after a long-term test / appraisal - a total of 197.45 sq km 3D seismic subsequently being acquired over the acreage between December 2007-February 2008. The application for development & production lease was submitted by OMV in March 2011. UEPL had acquired the acreage from OMV following the signing of USD 193 million (EUR 157 million) agreement on 28 February 2018 under which OMV sold its upstream business in Pakistan to United Energy. The transaction was completed on 28 June 2018.

United Energy Pakistan (UEP) has been awarded the Tajjal D&PL (Development & Production Lease) over the Tajjal 1 gas discovery in district Khairpur of Sindh province.

By 24 September 2018, the Public Survey Commission had greenlight Total's application for up to five exploration wells on its Guyane Maritime Exclusive Exploration Licence (EEL), one of these wells to be drilled on the Nasua prospect. Back in March 2018, Total were seeking to farm-out WI in the Nasua prospect to a select number of companies active in Guianas Margin (Guyana, Suriname and French Guiana), and were looking for a partner to help it drill what it has described as a "giant oil prospect". In water depths of around 2,000m the well, known as Nasua-1, could spud as early as 2018-2019 to target stacked horizons at a cost of up to US$ 150-200 million and has been enabled by Total securing an extension for the Guyana-Suriname Basin block. With progress to the spudding of Nasua-1 continuing, Total could potentially still be seeking to farm-out WI to a partner, may already be in discussions with a potential farm-in partner, or be happy to continue to shoulder the cost of exploration alone should a farm-in partner not materialise.On 14 September 2017, the French Minister of Ecology and Sustainable Development and the Minister of Economy and Finance extended by decree the EEL for a further three years. The decree was published in the Journal Official de la Republique Francaise (JORF) 0221 on 21 September 2017. French Guiana is a Department of France. While then-operator Tullow made the GM-ES-1 (Zaedyus-1) discovery in 2011 (72m of net oil pay in two turbidite fan systems), Shell's follow up programme in 2012-2013 failed to find any commercial hydrocarbons. Shows were detected in the GM-ES-2 (Zaedyus-2) appraisal and the GM-ES-3 (Priodontes 1) NFW. The GM-ES-5 appraisal and GM-ES-4 Cebus-1 NFW were also dry. With Total throwing out the welcome mat in March 2018, the most likely farm-in partner were thought to be a larger company with the expertise and financial wherewithal to cover the drilling programme. Several companies like ExxonMobil, which discovered the Liza Field in offshore Guyana, Tullow and Repsol of Spain are active in the Guyana-Suriname Basin. Brazil's Foz do Amazonas Basin could yield some leads as well. A 2017 French decree assigned Total operatorship and 45% WI after Shell activated its retreat from the block in February 2016. That resulted in Total holding 92.5%. In the extension period, Northpet Investments Ltd (Northpet), was to increase its interest from 2.5% to 7.5% WI. Northpet is owned by Vermeer Exploration BV (Vermeer). This is 49% Hague and London Oil plc (HALO) and 51% management & founding shareholders of HALO. However, in April 2017, Northpet submitted to withdraw from the block, which will give Total 100% WI subject to government approval.

Total were seeking to farm-out WI in the Nasua prospect to a select number of companies active in Guianas Margin (Guyana, Suriname and French Guiana), and were looking for a partner to help it drill what it has described as a "giant oil prospect".

Orenburg, Volga-Urals, seismically-defined structure, tested 283 bo/d assumedly from the U. Tournaisian Cherepetskiy fm. The Kornilovskoye field lies in the Kornilovskiy block (licence ORB03168NR).

Kornilovskaya 2 (OrenburgNeft 100%), in the Kornilovskiy block (licence ORB03168NR), lies seismically-defined structure, tested 283 bo/d assumedly from the U. Tournaisian Cherepetskiy fm.

Pakistan Petroleum Ltd (PPL) reported on 28 April 2020 in the quarterly report that it had re-entered the Margand X-1 (also called Mor Gandh X-1) discovery well within the Margand 2866-4 EL (Kirthar Fold Belt) onshore licence and it was deepened to a TD of 5,100 m before initiating testing in a deeper section of Jurassic Chiltan Formation. It was subsequently reported to have flowed around 15 MMcfg/d through 128/64" choke during testing along with 120 b/d of water. PPL had earlier reported the gas discovery in this well on 23 December 2019 after drilling to a TD of 4,500 m. A drill stem test (DST) was carried out and it flowed 10.7 MMcfg/d and 132 b/d of liquids through 64/64" choke with a well head flowing pressure (WHFP) of 516 psi from the Chiltan Limestone Formation. PPL was conducting the study about the nature of liquid which is assumed to be condensates. It was reported that the well had a potential to flow at higher rates through acid stimulation. This was the first discovery in Kalat Plateau, opening up a new area for hydrocarbon exploration. Margand X-1 was the first well in the Margand EL block and it was spudded on 30 June 2019 using the “WDI-812” land rig with a prognosed TD of 4,500 m. Prior to initiating DST in early December 2019, PPL conducted wireline logging and modular dynamic testing which suggested the presence of hydrocarbons. Margand X-1 was drilling at 1,168 m depth during mid-July 2019, reached 1,743 m by the end of the month and progressed to 2,116 m depth during mid-August 2019. It was drilling at 2,800 m depth by the end of August, reached 3,488 m by mid-September and 3,669 m depth during late September 2019. It was drilling at 3,703 m depth in October 2019, progressed to 4,279 m by mid-November and reached the final TD of 4,500 m in late November 2019. Margand EL covers an area of 2,484 sq km and is located in Balochistan province. PPL currently hold 100% interest in the block. PPL reported in the 2H 2018 report in March 2019 that it has acquired 2,434 line km gravity and magnetic data in the block. The company had earlier acquired 261 line km of 2D seismic (dynamite source) in the acreage between December 2017 to April 2018 using the BGP 9501-B seismic crew.   Background Information PPL (operator), along with OMV, were awarded the Margand exploration license, with the Petroleum Concession Agreement (PCA) having been signed on 28 February 2014. The equity split at the time of award was as follows: PPL (50%, operator) and OMV (50%). It was subsequently announced in January 2017 that OMV has farmed out from the block assigning its full 50% interest to PPL, effective 30 June 2016. PPL was granted a 12-month extension to the Phase-I of initial term for Margand EL from 28 February 2017 to 27 February 2018. It was followed by a further 12-month extension to the Phase-I from 28 February 2018 to 27 February 2019. PPL was subsequently granted the renewal with licence entering into two-year Phase-II of initial term with effect from 28 February 2019.

Pakistan (Kirthar Fold Belt) Margand X-1 op. by PPL (100%) in Margand 2866-4 EL block, gas discovery in the Bajocian-Callovian Chiltan Fm, DST'd 10,7 MMcfg/d + 132 b/d liquids [1" choke], could contain 1 Tcf of gas in new play type, operator is claiming to have made the nation’s largest discovery in more than a decade although analyst sources caution it is premature to make such a boast.

On 7 February 2018, Gazprom Neft reported the discovery of the Novozarinskoye oil field in Orenburg Oblast (Volga-Urals Basin). The company mentioned reserves of more than 11 MMt (about 80 MMbbl) of oil for the field. The discovery is located within the 349 sq km Uranskiy block operated by Gazprom Neft Orenburg (Gazprom Neft subsidiary). In 2017, Gazprom Neft Orenburg discovered the Novosamarskoye oil field within the Uranskiy block. The field holds reserves of more than 8 MMt (about 60 MMbbl) of oil in Famennian carbonates.

Russia (Volga-Urals B.) ? op. by GAZPROM (100.0%) in Uranskiy block

Jersey Oil and Gas (JOG) announced on 20 May 2020 that it has completed the acquisition of Equinor's 70% interest and operatorship in licence P2170 (Blocks 20/5b and 21/1d). The deal originally announced on 27 January 2020 stated that the acquired interest is in return for two milestone payments and associated royalties with the Verbier discovery. Under the terms of the deal JOG will pay USD 3 million once the Field Development Plan has been sanctioned by the OGA. A further payment of USD 5 million will be paid once Verbier comes onstream. With regards to the royalties, Equinor will receive (net 70%) payments on the first 35 MMbo produced. JOG is hoping to push towards select gate in Q3 2020 as it looks to develop the Greater Buchan Area which is comprised of the Buchan redevelopment project, Verbier, J2 discovery and Glenn. Following the development concept selection process is completed JOG will launch its farm-out process for the project. The company believes that its acreage contains 120 MMboe of discovered mean recoverable resources and further potential within identified mean prospective resources. It is estimated from JOG that Buchan (Devonian) alone contains over 80 MMbo (recoverable) with further potential in a shallower reservoir (Andrew sands) sat above the main Buchan reservoir. Buchan is thought to be the main new hub for the area development. The development of the J2 discovery will run concurrently with Buchan. J2 is thought to be made up of two accumulations, approximately 20 MMbo present in the Sgiath sandstone Formation and further recoverable oil in Upper Jurassic sands which are thought to be a potential eastern extension of the Verbier discovery. Glenn is located 15 km to the east of Buchan and could be a potential tie-back to Buchan. Glenn is a faulted horst with oil sat within Upper Jurassic, shallow marine Sgiath Formation sands. It is thought that Glenn could hold up to 14 MMbo (recoverable). The Verbier discovery, which was unsuccessfully appraised by Equinor with JOG as a partner in 2019 is thought to contain approximately 25 MMboe. It is thought that a large part of the mapped area of the Verbier discovery located to the northwest of the recent appraisal well remains untested along with further additional resource potential thought to sat in a deeper horizon beneath Verbier. JOG also has a prospect called Cortina in this area and from the recent acquisition of the 2018 PGS Geostreamer 3D data this additional potential will be further reviewed. Following completion of the deal, interest in P2170 is held by Jersey Petroleum Ltd (88% + operator) and CIECO V&C (UK) Ltd (12%).

Jersey has completed the acquisition of 70% + operatorship in P2170 / blocks 20/5b + 21/1d from Equinor in exchange for payment (USD 3 & 5 MM linked to Verbier clearance + production) + royalty based on oil production from the Verbier U. Jurassic reservoir. Jersey (op) 70%, Equinor 18%, CIECO 12%

in late October 2017, Apache completed the Hydra East 1 exploration well in the Shushan C-12 West block after the well yielded 1,963 bo/d from the Kharita Member. The well was spudded on 28 August 2017 using L/R “EDC-17” and was drilled to a TD of 4,348 m in the Upper Safa Unit. It had a planned TD of 4,115 m and objectives in the Alam el Bueib 6 Unit and. Apache is the operator of the 15 sq km Shushan C-12 West Block. The JV comprises Apache Oil Egypt (67%) and Sinopec International Petroleum E&P Corp (SIPC) (33%). Background information On 24 January 2008 the Hydra 1 wildcat discovered gas and condensate after a drill stem test in the Jurassic Lower Safa Formation which flowed 41.6 MMcf/d and 1,313 bc/d. the Hydra field was put on production in 2013 from the Alam El Bueib 6 and Lower Safa reservoirs. In late March 2016, Apache completed as a gas producer its sidetracked development well Hydra 2ST in the Hydra field, Shushan C-12 West Block The well was re-entered on 25 January 2016 using L/R “EDC-57” and was deepened to a TD of 3,902 m in the Zahra Member of the Khatatba Formation. It had with the objective to reach the Alam el Bueib 6 Unit and a PTD of 4,007 m. Initially the Hydra 2 appraisal well was spudded on 13 June 2008 and drilled to a TD of 3,328 m before being p&a as a dry well. The field has been developed by 3 development wells with AEB-5 and Lower Safa reservoirs as objectives.        

