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O&G Development Central Kft. (OGD), domestic subsidiary of Sand Hill Petroleum BV, is seeking to farm down its exposure in the acreage held in central Hungary. The blocks on offer include the Nagykata, Mogyorod and Ocsa permits. As part of the company's risk management strategy in an unprecedented period of volatility on the commodity markets, a negotiable share in the contracts is offered. All permits are solely operated by OGD, through its purpose-established vehicles. The 551 sq km Nagykáta block is located in the Jász–Nagykun–Szolnok and Pest political provinces, some 45 km east of the capital city of Budapest. The 521 sq km Mogyoród block is located in the Nógrád and Pest political provinces, a few kilometres northeast of Budapest. The 593 sq km Ócsa block is located in the Pest political province, a few kilometres southeast of Budapest. All the tracts are falling within the Paleogene Sub-basin, tectonic unit of the Pannonian Basin. The exploration concept is related to the Mesozoic (and Palaeozoic basement) play, as well as the clastic series of the Oligocene-Miocene succession. The petroleum play in the area has been proven by the discoveries nearby, in e.g. Gomba oil field. Interested parties please contact Mr. David LeClair ([email protected]). Background Information The Nagykata, Mogyorod and Ocsa was granted to OGD on 16 February 2016. The contracts, pre-awarded in late November 2015, followed the country’s Third Hydrocarbon Licensing Round. The petroleum plays within the Paleogene Sub-basin relate to the Mesozoic (Triassic and Jurassic) basement series developed in the carbonate facies, the Eocene clastic series and the Miocene, syn-rift successions.

O&G Development Central Kft. (OGD), domestic subsidiary of Sand Hill Petroleum BV, is seeking to farm down its exposure in the acreage held in central Hungary. The blocks on offer include the Nagykata, Mogyorod and Ocsa permits.

According to press, 2 oil discoveries were made late last year in the Rechytsa district, Homiel (Gomel) region in SE Belarus. One find lies at 4,200m, 389,000 Mt recoverable shortly, the other a 6m oil pay exploitable as of 1 Q ’18.  3D seismic surveying will be carried out in 2018, no specifics.

According to press, 2 oil discoveries were made late last year in the Rechytsa district, Homiel (Gomel) region in SE Belarus. One find lies at 4,200m, 389,000 Mt recoverable shortly, the other a 6m oil pay exploitable as of 1 Q ’18. 3D seismic surveying will be carried out in 2018, no specifics.

Saffron announces the termination of the Po Valley Operations acquisition deal from Po Valley Energy (ref. DEA 22 Jan ’18), ‘given the rapid pace of development of the company's activities in South East Asia’. The Saffron board has expressed the desire to limit upfront equity dilution, hence this termination. Saffron plans to announce its first proposed acquisition SE Asia in the next few weeks. For the record, the Po Valley deal involved Sound Energy disposing of Appenine Energy (Sound Energy Holdings Italy Ltd) and PVO to Saffron in a share deal.

Po Valley Energy has pulled out of a deal that would have seen it sell its northern Italian gas assets to Saffron Energy.

Arenal block, Magallanes Basin, 2014 well re-entered and completed Jul-Aug ’19 with unconventional tight gas from the Zona Glauconitica. The original well was completed with conventional gas from the Springhill + Tobifera fm’s.

Rosal-2 nfw Arenal block, Magallanes Basin, 2014 well re-entered and completed Jul-Aug ’19 with unconventional tight gas from the Zona Glauconitica. The original well was completed with conventional gas from the Springhill + Tobifera fm’s.

Advent Energy Ltd announced on 28 September 2018 that it had signed a binding agreement to sell the majority shares in its wholly owned subsidiary Offshore Energy Pty Ltd to Bonaparte Petroleum Pty Ltd.  Bonaparte Petroleum has agreed to purchase 90% of the shares in Offshore Energy, currently held by Advent. The agreement is conditional upon board approval of both companies, Bonaparte Petroleum showing it has the capability to fund the work programme proposed in the transaction and potential shareholder approval, if required by the Australian Securities Exchange (ASX). Offshore Energy holds 100% interest in exploration licence EP 386 and retention lease RL 1, both located in the onshore Bonaparte Basin.  Bonaparte Petroleum has indicated that it has the capability to progress the licences, and under the terms of purchasing the shares has agreed to submit required documents for the drill of one or two exploration wells within EP 386, as well as acquiring 50 km new 2D seismic prior to the end of the current permit validity period, which concludes on 31 March 2020.  The company will also complete the decommissioning of two existing wells.   The work will be fully funded by Bonaparte Petroleum under the share acquisition. Further terms to the agreement include the issue of 10% interest, under a standard joint operating agreement, to Advent on the award of any subsequent retention or production licences over the current asset area. Under these terms Advent will earn a 10% share in Bonaparte Petroleum, and transfer the remaining shares in Offshore Energy to Bonaparte Petroleum.  A further 10% interest in any subsequent licences will be granted to Advent upon the discovery of 15 MMboe reserves. An option remains for Advent to buy back into REL 1. If EP 386 is not renewed or transferred to a retention or production licence, Advent will also be reinstated as operator and holder of RL 1. If Bonaparte Petroleum chooses not to proceed with the transaction outlined in the agreement reached on 28 September 2018, Advent will be paid a break fee of AUD 50,000. Advent Energy Ltd had been aiming to farm-out interest in the licences, alongside its other Australian asset PEP 11, located in the Sydney Basin.