Hydra East 1 op. by Khalda (Apache 33,5%, Sinopec 16,5%, EGPC 50%, carried) in Shushan C-12 West block susp. after testing 1 963 bo/d from the Kharita fm. TD=4348m.

On 8 June 2019, it was announced that Arar Petrol ve Gaz Arama Uretim Pazarlama A.S has been awarded the O22-A onshore exploration licence in the Taurides and Anatolides Fold Belt towards southwest of the country on 28 May 2019. The licence covers around 619 sq km area and it has been granted for a five-year term with an expiry date of 27 May 2024. Arar Petrol is 100% owner and operator of the licence. Arar Petrol had filed the application for O22-A exploration licence on 16 October 2018.

Arar Petrol ve Gaz Arama Uretim Pazarlama A.S has been awarded the O22-A onshore exploration licence in the Taurides and Anatolides Fold Belt towards southwest of the country

Oil Search has accepted an offer of award for offshore retention lease APRL 41 (undeveloped Flinders + Hagana field area), 507 sq km on the Fly River Platform. The RL will provide Oil Search with a 5-yr period to assess commerciality (extendable). The formal award remains subject to govt approval.

Papua New Guinea, APRL 41

The latest on the planned PCECP round (Philippines Conventional Energy Contracting Programme) is for an Oct ’18 launch.  14 bidding areas on offer. Details from the DoE, contact email [email protected].

Philippines, not found

NC98-P-002 field area, Sirte Basin / Zelten Platform, re-entered Sep '19 with PTD 4,226m, P&A at TD 3,911m in Feb '20, NWD rig 10. Target Lower Nubian sst.

P-003ST-NC098 appr C98-P-002 field area, Sirte Basin / Zelten Platform, re-entered Sep '19 with PTD 4,226m, P&A at TD 3,911m in Feb '20,Target Lower Nubian sst.

It was reported in December 2018 that Saif Energy Ltd has assigned its full 10% interest in Bannu West 3370-13 EL (Potwar Basin) onshore concession to Zaver Petroleum Corporation Ltd (ZPCL) and it would be effective retrospectively from 8 June 2018. The licence covers an area of 1,230 sq km and is located in the FATA administrative region of the country. MPCL is the operator of this licence and the revised equity spilt is as follows: MPCL (55%, operator), Oil and Gas Development Company Ltd (OGDCL) (35%) and ZPCL (10%). MPCL initiated 3D seismic acquisition (dynamite/vibroseis source) programme in the block in July 2018 and a total of 216 sq km was acquired by the end of the November 2018 – the survey was continuing although the company has already exceeded the planned target of 150 sq km 3D acquisition.     Background Information The licence was awarded to Tullow Pakistan (Developments) Ltd (85%, operator) and Tullow Pakistan (Operations) Private Ltd (15%) on 27 April 2005 and the work programme for the initial three year exploration phase (with a minimum financial commitment of US$13.16 million) is believed to include G&G studies, the acquisition of 150 sq km 3D seismic and the drilling of one exploration well. Tullow Pakistan (Developments) Ltd assigned a 35% working interest to OGDC with effect from 12 September 2005, with a further 10% also assigned to Saif Energy Ltd. It is understood that Tullow Pakistan (Operations) Private Ltd also assigned a 5% working interest to OGDC at the same time, as a result of which the revised equity split was as follows - Tullow Pakistan (Developments) Ltd (40%, operator), OGDCL (40%), Saif Energy Ltd (10%) and Tullow Pakistan (Operations) Private Ltd (10%). Tullow Pakistan (Operations) Private Ltd subsequently assigned its entire 10% working interest to Mari Gas Co Ltd (MGCL) with effect from 24 May 2006, as a result of which the revised equity split is as follows - Tullow Pakistan (Developments) Ltd (40%, operator), OGDCL (40%), Saif Energy Ltd (10%) and Mari Gas Co Ltd (MGCL) (10%). Mari Gas Co Ltd (MGCL) subsequently changed its name to Mari Petroleum Company Ltd (MPCL) with effect from 19 November 2012. The licence was granted a one year extension to the first contract year with effect from 1 September 2007 - a one year extension having previously been granted. Tullow was granted an additional one year extension to the first contract year of the license with effect from 1 September 2008, followed by a further 12 month extension to the first contract year with effect from 1 September 2009. Tullow was granted an additional one-year extension to the first contract year of the licence concession with effect from 1 September 2010. It was followed by a further two-year extension effective 1 September 2011. Tullow was granted an additional four-year extension to the first contract year of the Bannu West EL from 1 September 2013 to 31 August 2017. It was reported in Tullow Oil’s 2016 Financial Results that Tullow Pakistan (Developments) Ltd had agreed in May 2016 to sell its 20% interest and transfer operatorship in Bannu West EL to MPCL. MPCL subsequently announced on 28 March 2017 that the government has granted approval for the operatorship of Bannu West EL. The company also announced acquiring 5% interest from Oil and Gas Development Company Ltd (OGDCL) in the block and as a result, effective 20 March 2017, MPCL became the operator of block with revised equity split as follows: MPCL (35%, operator), OGDCL (35%), TPDC (20%) and Saif Energy Ltd (10%). MPCL announced on 19 July 2017 that it signed the Head of Terms (HoT) agreement with Tullow Pakistan (Development) Ltd for acquiring Tullow’s entire working interests in three onshore blocks in Pakistan – Bannu West, Block 28 and Kalchas blocks. It was subsequently reported in early July 2018 that MPCL acquired Tullow’s full 20% working interest in the Bannu West EL with effective date as 7 June 2018 and the revised equity split was as follows: MPCL (55%, operator), OGDCL (35%) and Saif Energy Ltd (10%). MPCL acquired 105 line km 2D seismic (dynamite / vibroseis source) in the block using the Mari Seismic Unit’s “MSU-1” seismic crew. The survey was initiated in March 2018 with a plan of acquiring 99 line km 2D and it was completed in April 2018.

Saif Energy Ltd has assigned its full 10% interest in Bannu West 3370-13 EL (Potwar Basin) onshore concession to Zaver Petroleum Corporation Ltd (ZPCL)

Vermilion Energy has entered into an arrangement agreement to acquire a private southeast Saskatchewan producer ('Privateco') for total cash consideration of $90.8 million.   Under the terms of the Arrangement, Vermilion has agreed to acquire all of the issued and outstanding common shares in the capital of Privateco, including all Privateco Shares issuable, in accordance with the terms of existing grants of options or warrants, prior to the effective time of the Arrangement, and assume all outstanding debt of the Privateco.  The Purchase Price will be funded from Vermilion's existing credit facilities.  The Board of Directors of Privateco has unanimously approved the Arrangement and recommended that Privateco shareholders vote in favour of the Arrangement.  The Arrangement remains subject to customary closing conditions, including receipt of applicable court, Privateco shareholder and regulatory approvals, and is expected to close on or about February 15th, 2018.   The Acquisition is comprised of high netback, low base decline, light oil producing fields in the Sinclair and Fertile areas, straddling the Saskatchewan/Manitoba border, approx. 55 km northeast of Vermilion's existing operations in southeast Saskatchewan.  The Assets include approx. 42,600 net acres of land (approx. 100% W.I.), three oil batteries, and associated pipelines, along with the necessary water infrastructure to facilitate the existing seven waterflood projects and initiate up to eight additional waterflood projects.  The Assets produced approx. 1,150 bbl/d of 40° API oil during Q4 2017, sourced from the Bakken/Three Forks formation.  All of the current production and infrastructure will be 100% owned and operated by Vermilion.  Total proved plus probable ('2P') reserves attributed to the Assets at December 31, 2017 are 6.7 mmboe (100% crude oil), based on an independent evaluation by GLJ Petroleum Consultants.  The Assets demonstrate a low base decline rate of approx. 15% at present, and are expected to have even lower decline rates over time.  Areas under waterflood have decline rates of less than 10% with certain areas of flat or increasing production.  Approx. 45% of the production comes from active waterflood projects, leaving significant opportunity to expand the waterflood. The Acquisition is accretive on a fully-diluted per share basis for all pertinent metrics including production, fund flows from operations, reserves and net asset value.  Making no deduction for undeveloped land value, transaction metrics equate to $13.55 per boe of 2P reserves, and $79,000 per flowing barrel of production.  Based on 2018 WTI strip pricing of US$61.83/bbl, the operating netback for the Assets is estimated at approximately $51.80 per boe.  Using the 2P finding, development and acquisition cost (based on the reserves in the GLJ report) of $19.02 per boe (including future development capital), the Assets are expected to deliver a 2P after-tax fund flows recycle ratio of 2.7 times.  Using the same strip pricing assumption, the total Acquisition cost (including assumed debt) is approximately 5.1 times estimated annualized 2018 fund flows from operations ('FFO'), after deducting incremental interest expense.  Calculated on a debt-adjusted cash flow basis, the total Acquisition cost (including assumed debt) is approx. 4.6 times.  Pro-forma the acquisition, our year end 2018 debt-to-FFO ratio is forecast to be 2.0 times based on January 11, 2018 strip pricing, as compared to 1.9 times prior to the acquisition. The Acquisition complements our current southeast Saskatchewan operations and will be managed out of our existing field office in the area.  Furthermore, the Acquisition aligns with our sustainable growth-and-income model by targeting low risk assets with high netbacks, strong free cash flow generation, low base decline rates and strong capital efficiencies on future development.  As a result of the Acquisition, and based on a mid-February closing date, we are revising our 2018 production guidance to between 75,000 and 77,500 boe/d (from 74,500 to 76,500 boe/d previously).  We are also increasing our 2018 capital budget to $325 million (from $315 million previously) to reflect additional capital activity on these assets planned for the second half of the year.  Original article link Source: Vermilion Energy

Vermilion Energy has entered into an arrangement agreement to acquire a private southeast Saskatchewan producer ('Privateco') for US$91 MM. Acquisition is comprised of high netback, low base decline, light oil producing fields in the Sinclair and Fertile areas.

Rey Resources Ltd and Doriemus Plc entered into a farm-in agreement in March 2019, which will see Doriemus acquire interest in licence L 15, located in the Canning Basin.  Doriemus initiated the farm-in agreement on 5 March 2019. Doriemus is to acquire 50% interest in L 15 under the farm-in agreement. To acquire 50% interest, and operatorship, in L 15 Doriemus must fund up to AUD 1 million in development costs associated with bringing the Kora West field back into production over the first 12 months. Doriemus reported that funds were already available prior to completion of due diligence. Doriemus reported on 15 February 2019 that the interest sale of Horse Hill Developments, UK, has also provided strength to its balance sheet as the West Australian farm-ins progress. Additional spend could also be raised from a combination of cash reserves and production revenue from its 20% interest in the Lidsey oil field, located in the Wessex Basin, UK. L 15 is 100% owned by Gulliver Productions Pty Ltd, a wholly owned subsidiary of Rey Resources, and covers an area of 165 sq km over the Kora West field. The field was discovered in 1984 and produced around 20,000 bbl oil between 1989 and 1992. With 2P recoverable reserves of nearly 400,000 bbl, Doriemus plans to bring the Kora West field back into production by around May 2019. Doriemus reported on 15 February 2019 that it had completed its due diligence relating to the acquisition of interest in Rey Resources’ L 15 (West Kora) licence. The company planned to seek finalisation of the previously reported farm-in agreement and joint operating agreement.  Doriemus first announced on that it had entered into a farm-in deal with Rey Resources 31 December 2018, for two Canning Basin permits, exploration permit EP 487 (Derby Block) and production licence L 15 (West Kora). The companies signed two independent binding letters of intent for Doriemus to acquire 50% interest and operatorship in both assets. In Ep 487, the farm-in agreement was terminated in August 2019, after Doriemus failed to meet required funding conditions for the farm-in. L 15 was awarded on 1 April 2010. Should the farm-in be completed, interests will become: Doriemus Plc (50% + operator) and Gulliver Productions Pty Ltd (50%). Until this time, Gulliver Productions remains as operator with 100% interest. Doriemus currently holds minority, non-operated interest in three licences in onshore United Kingdom. Upon completion of the deal with Rey will see Doriemus enter Australia for the first time.

PL 216 (Dalwogan), 230 sq km in the Taroom Trough, Bowen-Surat Basin, was awarded for CBM ops on 23 Jul ’19 for 30 years

Cairn confirmed in its full year announcement in March 2020 that it has agreed two deals for licences P2379 and P2380 with Shell. Shell is to acquire a 50% interest in licence P2379 which contains the Diadem prospect and is a firm well commitment. In exchange for this interest Cairn will acquire a 50% interest in licence P2380 which has a firm well commitment on the Jaws prospect. The Jurassic Fulmar sandstone play is prolific in the area and if the wells are successful then they could be tied into the Nelson facilities. The deals are pending OGA approval and it is likely that the wells will be drilled in 2H 2020 / 1H 2021. The commitment well for Jaws is required to be drilled to a depth of 3,730 m or the base of the Upper Jurassic. P2380 was awarded in the 30th Offshore licensing round which focussed on ‘mature’ areas of the North Sea and comprises of just one block – 22/12d. Any potential discoveries could be used to extend the field life at Nelson. Shell also picked up licence P2377 in the 30th Round which also contains a firm commitment well on a prospect known as Orlov and is within reach of a tie-back to Nelson. In September 2019 Zennor Petroleum and ONE-Dyas pulled out of licence P2379 leaving Cairn as the sole participant. The licence comprises of four blocks – 22/11b, 22/12b, 22/16b and 22/17c and contains three discoveries 22/11b-3 (Lima), 22/12a-10 (Phoenix) and 22/16-6 (Dalziel). The first of the three discoveries was 22/12a-10 (Phoenix) back in 2004. The discovery was made by Shell as a near field exploration project for the Nelson facilities. The discovery was appraised in 2010 with well 22/12a-12 which confirmed oil bearing sands within the Forties Sandstone Member within a relatively simple and low risk 4-way dip closed structure. A sidetrack of the appraisal well 22/12a-12Y was kicked-off and penetrated the reservoir outside of the structure and did not encounter any hydrocarbons. 22/11b-13 (Lima) was discovered in 2008. The well targeted three Jurassic pods. Of the three pods, only one (Fulmar 1) contained oil which is stratigraphically trapped within thin sandstones pinching out before the pod. The most recent discovery was 22/16-6 (Dalziel) in 2015. This was drilled by ENGIE targeting the Upper Jurassic Fulmar prospect. It encountered oil and tested in excess of 8,000 boe/d. Following completion of the deals interest in the licences will be held by 50% each between Cairn and Shell.

Cairn is exchanging a non-operating 50% stake with Shell in so far wholly-owned P2379 (Diadem prospect) in return for 50% in Shell’s P2380 (Jaws prospect). Partnership to become 50:50 in both.

On 8 June 2019, it was announced that Era Enerji, Enerji Servis Hizmetleri ve Petrol Tic. Ltd. Sti. (Era Enerji) has been awarded the M32-C4 onshore exploration licence in Koniya Basin on 28 May 2019. The licence covers an area of 153 sq km and it is located in Koniya and Nigde provinces, towards the south-central part of the country. Era Enerji is the 100% owner and operator of the licence which has been granted for a five-year term with an expiry date of 27 May 2024. The company had applied for the M32-C4 licence on 1 August 2019, which was its second application for the acreage. Era Enerji had earlier applied for the M32-C3,C4 licence in February 2018, which covered a larger area of 306 sq km area and it was rejected by the government on 3 July 2018.

Era Enerji has been awarded the M32-C4 onshore exploration licence in Koniya Basin on 28 May 2019. The licence covers an area of 153 sq km and it is located in Koniya and Nigde provinces, towards the south-central part of the country. Era Enerji is the 100% owner and operator of the licence which has been granted for a five-year term with an expiry date of 27 May 2024. The company had applied for the M32-C4 licence on 1 August 2019, which was its second application for the acreage. Era Enerji had earlier applied for the M32-C3,C4 licence in February 2018, which covered a larger area of 306 sq km area and it was rejected by the government on 3 July 2018.

Lakwa field area + ML, Assam Shelf, TD 4,925m, susp. oil end Apr '20, GTV-200 rig.

India (Assam Shelf) Lakwa-BD appr in Lakwa field area + ML, Assam Shelf, TD 4,925m, susp. oil end Apr '20

On 26 September 2018 the new TFT concession contract signed between Repsol, Total, Sonatrach and Alnaft was officially approved by the council of ministers. On 11 June 2018 Total reported that it signed a new concession contract with Sonatrach, Repsol and Alnaft on the Tin Fouye Tabankort (TFT) field, Illizi Basin, south-east of Algeria. The new contract will become effective upon the approval by the Algerian authorities and replace the existing one which is due to expire in 2019. It will allow to continue production at the field for another 25 years. Interests in the new concession are: Sonatrach 51%, Total 26.4% and Repsol 22.6%. The partners will carry out drilling and investments required to develop additional reserves estimated at more than 250 million barrels of oil equivalent including around 1 Tcf of dry gas. These investments of around 324 million USD will allow to maintain the production of the field which is currently over 80,000 b/d of oil equivalent for six years. It is planned to drill 11 new production wells. The new concession is a result of a framework agreement signed last year. In April 2017 Sonatrach and Total signed a framework agreement strengthening the existing partnership between the two companies. The agreement was signed by Sonatrach’s CEO Abdelmoumen Ould Kaddour and Total’s CEO Patrick Pouyanne. It established a new contractual framework for the Timimoun gas development, enabled continued joint operations on the TFT gas-condensate field, provided for the joint development of a new project and arranged a settlement of outstanding differences between the two companies. Background information The TFT field is a giant gas and oil field and is considered as one of the largest hydrodynamic trap in the world. The field was discovered in February 1961, with new-field wildcat Tin Fouye 1. The two main reservoirs are the Upper Ordovician Gara Louki Formation (oil & gas) at a depth of 1,400 - 1,500m and in the Lower Emsian F6 Sandstone Unit (oil) at 750m. The main Gara Louki reservoir has been subdivided into two superimposed geological units which are in vertical pressure communication. The upper unit has a coarser facies and extends over the whole of the reservoir with a constant thickness of between 10 and 20m from west to east. The lower unit is more laterally discontinuous with rapid lateral facies changes and displaying much poorer reservoir characteristics. Gross reservoir thickness of the Gara Louki Formation varies from 0 - 59m. Oil production started in 1961 from the F6 sandstone reservoir, but output went into a gradual decline. Water injection began in 1980 in the Ordovician reservoir. On 28 January 1995, Sonatrach, Total and Repsol announced that they had signed a 20 year production-sharing contract for the development of the gas, condensate and LPG reserves of the TFT field. Commercial gas production started in March 1999.

Algeria Repsol SA, TOTAL SA sign a new concession contract for the Tin Fouye Tabankort field

Timor Leste’s licensing round opens on Wednesday under the authority of the ANPM (Autoridade Nacional do Petróleo e Minerais) for on- & offshore acreage during the Oil and Gas Summit (3-4 Oct ’19) in Dili. 18 areas are ready, details awaited.

East Timor, not found

Madagascar Oil Ltd is looking for a partner to share the risk of drilling an exploration well in Block 3104 in the Morondava Basin Madagascar Oil holds a 100% interest in the licence. The company has a USD 20 million three-well drilling programme that it expects to start in June 2019. The Tsimiroro lights oil prospect has an estimated recoverable resource between 85 MMbo to over 1 Bbo. The prospect is located south of the heavy oil Tsimiroro field and north of the Manadaza light oil discovery. The wells will target the 200 m thick Lower Sakamena sandsatone expected at a depth of 700 m. Interested parties can contact Ian Cross at Moyes & Co: [email protected] +65 9776 0753 The manadaza discovery well was sourced by the Middle Sakamena shales and contains light oil of 41° API. The well was drilled in 1991 by Shell. The Tsimiro heavy oil field is located within the same licence and is also sourced by the Milldes Sakamena shales. Madagascar Oil announced in December 2018 plans to restart commercial operations at the field. Initial production will start with 4,000 b/d and production will be extend to 35,000 b/d in a second phase.

Madagascar Oil Ltd is seeking partners to drill exploration wells in Block 3104

In October 2019, Mediterra Energy plugged and abandoned the new field wildcat Khamsin 1 in the Sudr (Dev) block, Gulf of Suez Basin. The well was spudded on 27 September and drilled to a TD of 1,180 m in the Serravallian Belayim Formation. Planned TD was at 4,270 m in Eocene limestone series. The Sudr (Dev) block was granted to Mediterra Energy Corp in November 2016. It covers an area of 63 sq km and includes the Sudr and Sudr 27 oil fields, discovered in 1947 and 1951, respectively. Mediterra Energy is a JV between EGPC and the Canadian-based Mediterra Energy Corp.

Khamsin 1 nfw. (Mediterra Energy Corp 100%) in the Sudr (Dev) block, P&A, Results are not available. Planned TD was at 4270 m in Eocene limestone series.

On 14 January 2019 the Dutch Ministry reported that NAM sold its participation in the Andel Vb licence to Vermilion and Parkmead effective from 20 December 2018. It is believed that NAM’s interest was split equally between Vermilion and Parkmead. The licence contains two blocks which are located about 20 km east of the city of Rotterdam. The licence contains part of the Kerkwijk gas field discovered by Kerkwijk 1 in 1988. The field never produced. Its reservoir is below a depth of 2,700 m in the Bunter Group. Interest is the Andel Vb licence are held by Vermilion Energy Netherlands BV (37.5% + operator), Parkmead (E&P) Ltd (22.5%) and Energie Beheer Nederland BV (40%).

Netherlands (West Netherlands B. (Anglo-Dutch B.)) Kerkwijk

Bayerngas will be withdrawing from upstream activities onshore Germany and is selling its Reudnitz holdings SE of Berlin in Brandenburg to newly-formed domestic co. Genexco. Involved are 100% in the Reudnitz, Reudnitz Nordost and Reudnitz Südost blocks, total 554 sq km, the transfer of which is expected to be concluded late 2017.

Bayerngas will be withdrawing from upstream activities onshore Germany and is selling its Reudnitz holdings SE of Berlin in Brandenburg to Genexco. Involved are 100% in the Reudnitz, Reudnitz Nordost and Reudnitz Südost blocks, total 554km².

An auction is planned 29 Nov '19 for 30-year rights to the Khambateyskiy block, 343 sq km of state significance in the Yamal-Nenets AO, W. Siberia. Application deadline 25 October. Khambateyskiy lies on the SE Yamal Peninsula + Ob Estuary and contains the Khambateyskoye gas-cond discovery. Starting price USD 28 MM. Contact Rosnedra, email [email protected].

An auction is planned 29 Nov '19 for 30-year rights to the Khambateyskiy block, 343 sq km of state significance in the Yamal-Nenets AO, W. Siberia. Application deadline 25 October.

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

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

Ref. DEA 31 Jul ’18, Perenco has completed the 49% farmin from Petrofac in the latter’s Mexico assets – including Santuario (Sureste  onshore), Magallanes (coastal onshore Sureste) + Arenque (Sureste offshore) following clearance from the competition commission.

Perenco has completed the 49% farmin from Petrofac in the latter’s Mexico assets – including Santuario (Sureste onshore), Magallanes (coastal onshore Sureste) + Arenque (Sureste offshore) following clearance from the competition commission.

G-1 field area, KG offshore, WD 188m, ops terminated at TD 3,780m late Dec ‘18, Essar Wildcat SS.

G-1 field area, KG offshore, WD 188m, ops terminated at TD 3,780m late Dec ‘18,results n/a.

On 29 June 2020, Lukoil, Gazprom Neft and Tatneft announced the completion of a deal regarding setting up JV New Oil Production Technologies LLC (NOPT) aimed at exploration and production of hard-to-recover hydrocarbons in Orenburg Oblast (Volga-Ural Province). Each company holds a one-third interest in the JV. During the initial stage, the venture will operate two licenses in the region. The Savitskiy block (ORB03334NR) covers 900 sq km and encompasses several prospects and leads. The license was originally awarded to Gazprom Neft and it was transferred to Gazprom Neft's subsidiary Savitskoye in early 2020 as the preparation for the reported deal. It is understood that Gazprom Neft already drilled one exploratory well with horizontal completion and recorded a 880 sq km 3D seismic survey. Five more wells have been planned. The Zhuravlevskiy block (ORB16634NR) covers 123 sq km and encompasses the suspended Zhuravlevskoye field with remaining in-place reserves estimated 18 MMbbl of oil. The license, awarded to Lukoil-subsidiary RITEK, was transferred to its subsidiary Zhuravlevskiy in March 2020. The JV plans to record 118 sq km of 3D seismic data and to drill one exploratory well for conventional resources and one well for unconventional resources during 2020-2023.

Lukoil, Gazprom Neft and Tatneft have formed New Oil Production Technologies LLC (each holding one third) to explore and produce conventional and unconventional hydrocarbons in the Savitskiy and Zhuravlyovskiy licences (Orenburg region).

Petrel Energy Ltd announced on 19 November 2018, that it and Warrego Energy Ltd had signed a non-binding term sheet for the merger of the companies, via a reverse takeover.  Under the terms of the deal, Petrel will acquire Warrego Energy.  It remains subject to customary, relevant authority approvals. A binding sale and purchase agreement will be the next steps in the transaction, which is expected to be signed in the coming weeks.  Under the initial terms outlined, Warrego shareholders will receive shares in Petrel, representing around 77% of the company.  A new listing of the combined company will be issued after the completion of the merger. Warrego holds interest in exploration permit EP 469, located in the Perth Basin, which covers an area of 224 sq km and was awarded on 16 April 2010. In June 2018 Strike Energy Ltd completed an agreement to acquire a 50% interest and operatorship in EP 469 from Warrego.  The companies will form a joint venture holding the permit, and a joint operating agreement will be signed. A well was included in the farm-in deal, which must be drilled within 24 months of the commencement of the joint venture.  It is thought that it would target the Erregulla West field, which lies in the south-west of the permit. No wells have been drilled under the permit’s validity to date, but it does contain the Erregulla oil and Erregulla West gas discoveries, made in 1966 and 1990 respectively.

Petrel Energy Ltd announced on 19 November 2018, that it and Warrego Energy Ltd had signed a non-binding term sheet for the merger of the companies, via a reverse takeover. Under the terms of the deal, Petrel will acquire Warrego Energy.

The Chubut authorities have approved Capsa increasing its interest from 88 to 95% in the Pampa del Castillo-La Guitarra concession. The 120-sq km block lies in the San Jorge Basin, Chubut. Provincial company Petrominera Chubut sold 7% of its prior 12% stake in the deal.

The Chubut authorities have approved Capsa increasing its interest from 88 to 95% in the Pampa del Castillo-La Guitarra concession. The 120-sq km block lies in the San Jorge Basin, Chubut. Provincial company Petrominera Chubut sold 7% of its prior 12% stake in the deal.

Press reported in early July 2020 that Nigerian company Niger Delta Exploration & Production Plc (NDEP) was invited by the authorities for negotiations on the onshore PT5-B block. Canadian Overseas Petroleum Ltd (COPL) - partner in the Shoreline CanOverseas consortium - also communicated being invited by the authorities to discuss on the block. The 4,321 sq km block is located on the Mozambique coastal plain, 750 km north of Maputo. It surrounds the north, west, and southwest margins of the Pande gas field. On 15 December 2017, Shoreline CanOverseas – a consortium composed of Canadian Overseas Petroleum Ltd (50%) and Shoreline Energy International (50%) - has been advised by the Government of Mozambique that it had been pre-awarded the PT5-B block in the 5th Licensing Round. The consortium has been invited to negotiate with the Government of Mozambique the terms of the production sharing contract governing the block in Q1 2018. However, the consortium was not reported as a winner of the round by the Mozambican authorities. At the time of the pre-award, interest in the block were held by Shoreline CanOverseas Dev Corp Ltd (57% + operator), Bluegreen Investments LLC (23%), are Indico Dourado Ltda (10%) and Empresa Nacional Hidrocarbonetos (ENH, 10%).

Mozambique (Mozambique B.) PT5-B op. by COPL (29%), SHORELINE (29%), BLUEGREEN (23%), INDICO DOU (10%), ENH (10%), Mozambique Canadian Overseas Petroleum Ltd and Nigerian NDEP - Direct negotiations for PT5-B block.

According to local media report, Repsol and Petronas Carigali (via its subsidiary Petronas Andaman III Indonesia BV) signed an official contract agreement on the latter's acquisition of 49% participating interest in the Andaman III PSC, in offshore North Sumatra Basin, on 23 December 2019. With the completion of the deal, Repsol will hold the remaining 51% operating interest in the block. In early December, Repsol received approval from the government of Indonesia, to farm out a 49% participating interest in the block to Petronas Carigali. Likewise, Repsol also received approval for a two-year extension of the exploration period in the PSC. Local media reported in early November 2019 that the exploration extension was recommended by BPMA, the Aceh upstream regulator, prior to final approval by the Ministry of Energy and Mineral Resources. IHS Markit initially reported the farm-in agreement in early November 2019, pending official approval. Repsol opened a data room in September 2018 offering up to 49% in the block. The new partner will support the drilling of high-impact wildcat Rencong 1X, planned for late 2020. The well will target Upper Eocene-Lower Oligocene carbonates of the Tampur Formation. The well will fulfill the exploration commitments for the PSC. In late November 2017, the operator completed the seismic commitment for the PSC with a 3D seismic survey covering more than 3,000 sq km. The survey, acquired using Elnusa’s “Elsa Regent” vessel, was reported as the largest 3D seismic survey acquired in Indonesia at the time. The block is operated by Repsol’s fully owned subsidiary Talisman (Andaman) BV. Prior to the farm-in by Petronas, the company was holding 100% interest in the PSC. The Andaman III PSC, awarded in 2009, covers approximately 8,500 sq km and lies between shelf and over 1,300 m water depth. Background Information The Andaman III block was offered during Phase II 2008 Tender Round under the regular tender mechanism and was officially awarded to Talisman (100%, operator) on 30 November 2009. The company paid a signature bonus of USD 7.5 million for the block. Firm commitments for the initial three-year exploration period included G&G studies worth USD 2 million, acquisition of 2,500 sq km 3D seismic (USD 15 million) and drilling one well (USD 30 million). The seismic acquisition commitment was initially planned in 2010 but was pushed back to a later date. Second exploration phase commitments (Year 4 to 6) include G&G studies (USD 0.6 million), acquisition of 500 sq km 3D seismic data (USD 3 million) and drilling one exploration well, likely carried over from the first exploration phase (USD 30 million). Multiple play types exist in the area, including carbonate build-up on a basement high or on an anticline, syn-rift clastics with combined stratigraphic-structural trap component, inverted syn-rift clastics close to the Mergui Ridge, carbonate build-ups on flanks of the Mergui Ridge and Barisan fold-belt anticlines. Potential source rocks in the area in include the shales of the Eocene Parapat (lacustrine syn-rift), Oligocene Bampo, Lower Miocene Peutu/Belumai and Middle Miocene Baong formations. Potential reservoirs which could have commercial accumulations in this deepwater area are the Belumai carbonates and Parapat syn-rift sandstones. Shales of the Bampo and Baong formations would be the likely seals.

Repsol and Petronas Carigali (via its subsidiary Petronas Andaman III Indonesia BV) signed an official contract agreement on the latter's acquisition of 49% participating interest in the Andaman III PSC, in offshore North Sumatra Basin,

Vietsovpetro (VSP) has plugged and abandoned deeper pool wildcat 12/11-EF 1X (EF 1X) in Block 12/11, offshore Nam Con Son Basin, in late August 2017. The well tested 2.6 MMcfg/d from the Upper Oligocene Cau sandstone objective. EF 1X was spudded in mid-March 2017 and was drilled to a TD of 4,748 m using the “Murmanskaya” J/U. EF 1X tested the middle section of the Hai Au structure. Discovery well 12W-HA 1X (Hai Au 1X) is located northeast of EF 1X. It was drilled in 1996 by operator Canadian Petroleum Vietnam to a TD of 4,443 m using the “Doo Sung” J/U. The well flowed 24 MMcfg/d gas and 840 bc/d at a depth of 3,300 to 3,350 m in the Lower Miocene Dua Formation. DST test at the Cau Formation (at 3,925 to 3,955 m) did not flow. EF 1X is the second of a two-well campaign in the block. Thien Nga 3X (12/11-TN 3X), the first well in the campaign, was spudded on or around 20 August 2016 and was drilled to a TD of 5,510 m using the “Murmanskaya” J/U. The well tested more than 35 MMcfg/d from the Oligocene Cau Formation. Vietsovpetro is operator of Block 12/11 with a 100% interest. Vietsovpetro is a joint venture between PetroVietnam (51%) and Zarubezhneft (49%).

Vietnam (Nam Con Son B.) 12/11-EF 1X op. by ZARUBEZ N (60.0%, VIETSOV 0.0%, SOVICO HLD 40.0%) in Block 12/11

ExxonMobil is close to signing a deal to explore for oil and gas offshore Mauritania, its first foray into the West African country, Mauritania’s oil, energy and mines director said on Wednesday. An ExxonMobil spokeswoman declined to comment on the deal, but said the Texas-based company does not yet have drilling activities in Mauritania. Interest has surged in oil and gas fields offshore of Mauritania and neighbour Senegal since big discoveries by Cairn Energy and Kosmos Energy, the latter now partnered with BP, in separate projects over the last three years. Both are expected to start production early next decade. London-based BP is already developing a major gas project and France’s Total has bought into several exploration licences in both countries. 'We have agreed on the terms of three blocks,' Moustapha Bechir, Mauritania’s director general of oil, energy and mines told Reuters on the sidelines of an Oil & Gas Council conference in Dakar. He said they and Exxon had yet to formally sign the deal, but would do soon. Experts describe the deep waters there as the next big frontier in energy drilling, though the true size of the deposits is not yet known. BP next year plans to make a final investment decision on a liquefied natural gas (LNG) project that would ship West African gas worldwide. Long overlooked by firms more focused on massive deposits in the Gulf of Guinea further south, Senegal’s and Mauritania’s oil and gas was discovered by new technology that has given companies a better idea of what lies under the sea bed. Now, specialist firms are trawling the deep waters making seismic tests to determine what is below. Oil service companies such as Baker Hughes, now part of General Electric, Schlumberger, and others are lining up to team up with oil producers to develop the resources. Governments in less developed areas south of Senegal and Mauritania’s deposits, including Gambia, Guinea Bissau and Guinea, are also trying to coax oil companies in the hope that they can emulate the interest. Gambia is marketing oil blocks in its thin sliver of territorial water, while Guinea has started to drill offshore. Guinea Bissau plans to drill its first deep offshore well next year, Celedonio Vieira, the director of marketing and business development at state-run PetroGuin, told Reuters. 'We are optimistic because of the success in Senegal,' he said. Original article link Source: Reuters

Mauritania, not found

Ref. DEA 29 Nov ’17, Pampa Energía has reportedly signed the contract for the 120-sq km Las Tacanas Norte block awarded on 8 Nov ’17 by the Neuquén authorities under the V Ronda Licitatoria del Plan Nuevos Horizontes. The contract includes a USD 207 MM exploration commitment over the 4-year term. It lies adjacent to the company’s El Mangrullo block, main target Vaca Muerta, to which 8 wells are planned. GyP Neuquén has a 10% stake in the contract.

Pampa Energía has reportedly signed the contract for the 120-sq km Las Tacanas Norte block awarded on 8 Nov ’17 by the Neuquén authorities under the V Ronda Licitatoria del Plan Nuevos Horizontes.

Battonya-Pusztafoldvar Dél block, Békés sub-basin in SE Hungary, spring 2019 well, P&A dry at TD 2,172m (Szolnok fm). Target gas in L. Pannonian sst.

Dombiratos 1 (Vermillion 100%) in Battonya-Pusztafoldvar Dél (South) block, Bekes sub-basin in SE Hungary, TD=2172m (Szolnok fm), P&A, dry. Target assumed L. Pannonian sst gas.

Tlou Energy Limited (Tlou) confirmed on 1 April 2019 that it had been awarded the new “Boomslang“ CBM Prospecting Licence PL011/2019 for an initial term of three years. It encompasses approximately 1,000 square kilometers (sq km) of acreage contiguous to its existing Lesedi Coal Bed Methane (CBM) Project in ML2018/18L. Tlou had announced on 13 March 2019 that Botswana Public Procurement and Asset Disposal Board (PPADB) and the Ministry of Mineral Resources, Green Technology and Energy Security (MMGE) had provided intermediate, technical stage approval for the provision and staged development of a new CBM-fueled Lesedi power plant, so the project only now requires the government to approve its financial proposal. Tlou regards the Boomslang area to be highly prospective. Not only is it on-trend with the Lesedi project, but in combination with its Mamba CBM project, the additional resource base  would provide the company with greater operational flexibility. The Lesedi CBM Project is located within Mining Licence (ML 2018/18L) which plays host to the Selemo CBM (Lesedi) coal bed methane field. Lesedi CBM pod testing was underway throughout March 2019. Tlou intends to use the Lesedi testing phase to convert a significant portion of currently established gas Resources to Reserves prior to the delivery of gas to its proposed central processing facility and power station. Tlou Energy Limited is based in Brisbane, Australia but listed on both the Australia (ASX), Botswana (BSE) and AIM stock exchanges. Following the acquisition of PL011/2019, it is believed to holds 11 CBM licences in south-eastern Botswana encompassing around 9,300 sq km.

Tlou has been granted the ca. 1,000-sq km Boomslang block, a new CBM prospecting licence on-trend with the Lesedi CBM project, for an initial 3-year term.

In April 2017, BP suspended the Nafahat West 1 wildcat in the onshore El Matariya block (Block 3), Nile Delta basin. The well was spudded on 26 February 2018 with the “EDC-9” land rig. It has the Messinian sands as the objective and a planned TD of 3,500 m. The El Matariya Onshore Concession Area is located onshore Nile Delta and covers an area of 960 sq km. It is adjacent to Dana Gas’s existing West El Manzala and West El Qantara Development Leases and the recently acquired North El Salhiya (Block 1) Concession Area. BP operates the block with a 50% interest and Dana Gas holds the remaining 50%. Background information On 2 June 2015, Dana Gas announced that it had finalized an agreement with BP for the drilling of an exploration well in the onshore El Matariya (Block 3), Nile Delta. Under the terms of the agreement, BP as the operator will carry Dana Gas for its 50% share of the cost of the well, subject to an agreed cap of USD 39 million. BP has the option, subject to Government approval, to farm into parts of Dana Gas’s West El Manzala concession while retaining the operatorship and ownership of the existing and future shallow gas business with Dana Gas. In addition, BP has a further option, again subject to Government approval, to farm into other areas of West El Manzala concession and into the recently-awarded North El Salhiya concession area, for a 50% participating interest in each case, if it elects to drill a second exploration well and carry Dana Gas’s 50% share of the related well costs, again subject to a similar agreed cap. As with the first farm-in option, operatorship and ownership of the existing and future shallow gas business of the farm-in areas will remain with Dana Gas. In early March 2017, BP abandoned Mocha 1 wildcat in the onshore El Matariya block after encountering non-commercial quantities of gas in the Oligocene, which was the target. The well was spudded in early May 2016 and drilled to a TD of 5,940 m. It has the Oligocene layer as the objective and a planned TD at around 6,000 m. Wet gas was encountered in the Messinian layer during drilling. In early February 2018, BP abandoned the Khairat Downthrown 1 (Jd 64-7) exploration well in the onshore El Matariya (Block 3), Nile Delta after the well penetrated a good Messinian reservoir interval but was water wet. The well was spudded on 31 December 2017 with the “EDC-9” land rig and drilled to a TD around 3,300 m. It has objectives in the Miocene layer and a planned TD of 3,306 m.

Nafahat West 1 (BP 50% op, Dana Gas 50%) in the onshore El Matariya block (Block 3), suspended, results n/a. It has the Messinian sands as the objective and a planned TD of 3500 m.

In early November 2019, Divine Inspiration Group (DigOil) – partner of Efora Energy in the local company Semliki Energy - confirmed being seeking a new partner for its Block III. The company plans to drill two exploration wells (potentially three) in the northern part of the licence. The 3,217 sq km onshore licence is located in the Nord-Kivu province, eastern Democratic Republic of Congo (DRC), East African Rift System. Block III is crossed by the Semliki River and lies between Lake Albert and Lake Edward adjacent to Ugandan border. In May 2019, the company had received a fist validity extension for its licence. As a result, the exploration phase was set to expire in January 2020. On 22 November 2019, a second validity extension was granted and the licence is now valid until July 2020. Interest in the licence is held by Semliki Energy SPRL (85% + operator) and Societe National d’Hydrocarbures de la Republique du Congo (15%).

Democratic Republic of Congo, Block III

As of April 2020, China National Offshore Oil Corp (CNOOC) is seeking partners in its BC9 and BCD10 contracts in the Gabon Coastal Basin offshore Gabon. The company operates the contracts BC9 and BCD10 with a 100% interest since Shell exited the licences in November 2019. The company attempts to farm out up to 50% stake prior to drill two high impact wells between late 2020 and 2021, one in each block. According to CNOOC all commitments have been met in both contracts. The company is to enter, in September 2020, in the 2-year fourth exploration period of the BC9 contract with the possibility to be extended up to three years. The BCD10 licence holds the multi Tcf Leopard gas discovery (2014) and is in a gas holding period until 2026 with minimal work commitments. CNOOC identified, both in post-salt and in pre-salt sequences, some 25 leads and/or prospects of which two are drill-ready. The "Tigre" prospect is to be drilled in about 2,000 m of water depth in the BC9 block targeting an approx. 100 sq km area in the pre-salt Gamba sandstones of Aptian age. The "Seal" prospect is to be drilled in approx. 400 m of water depth in the southeastern corner of the BCD10 block targeting the carbonate of the Albian Madiela Group formation in a large 3-way structure with mean recoverable resources estimated at 356 MMbo. CNOOC is also working on the Leopard gas discovery studying for a further appraisal program to determine the feasibility of a standalone development. CNOOC has open a data room since March 2020 with an anticipated bid deadline in mid-2020. Contact details:         Lucas Ong Business Development Advisor                          E-mail: [email protected]               Tel: +44 1895-555319 Ben Kilner Team Lead, Global Exploration                          E-mail: [email protected]               Tel: +44 1895-555310   Background information The blocks BC9 and BCD10 were initially granted to Shell on September 2007. BC9 and BCD10 blocks are mainly in deep waters, covering a total of some 13,400 sq km of which about 530 sq km are in shallow waters. CGG acquired a 6,000 sqkm 3D seismic program between 2010 and 2011. CNOOC farmed in both blocks in 2012. The partners drilled a first wildcat N'Komi Marin 1 in 2014, the well intersected a 200 m paleo-oil column in the pre-salt Gamba formation. It was followed by a success with the Leopard gas and condensate discovery made in October 2014. The latter drilled to TD of 5,063 m intersected a substantial gas column of 200 m of net gas pay in the Gamba formation. The discovery was confirmed by the appraisal Leopard 2 suspended in January 2016. CGG completed in March 2016 the acquisition of a 3D seismic program in the BCD10 block. Six exploration wells were drilled before 2007, in the areas covered by the actual BC9 and BCD10 blocks, targeting post-salt objectives such as the Cenomanian Cap Lopez formation and the Albian Madiela Group formation. All were dry except the Grand Large N'Kendji Marine 1 wildcat, which encountered non-commercial oil in February 1985. The well, drilled by Elf Gabon, is located 85 km west of Sette Cama in 163 m of water. It bottomed in the Albian Madiela Group at a depth of 3,893m.

China National Offshore Oil Corp (CNOOC) is seeking partners in its BC9 and BCD10 contracts in the Gabon Coastal Basin offshore Gabon.

South Disouq block, onshore Nile Delta Basin, TD 2,764m,  30.7m net gas pay in the target Abu Madi, testing gauged 39.3 MMcf/d on 1/2” choke, exceeding initial expectations and limited by surface facilities. Well shut-in for pressure build-up, more testing planned. Commercial production is expected before year-end. SDX (op), partner IPR.

Egypt (Nile Delta B.) ? op. by RWE (100.0%, DISOUCO 0.0%) in Disouq (Dev) block

On 12 April 2019, the CNH updated the companies list for the CNH-A6-7 Asignaciones/2018 Farm-Out Bid Round with little change except that there are now 20 companies that have expressed an interest.  There remain 13 companies authorized to pay data base access fees, 10 companies with data base access, and 11 companies that have initiated the prequalification process. On 13 March 2019, Secretary of Energy Rocio Nahle was reported in the press at the IHS Markit CERAWeek conference to have said that PEMEX may seek to delay the CNH-A6-7 Asignaciones/2018 Farm-Out Bid Round until 2020.  There has also been reports in Mexico that PEMEX may seek to transform the process into only a Service Contracts type round.  Further details are expected in the future.   On 11 January 2019, the CNH updated the companies list for the CNH-A6-7 Asignaciones/2018 Farm-Out Bid Round.  The CNH reported that there is a total of 19 companies that have expressed an interest, 13 companies authorized to pay data base access fees, 10 companies with data base access, and 11 companies that have initiated the prequalification process. On 11 December 2018, the CNH reported modifications to the schedule for the CNH-A6-7 Asignaciones/2018 Farm-Out Bid Round due to a request by SENER received on 7 December 2018.  There were some reports that the round might be cancelled also but SENER decided to extend the round by six months. The modified schedule as of 11 December 2018 is now reported to be the following: The period to pay the data room access fee is 27 April 2018 until 8 July 2019. Reception of pre-qualification documents is from 22 July 2019 until 23 August 2019. The list of pre-qualified companies will be published on 29 August 2019. The final version of the bid documents will be published on 5 September 2019. The bid submittal date is 9 October 2019.   On 26 November 2018, the CNH updated the companies list for the CNH-A6-7 Asignaciones/2018 Farm-Out Bid Round.  The CNH reported that there are a total of 18 companies that have expressed an interest, 12 companies authorized to pay data base access fees, 10 companies with data base access, and 11 companies that have initiated the prequalification process. On 18 July 2018, the CNH modified the bid documents for the CNH-R03-L02/2018 Bid Round, the CNH-R03-L03/2018 Bid Round, and the CNH-A6-7 Asignaciones/2018 Farm Out Bid Round whereby all of the bid rounds are now running concurrently and the calendars for all three rounds have been modified substantially with the bid submittal date now on 14 February 2019.  The CNH reported that this has been done at the request of the new incoming administration in order for the new Secretary of Energy to have time to review all of the bid documents and model contracts for possible modifications.  The new Energy Secretary will have approximately two months to review the contracts from 1 December 2018 until 6 February 2019 when the final versions of the bid documents will be published. On 13 July 2018, the CNH updated the companies list for the CNH-A6-7 Asignaciones/2018 Farm Out Bid Round.  The CNH reported that there are a total of 12 companies that have expressed an interest, eight companies authorized to pay data base access fees, seven companies with data base access, and six companies that have initiated the prequalification process. On 19 June 2018, the CNH modified the bid documents for the CNH-A6-7 Asignaciones/2018 Farm Out Bid Round for seven contracts that includes 27 PEMEX exploration and production entitlements.  The modifications also included publication by the SHCP regarding the royalties to be offered and the changes to the bidding criteria.  The bidding criteria will not include additional royalties offered as these are fixed percentages now, see table below.  Most are set at 15% additional royalties with the Giraldas-Sunuapa contract the only one set differently at 6%.  The modified bid documents also include the fixed initial bonus payment to be made to PEMEX by the winning bidder.  These initial payments range from a low of USD 5 million to a high of USD 146 million and total bonus payments are USD 587 million.  The lone bidding criteria now will be an additional cash payment offered with the highest additional cash payment to indicate the winning company.  The additional cash payment will be split 20% to the Mexican government and 80% to PEMEX.  The winning bidder will have 55% working interest while PEMEX will retain 45%.  Some of the contracts will be only for production and some will be for exploration and production.  Also the majority of contracts have some type of geological depth restrictions.  The bid submittal date is 31 October 2018. On 15 June 2018, the CNH updated the companies list for the CNH-A6-7 Asignaciones/2018 Farm Out Bid Round.  The CNH reported that there are a total of 8 companies that have expressed an interest, four companies authorized to pay data base access fees, four companies with data base access, and two companies that have initiated the prequalification process. On 27 April 2018, the CNH officially launched the CNH-A6-7 Asignaciones/2018 Farm Out Bid Round for seven contracts that includes 27 PEMEX exploration and production entitlements.  There are also seven state controlled blocks that were incorporated into several of the contracts. There is one bid document and joint operating agreement (JOA) for the seven blocks but there is one separate contract for each block. The contract type will be a License Contract.  PEMEX will be paid a fixed fee established in the bid documents and will have 45% working interest.  Total current production for all fields was reported to be 33 Mbo/d and 190MMcfg/d.  The estimated total recoverable reserves is 183 MMbo and 983 Bcfg with an estimated investment of USD 870 million.   The seven packages have been split into three groups.  A company must pay USD 136,612 at exchange rate of 1USD to 18.3 MXN to access one group for the data room purposes.  If a company wants to access all of the data for the three groups the fee will be USD 409,836.     On 5 March 2018, the CNH published information for seven packages that includes 36 exploration and production entitlements that PEMEX will farm-out, now reported to launch the first week of April 2018.  The CNH has published preliminary information on its CNIH website regarding the seven packages of blocks to be farmed-out.  PEMEX CEO Carlos Trevino reported on 6 March 2018 at CERAWeek conference that it plans to have the preliminary awards for these farm-outs concluded by September 2018 and final contract signatures prior to 1 December 2018 when the new administration will take office.  He also indicated that the Ayin-Batsil block would be re-offered as a farm out block in 2018 and that is all he estimates the company can do for this year. The CNH has approved various modifications and migration requests by PEMEX involving up to 50 blocks since November 2017.  Two packages of blocks, the Cauchy block and the Costero blocks, that were originally requested to be migrated for farm-out purposes have not been included in the latest information regarding the farm-out round. CNH-A6-7 Asignaciones/2018 Farm Out Bid Round – Companies List – 11 January 2019 Company Companies that have paid Access to the Data Room Companies that have begun the prequalification process California Resources Corporation 1 1 China Offshore Oil Corporation E&P Mexico, S.A.P.I. de C.V. 2 2 Compania Espanola de Petroleos, S.A. U. 3 3 Deutsche Erdoel Mexico, S. de R.L. de C.V. 4 4 ECP Hidrocarburos Mexico, S.A. de C.V. 5 5 Frontera Energy Corporation 6 6 Galem Energy, S.A.P.I. de C.V. 7   Gran Tierra Mexico Energy, S. de R.L. de C.V. 8 7 Hokchi Energy, S.A. de C.V. 9   Petrobal S.A.P.I. de C.V. 10 8 Southerngeo Mexico, S.A.P.I. de C.V. 11 9 Tecpetrol International S.L.U. 12 10 Vista Oil & Gas Holding II, S.A. de C.V. 13 11 Source: IHS Markit © 2019 IHS Markit   CNH-A6-7 Asignaciones/2018 Farm Out Bid Round - PEMEX Farm-Out Blocks – 19 June 2018 with Additional Royalties and Initial Bonus Payments Contract Area Basin Entitlement or Farm-Out Block Nomenclature Entitlement (AE & A blocks) Fields-Production, AR Entitlements, State Owned Blocks Area sq km Remaining OOIP Mmbo Remaining OGIP Bcfg Reported Risked  Median Prospective Resources MMboe Additional Royalties % Initial Bonus Payment MM USD Total Minimum Work Program work units Calculated work unit values MM USD 1,044/work unit 1 Sureste Artesa AE-0058-M-Mezcalapa-08 Artesa, Gaucho, Nispero, Rio Nuevo, Sitio Grande 893.13 1476.4 2025.7 147.5 15.00 86.00 33,750.00 35.24 2 Sureste Bacal-Nelash A-0027, A-0036, A-0235, A-0339 Arroyo Prieto, Bacal, Nelash, Tiumut 160.8 281.3 501 15.00 66.00 27,220.00 28.42 3 Veracruz Bedel-Gasifero AE-0040-Tesechoacan-02 Bedel, Eltreinta, Gasifero 1168.11 500 649 133.83 15.00 128.00 31,196.00 32.57 4 Sureste Cinco Presidentes A-0092-M-Campo Cinco Presidentes Cinco Presidentes, Rodador 167.12 831.6 665.6 15.00 120.00 15,606.00 16.29 5 Sureste Giraldas-Sunuapa AE-0054-2M-Mezcalapa-04 Chiapas-Copana, Comoapa, Muspac, Giraldas, Sunuapa 1726.38 1058.5 3951.1 210.68 6.00 36.00 33,465.00 34.94 6 Sureste Juspi-Teotleco AE-0057-M-Mezcalapa-07 Juspi, Teotleco 449.95 390.4 1592.7 143.9 15.00 146.00 38,383.00 40.07 7 Sureste Lacamango A-0187-M-Campo Lacamango Lacamango 16.26 75.3 95.5 15.00 5.00 9,818.00 10.25 TOTALS 4581.75 4613.5 9480.6 635.91 587.00 197.77 Source: IHS Markit © 2018 IHS Markit    CNH-A6-7 Asignaciones/2018 Farm Out Bid Round - PEMEX Farm-Out Blocks – 27 April 2018 Contract Area Basin Entitlement or Farm-Out Block Nomenclature Entitlement (AE & A blocks) Fields-Production, AR Entitlements, State Owned Blocks AE Blocks A Blocks AR-State Blocks Area sq km Remaining OOIP Mmbo Remaining OGIP Bcfg Reported Risked  Median Prospective Resources MMboe 1 Sureste Artesa AE-0058-M-Mezcalapa-08 Artesa, Gaucho, Nispero, Rio Nuevo, Sitio Grande, Carmito, Acuyo, Sabancuy 1 5 3 893.13 147.5 Artesa A-0029-M-Campo Artesa 134.2 235.3 Artesa A-0141-M-Campo Gaucho 36.9 92.2 Artesa A-0236-M-Campo Nispero 324.5 232.4 Artesa A-0291-M-Campo Rio Nuevo 193 220.9 Artesa A-0312-M-Campo Sitio Grande 787.8 1,244.80 2 Sureste Bacal-Nelash A-0027-M-Campo Arroyo Prieto Arroyo Prieto, Bacal, Nelash, Tiumut 0 4 0 160.8 21.8 57.2 Bacal-Nelash A-0036-2M-Campo Bacal 120.7 137.9 Bacal-Nelash A-0235-2M-Campo Nelash 86.2 162.9 Bacal-Nelash A-0339-2M-Campo Tiumut 52.7 142.9 3 Veracruz Bedel-Gasifero AE-0040-Tesechoacan-02 Bedel, Eltreinta, Gasifero, Mixtan, and Palmaro 1 3 2 1,168.11 133.83 Bedel-Gasifero A-0045-M-Campo Bedel 214.50 113.50 Bedel-Gasifero A-0122-M-Campo El Treinta 160.70 212.50 Bedel-Gasifero A-0140-M-Campo Gasifero 124.80 323.00 4 Sureste Cinco Presidentes A-0092-M-Campo Cinco Presidentes Cinco Presidentes, Rodador 0 2 0 167.12 715.6 551 Cinco Presidentes A-0292-M-Campo Rodador 116 114.6 5 Sureste Giraldas-Sunuapa AE-0054-2M-Mezcalapa-04 Chiapas-Copana, Comoapa, Muspac, Giraldas, Sunuapa, AR-0428 Campo Iris 2 5 1 1,726.38 158.27 Giraldas-Sunuapa AE-0063-3M-Grijalva-01 52.42 Giraldas-Sunuapa A-0083-M-Campo Chiapas-Copano 177.30 827.50 Giraldas-Sunuapa A-0099-M-Campo Comoapa 127.10 118.80 Giraldas-Sunuapa A-0144-M-Campo Giraldas 289.70 840.50 Giraldas-Sunuapa A-0230-M-Campo Muspac 85.90 1,190.20 Giraldas-Sunuapa A-0317-M-Campo Sunuapa 378.50 974.10 6 Sureste Juspi-Teotleco AE-0057-M-Mezcalapa-07 Juspi, Teotleco, AR-0470 Campo Arroyo Zanapa 1 2 1 449.95 143.9 Juspi-Teotleco A-0169-M-Campo Juspi 28.4 102.4 Juspi-Teotleco A-0329-M-Campo Teotleco 362.1 1,490.30 7 Sureste Lacamango A-0187-M-Campo Lacamango Lacamango 0 1 0 16.26 75.3 95.5 TOTALS 5 22 7 4,581.75 4,613.70 9,480.40 635.92 Source: IHS Markit © 2018 IHS Markit   CNH-A6-7 Asignaciones/2018 Farm Out Bid Round - PEMEX Farm-Out Blocks – A blocks – CNH reported Reserves and Cumulative Production from 1 January 2017 Entitlement or Farm-Out Block Nomenclature Entitlement ( A blocks) OOIP MMbo OGIP BCFG Cum_Prod Oil MMbo Cum_Prod Gas Bcfg RF Oil to 1/1/2017 RF Gas to 1/1/2017 1P Oil at 1/1/2017 1P Gas at 1/1/2017 Bid Round Remaining OOIP Mmbo Bid Round Remaining OGIP Bcfg Bacal-Nelash A-0027-M-Campo Arroyo Prieto 24.79 60.50 2.45 2.81 10% 5% 1.49 1.40 21.8 57.2 Artesa A-0029-M-Campo Artesa 191.41 333.68 53.26 95.09 28% 28% 7.82 8.41 134.2 235.3 Bacal-Nelash A-0036-2M-Campo Bacal 230.21 291.83 109.12 153.48 47% 53% 2.06 4.50 120.7 137.9 Bedel-Gasifero A-0045-M-Campo Bedel 219.83 99.07 1.80 0.51 1% 1% 9.98 10.04 214.50 113.50 Giraldas-Sunuapa A-0083-M-Campo Chiapas-Copano 320.19 2,226.60 142.11 1,396.05 44% 63% 6.70 34.69 177.30 827.50 Cinco Presidentes A-0092-M-Campo Cinco Presidentes 1,043.81 1,006.23 326.42 452.15 31% 45% 11.11 15.45 715.6 551 Giraldas-Sunuapa A-0099-M-Campo Comoapa 171.80 215.27 44.15 95.45 26% 44% 2.21 3.62 127.10 118.80 Bedel-Gasifero A-0122-M-Campo El Treinta 154.46 242.36 1.07 2.64 1% 1% 25.62 124.82 160.70 212.50 Bedel-Gasifero A-0140-M-Campo Gasifero 133.30 384.79 6.73 39.68 5% 10% 12.59 87.81 124.80 323.00 Artesa A-0141-M-Campo Gaucho 45.92 136.37 8.93 44.03 19% 32% 0.57 0.52 36.9 92.2 Giraldas-Sunuapa A-0144-M-Campo Giraldas 464.59 2,828.60 174.70 1,974.52 38% 70% 2.61 168.55 289.70 840.50 Juspi-Teotleco A-0169-M-Campo Juspi 39.98 175.06 11.56 71.99 29% 41% 0.44 3.06 28.4 102.4 Lacamango A-0187-M-Campo Lacamango 107.20 147.81 31.45 51.99 29% 35% 2.84 2.01 75.3 95.5 Giraldas-Sunuapa A-0230-M-Campo Muspac 163.20 2,720.05 77.01 1,526.71 47% 56% 0.68 8.21 85.90 1,190.20 Bacal-Nelash A-0235-2M-Campo Nelash 89.71 171.25 3.35 7.45 4% 4% 5.09 10.93 86.2 162.9 Artesa A-0236-M-Campo Nispero 479.46 484.55 153.85 249.57 32% 52% 4.09 8.02 324.5 232.4 Artesa A-0291-M-Campo Rio Nuevo 279.90 400.12 86.70 178.46 31% 45% 0.71 2.25 193 220.9 Cinco Presidentes A-0292-M-Campo Rodador 163.06 182.19 45.77 65.80 28% 36% 5.17 6.87 116 114.6 Artesa A-0312-M-Campo Sitio Grande 1,152.59 1,837.86 364.70 591.70 32% 32% 0.13 6.49 787.8 1,244.80 Giraldas-Sunuapa A-0317-M-Campo Sunuapa 427.75 1,160.25 48.03 170.89 11% 15% 6.96 70.57 378.50 974.10 Juspi-Teotleco A-0329-M-Campo Teotleco 393.52 1,614.79 29.59 108.05 8% 7% 9.12 42.53 362.1 1,490.30 Bacal-Nelash A-0339-2M-Campo Tiumut 54.69 146.18 1.96 3.12 4% 2% 0.98 2.37 52.7 142.9 GRAND TOTALS 6,351.39 16,865.42 1,724.71 7,282.14 N/A N/A 118.97 623.13 4,613.70 9,480.40 © 2018 IHS Markit Source: IHS Markit

CNH updated the companies list for the CNH-A6-7 Asignaciones/2018 Farm-Out Bid Round with little change except that there are now 20 companies that have expressed an interest. There remain 13 companies authorized to pay data base access fees, 10 companies with data base access, and 11 companies that have initiated the prequalification process.

As of late November 2018, the Council of Ministers met and agreed to award the Marine XX block to Societe Nationale des Petroles du Congo (SNPC) it is assumed that the licence is awarded. As is the norm SNPC was awarded the licence but is presumed to only holds a 15% interest, Total is thought to operate the area with an 85% stake. According to a source total is awaiting the implementing decree prior to starting exploration. Total is understood to have applied for the block as part of the Congo Licensing Round Phase I. The block covers some 3,300 sq km primarily atop the Congo Fan. To date two well have been drilled within the block both by Agip Recherches Congo SA the first Zulu Marine 1 was junked, the second Zulu Marine 1bis was plugged and abandoned with oil and gas shows. The primary objective was the sands of the Paloukou Formation.

Congo, Marine XX

On 6 February 2019, Pertamina Hulu Energi (PHE) and regional government-owned company PT Migas Hulu Jabar ONWJ (MUJ) signed an addendum to a previous agreement for the transfer of 10% participating interest (PI) in the Offshore Northwest Java (ONWJ) PSC from PHE to MUJ. The addendum addressed calculations of tax obligations for both partners in relation with the gross split contract for the block. In addition, the regional government via MUJ committed to support upstream activities in the area by simplifying and accelerating the issuance of the necessary permits. The addendum is expected to ensure sustainable long-term cooperation between Pertamina and the local administration in West Java. The addendum is a follow-up of the initial agreement signed on 19 December 2017, whereby PHE transferred the 10% PI to MUJ, in accordance with Regulation of Ministry of Energy and Mineral Resources No. 37/2016. Pertamina Hulu Energi is operator of the block, following a twenty-year extension signed on 18 January 2017. The ONWJ contract was the first to adopt the new Gross Split scheme which was implemented by the government on 16 January 2017. Oil and gas production from the block is being used entirely to support national strategic needs such as fuel, power plants and raw materials for fertilizer production. The latest development in the ONWJ PSC was the SP field, which was brought onstream in October 2018. The field has a production capacity of 30 MMscfd, catering for local consumption. SP was the first field development project carried out under Gross Split fiscal terms. MUJ is a business unit controlled by the Jakarta and West Java provincial governments, and by several regencies in the West Java area. Background Information PT Pertamina and SKK Migas, witnessed by Indonesian Minister of Energy and Mineral Resources, signed an extension for the Offshore Northwest Java (ONWJ) PSC on 18 January 2017. The contract will be valid for 20 years, from 19 January 2017 to 18 January 2037. The final government/contractor split for the new contract was set at 42.5%/57.5% for oil and 37.5%/62.5% for gas. Financial commitments for the first three years of the contract will be USD 82.3 million. Signature bonus to be paid by Pertamina is USD 5 million. Total investment for the 20-year duration of the contract is estimated at around USD 8.5 billion. The ONWJ PSC was originally awarded in 1967. The interest split in the block until 18 January 2017 was Pertamina Hulu Energi with 58.2795%, EMP ONWJ Limited with 36.7205% and Kufpec with 5%.

On 6 February 2019, Pertamina Hulu Energi (PHE) and regional government-owned company PT Migas Hulu Jabar ONWJ (MUJ) signed an addendum to a previous agreement for the transfer of 10% participating interest (PI) in the Offshore Northwest Java (ONWJ) PSC from PHE to MUJ. The addendum addressed calculations of tax obligations for both partners in relation with the gross split contract for the block.

PL 433, part-blocks 6506/9 + 6506/12 N. of Smørbukk field + Åsgard complex, TMD 4,497m, target Garn + Ile fm’s penetrated, sidetrack reveals 58m gross hc reservoir in the Garn + 87m in the Ile, testing gauged 21 MMcfg/d stable + 547 bc/d on 22/64” choke for 24 hrs, Island Innovator SS. Currently 40-90 MMboe gross, wells no to be permanently abandoned. Spirit (op), partners Dyas, PGNiG + Faroe Petr.

6506/09-04S (Fogelberg) appr. pos. by Spirit (51,7% op, PGNiG 20%, Faroe Petr.15% Dyas 13,3%) in PL 433 block, 58m gross hc reservoir in the Garn + 87m in the Ile, testing gauged 21 MMcfg/d stable + 547 bc/d [22/64” choke] for 24 hrs,

Metgasco Pty Ltd has entered into a Farm-out Agreement (FOA) with Vintage Energy Pty Ltd for Vintage to acquire a 50% interest in exploration licence ATP 2021-P. Metgasco first announced that a Heads of Agreement (HoA) had been executed on 22 May 2019, followed by the FOA on 2 July 2019. The permit, which is located in the Cooper-Eromanga basins, was awarded to Metgasco on 29 May 2018 and the company had been seeking a farm-in partner since acquiring the permit ahead of further exploration operations. The HOA was subject to regular required approvals and was expected to finalized by 30 June 2019, after which, the formal FOA has been signed by both parties but remains conditional on ministerial approval and licence registration. Conditions are expected to be met by end-July 2019. As per the HOA, Vintage will contribute 65% of costs associated with drilling a first exploration well (up to AUD 5.3 million) and to also cover 65% of past exploration costs already incurred by Metgasco (AUD 527,800). The initial work programme over the permit focused on better identifying the leads, completing regional geological evaluation and refining play types. To further define existing shallow oil targets, Vintage will also fund up to AUD 70,000 relating to reprocessing of 2D and 3D seismic data. ATP 2021-P is mainly prospective for Permian gas and Jurassic oil accumulations. The primary drill target, which could be tested in 2019 with an exploration well, is the Vali Prospect – an anticlinal structure at the Toolachee and lower Patchawarra levels with independent closure at a depth of around 2,250 m. Metgasco has reported that the prospect is likely to contain reservoir characteristics similar to that of the nearby Kinta 1 gas discovery. The Kinta 1 well intersected 37 m of interpreted gas pay but did not retuned hydrocarbons to surface. Vali has been assigned P50 recoverable resources of 19 Bcf. The Odin Prospect is another identified prospect, comprising an anticlinal structure on the western boundary of the permit with an independent closure at a depth of around 2,300 m. The Strathmount 1 exploration well, which was drilled in 1987, lies within the extent of the prospect. The well encountered 21 m of reservoir sands and 13.7 m of interpreted gas pay. Gas flow testing indicated returned gas to surface but at rates were too small to measure. On the 2016 Snowball 3D seismic data, Metgasco reports that the well appears to have intersected the sands outside of the Toolachee and lower Patchawarra level. Odin has been assigned P50 recoverable resources of 8.7 Bcf. ATP 2021-P, which covers an area 363 sq km, is currently 100% owned and operated by Metgasco. If the farm-in agreement is completed, participants will become: Metgasco Ltd (50% + operator) and Vintage Energy Ltd (50%).

Metgasco Pty Ltd has entered into a Farm-out Agreement (FOA) with Vintage Energy Pty Ltd for Vintage to acquire a 50% interest in exploration licence ATP 2021-P.

On late June 2020, PEMEX concluded the evaluation on the Cibix 1001EXP directional new-pool wildcat (NPW) in the AE-0056-2M-Mezcalapa-06 (AE-0141-Comalcalco) entitlement block. No further well testing information was released. The NPW is also located in the overlapping AE-0056-2M-Mezcalapa-06 (Campo Cibix) production entitlement in the northern area of the block and it used the same drilling pad as the Cibix 1EXP discovery well. The NPW was spudded on 22 August 2019. It had a proposed total depth (PTD) of 4,777 m measured depth (MD) and 3,850 m true vertical depth (TVD), and was targeting deeper Upper Miocene in a separate fault compartment than the Miocene reservoir discovered with the Cibix 1EXP. The well has estimated unrisked prospective resources of 29 MMboe. The estimated drilling cost for the first wellbore is USD 16.1 million and drilling the side-track is USD 23.71 million. The completion cost for the first wellbore is estimated to be USD 4.48 million and for the side-track is USD 2.03 million. On 27 August 2014, the 1,085.39 sq km AE-0056-2M-Mezcalapa-06 exploration entitlement block was granted to PEMEX 100%, has been modified two times but expired on 27 August 2019 and was replaced by the AE-0141-Comalcalco block on 28 August 2019 with the exception of the AE-0056-2M-Mezcalapa-06 (Campo Cibix) production entitlement block that will remain a part of the original AE entitlement but now in the development and production phase of that entitlement grant. On 18 June 2019, the CNH approved a PEMEX request for a permit to drill the Cibix 1001EXP directional new-pool wildcat (NPW) originally located in the AE-0056-2M-Mezcalapa-06 entitlement block but now known as the AE-0141-Comalcalco block. The well represents one of the commitment wells planned to be drilled in the block after the exploration plan was modified in May 2019.

Mexico (Sureste B.) Cibix 1001EXP op. by PEMEX (100%) in AE-0056 block. On late June 2020, PEMEX concluded the evaluation on the Cibix 1001EXP directional new-pool wildcat (NPW) in the AE-0056-2M-Mezcalapa-06 (AE-0141-Comalcalco) entitlement block. No further well testing information was released.

Petrobras will sell to 3R Petroleum the Riacho de Forquilla cluster of fields in the onshore Potiguar Basin. This comprises 34 production leases 30 of which will be wholly-owned. The deal is pending ANP + IBAMA approvals. It carries a price tag of USD 453.1 MM, USD 34 MM of which to be paid on contract signature on 7 Dec ’18. Contract/field details in GEPS.

Local player 3R Petroleum acquired 34 onshore fields from Petrobras for US$453 MM.

On 14 May 2018 Key Petroleum Ltd and Rey Resources Ltd reported that they had signed a sale and purchase agreement, which will see the companies acquire certain subsidiaries to complete an interest swap in permits EP 104, R1 and L15, located in the Canning Basin, and EP 437, located in the Perth Basin.  The deal remains subject to relevant authority approvals. Under the terms of the agreement, Rey Resources is to acquire all the shares in Key’s wholly owned subsidiary Gulliver Productions Pty Ltd. Rey Resources also reported that it had agreed to acquire Indigo Oil Pty Ltd’s share in the permits. This will give it 100% interest in the Canning Basin licences, which are referred to by the company as the “Lennard Shelf blocks”. As part of the deal in the Canning licences, Key Petroleum will receive a royalty of 2.5% and Indigo a 0.5% royalty in L15 and R1. Key Petroleum will also acquire all the shares in Rey Resources’ wholly owned subsidiary Rey Oil Gas Perth Pty Ltd, which holds a 43.47% interest in exploration permit EP 437.   Key Petroleum already holds the same interest as the Rey subsidiary, so acquisition will double its holding in the permit, increasing it to 86.94%.  Pilot Energy Ltd holds the remaining interest in the permit. Key Petroleum’s sale of its Gulliver Productions subsidiary sees its exit from the Canning Basin and it reports this deal will allow it to focus on the Perth Basin acreage.  The EP 427 permit contains the Wye Knot prospect, which is planned to be drilled in 2018 and is targeting potential resources of 1.4 MMbo.  The permit is adjacent to Key’s L7 production licence, which contains the Mount Horner field. Rey Resources has acquired licence to the north of its existing Canning Basin acreage. It hopes to farm-out some interest in the Lennard Shelf blocks. The licences are outlined as having conventional oil and tight gas potential.  L15 contains part of the Kora West oil field, while R1 contains the Point Torment gas discovery.

On 14 May 2018 Key Petroleum Ltd and Rey Resources Ltd reported that they had signed a sale and purchase agreement, which will see the companies acquire certain subsidiaries to complete an interest swap in permits EP 104, R1 and L15, located in the Canning Basin, and EP 437, located in the Perth Basin.

Lakwa field area + ML, Assam Shelf, TD 3,750m, susp. Apr '20, E-1400-13 rig.

India (Assam Shelf) Lakwa-BE appr in Lakwa field area + ML, Assam Shelf, TD 3,750m, susp. Apr '20

As of 10 January 2019, ExxonMobil Canada has acquired Suncor’s 35% working interest in offshore exploration license EL 1134 located in the Flemish Pass Basin giving the company a 100% working interest in the block. The 2,088.99 sq km block was awarded on 15 January 2013 from the NL12-02 Call for Bids held in 2011 for a work commitment bid of CAD 19,875,875. There were no details of the transfer of interest available. In February 2018, ExxonMobil Canada announced it had acquired Husky Oil Operations Ltd 65% working interest and operatorship of offshore exploration license EL 1134 located in the Flemish Pass Basin. There have been no wells drilled in the block under the current contract however a 3D seismic program was acquired over a majority of the contract in 2016. The block originally had a partnership of Husky Oil (operator) 40%, Suncor 35%, and Repsol 25% however Repsol released their interest to Husky which left a working interest breakdown of Husky 65% and Suncor 35%. After the transaction, the block partnership is now ExxonMobil Canada 65% and Suncor 35%. ExxonMobil Canada now is the sole owner of rights to the block.

Canada, EL 1134

The NPD confirmed, on 5 November 2019, that Var has taken a 20% interest in PL 901 from Equinor, adding to the 30% interest that Var already held in the licence. Subsequent to this, on 19 November 2019, a change of operator was reported – from Equinor to Var (effective 1 November 2019). PL 901 was awarded in APA 2016 and covers a 278 sq km area over parts of blocks 7122/5, 7122/6 and 7123/4, to the east and south of Tornerose. It contains the 2008 Tornerose appraisal wells 7123/4-1 S and 7123/4-1 A which only encountered shows. The deal is effective from 31 October 2019. Tornerose was discovered in 1987 by 7122/6-1. A 75 m gas column was encountered in the Upper Triassic Snadd Formation but at the time the find was considered uneconomic as companies exploring the Barents Sea were looking for oil. However, the development of nearby Snohvit meant that gas finds became more interesting so the discovery was appraised in 2006. 7122/6-2 was a success and Statoil confirmed that Tornerose was a viable project. However, the appraisal drilling in 2008 (in what is now PL 901) was disappointing, with the hydrocarbons in both 7123/4-1 S and sidetrack 7123/4-1 A being classed as residual. In 2019 Equinor was granted an extension to the PDO submission date for Tornerose and nearby Snohvit Beta from December 2019 to December 2024, although it is likely that this will need to be extended again. The two discoveries hold approximately 100 Bcfg and 140-200 Bcfg respectively, not enough to warrant a standalone development. Therefore, the projects cannot proceed until there is sufficient capacity at the Melkoya LNG facility (which is likely to be 2038). In 2012 Equinor ruled out the possibility of an expansion of capacity at Melkoya (ie a second train or a dewpoint facility/pipeline) on economic grounds. The company is, however, looking at options for a further phase of development at Snohvit to include compression (either onshore, subsea or on the platform), the drilling of new wells and a potential new pipeline to shore, with a view to extending production past 2050. Concept selection for this Snohvit Future Phase II project will take place in December 2019, with FID by the end of 2020 and potential start-up in 2025. Interest in PL 901 is now held by Var Energi AS (50% + operator), Equinor Energy AS (30%) and Concedo ASA (20%).

The NPD confirmed, on 5 November 2019, that Var has taken a 20% interest in PL 901 from Equinor, adding to the 30% interest that Var already held in the licence.

Rampart Deep discovery area, NW part of Mississippi Canyon block 72, OCS lease G08483, WD 574m, cleared to P&A (result yet n/a, but assumed non-hc), Ensco 8505 SS. Target supra-salt Middle Miocene. Partners are now evaluating the devt of the Rampart Deep find as a single-well tieback.

MC 72 3S0B1 (Derbio) expl Rampart Deep discovery area, NW part of Mississippi Canyon block 72, OCS lease G08483, WD 574m, cleared to P&A (result yet n/a, but assumed non-hc), Ensco 8505 SS. Target supra-salt Middle Miocene. Partners are now evaluating the devt of the Rampart Deep find as a single-well tieback.

BP confirms 2 late 2017 discoveries in the North Sea: 29/4e-5 (Z) (Capercaillie) nfw, P2189 / block 29/4e, location west of BP’s Vorlich (aka Marconi) discovery, TD 3,750m in Sep ‘17, light oil and gas-cond in the Paleocene + Cretaceous, Paul B Lloyd Jr SS. Well data now under evaluation. Options include a tie-back devt to existing infrastructure. BP 100%. 206/9b-5 (Achmelvich) nfw, P2125, NE part of Clair field West of Shetlands, TD 2,395m in Dec ‘17, oil in the Mesozoic, Paul B Lloyd Jr SS BP (op), partners Shell + Chevron.  

206/09b-05 (Achmelvich) op. by BP (27,62%, Enterprise Oil 27,97%, ConcoPhillips 24%, Chevron 19,42%, Britoil 0,98%) in P2125, NE part of Clair field, ops terminated, was drilled to a TD=2395m and encountered oil in Mesozoic age reservoirs. No details were given of the volumes that have been found. Evaluation and interpretation of the well results is "ongoing to assess future options". 029/04e-05Z (Capercaillie) op. by BP (100%) in P2189 block, was drilled to a TD=3750m and encountered light oil and gas-condensate in Paleocene and Cretaceous-age reservoirs. BP did not reveal the volumes discovered but said the well data is currently under evaluation and that options are expected to be considered for a "possible tie-back development to existing infrastructure".

Afar block 3, NE of Ulfa structure on Huqf Arch in Oman Basin, E. Oman, spudded 4Q ’18, oil shows in shallow horizons but none in the deeper target. CCED (op), partners Tethys Oil + MEPME.

Mahamid 1 (CCED 50% op, Tethys Oil 30%, MEPME 20%) Afar block 3, NE of Ulfa structure on Huqf Arch, oil shows in shallow horizons but none in the deeper target.

On 5 September 2019, the Argentine government granted an exploration permit for CAN-109 offshore block to a partnership of Shell and Qatar Petroleum through the publication of Resolution 525/2019 in the nation’s official gazette following the preliminary award of the block in May 2019 as a result of the Argentina Round 1 offshore bid round. Shell is the operator with 60% participating interest, while Qatar Petroleum holds the remaining 40%. Work program in the first exploration period of four years consists of 2D seismic reprocessing of 911 km and 3D seismic acquisition of 5,350 sq km, followed by a drilling commitment for one well in the second exploration period of another four years. An optional third exploration period of five years is possible, although accompanied by a 50% partial relinquishment. CAN-109 covers 7,880 sq km of offshore deepwater area (as designated by the Argentine Secretary of Energy) in Argentina Basin with approximated water depth of up to 1,400 m. The block was formerly part of state company YPF’s E-1 block (or ENARSA 1) before said concession was reduced in late-2017/early-2018 prior to the bid round. Shell and Qatar Petroleum won the rights for the block after submitting a joint offer of USD 59.125 million at the end of offshore Round 1 in April 2019. The CAN-109 area is relatively unexplored with no discoveries or significant wells other than two wells that were drilled and P&A’d with oil & gas shows by Union Texas in CAN-109 in the mid-1990’s. Background Information The Argentine government published Resolution 276/2019 on 16 May 2019 to award 18 blocks in Austral, Malvinas, and Argentina Basin from its Round 1 of its offshore bid round with a total committed investment of USD 724 million. Granting of exploration permits from the round was originally expected to be published in early-August 2019 with signing of the permits to follow within 15 days.

Argentina, not found