Advent Energy Ltd announced on 28 September 2018 that it had signed a binding agreement to sell the majority shares in its wholly owned subsidiary Offshore Energy Pty Ltd to Bonaparte Petroleum Pty Ltd. Bonaparte Petroleum has agreed to purchase 90% of the shares in Offshore Energy, currently held by Advent.

Igiri Petroleum Ltd is looking to farm-down its 100% interest in two licences: PPL 523 and PPL 532. It is thought that around 80% interest is available, plus operatorship, to interested partners. Igiri has been working on the reviewing the prospectivity of the licences since they were awarded on 31 August 2015. Moving towards the third terms, Igiri would like a partner to support two upcoming seismic surveys and possibly drill an exploration well in 2021. The investment level and interest available is negotiable based on the interested party’s preferred options and expertise. Igiri is 40% owned by the Hides Gas Development Company (HGDC) which has financial support of local entities and technical support by Kallow Ltd and Energy Knowledge. Kallow has been reviewing the existing well and seismic data in the licences in preparation for acquiring an additional 25 km 2D data in PPL 523 and 20 km of data in PPL 532. The timing of the acquisition is dependent on gaining approval by the Department of Petroleum (DOP) to suspend the work commitment by a period of 12 months. The application has already been lodged. Based on the work completed to date, including lead and prospect reviews, Igiri believes this request should be granted without issues by end-2019. PPL 523 and 532 cover a combined area of 11,928 sq km in the south Fly Platform and central Papuan Fold Belt, respectively. Although both permits are available for farm-in, the main focus for Igiri at the moment is the prospectivity in PPL 523 where 18 leads have been identified. In the first terms of the work programmes, Igiri purchased all available geological and geophysical data and completed seismic interpretation and subsequently leads and prospects generation. In the second terms, the company moved forward with the work programmes by looking at the petrophysics and reservoir modelling and completed two geochemical surveys. Currently, planning for the upcoming seismic programmes is underway. If the commitments variations are approved by the DOP, both seismic and exploration drilling will be moved to the final terms, in years five and six, for both permits. PPL 523 contains the Moreland 1 and Mata 1 wells in the Morehead Graben. Moreland 1 was found to be dry by Australasian Petroleum in 1957. Mata 1 was drilled in 1991 by White Industries and ANZ Petroleum and encountered gas shows after drilling through the Darai Limestone, Ieru, Imburu and Toro sandstones. The well was drilled to basement. From the studies completed, Igiri considers that both the Lower Imburu shales and Barikewa Formation have good source rock potential in the oil generative windows. Combined with expected good sealing capacity by the regional Intra-Imburu and Ieru shales and conducive reservoir characteristics for hydrocarbon storage in the stacked Alene and Iagifu targets (140 m gross thickness), Igiri has mapped in-place prospective resources of around 3,000 MMbbl oil. PPL 532 contains the 1994 Menga 1 exploration well which was drilled by Mount Isa Mines and Santos. The well was plugged and abandoned after encountering oil shows in the Toro and Imburu formations before encountering deteriorating hole conditions. As with PPL 523, the source rock potential in PPL 532 comes from the Lower Imburu shales and Barikewa Formation with both oil and gas generative windows, as proven by oil discoveries to the west and gas to the south. Igiri expects good reservoir qualities in the Alene, Toro and P’nyang sands, supported by the regional seals. Eleven leads have been mapped with Igiri assigning in-place prospective resources of around 900 MMbbl oil and 1.4 Tcf gas. Once new seismic data has been acquired and integrated with historical data, Igiri hopes to move several leads towards prospect status ahead of its drilling commitments. Igiri Petroleum also has four applications in place under varies financial entities, including the HGDC, within in the Papuan Fold Belt and southern Fly Platform. Full interest of any awarded licence shall be transferred directly to Igiri Petroleum and become available for farm-in once the prospectivity is known.

Igiri Petroleum Ltd is looking to farm-down its 100% interest in two licences: PPL 523 and PPL 532. It is thought that around 80% interest is available, plus operatorship, to interested partners. Igiri has been working on the reviewing the prospectivity of the licences since they were awarded on 31 August 2015.

Petro Rio has signed to acquire an 80% interest from Dommo Energia in the Tubarão Martelo ('Hammer Shark') field in BM-C-039, Campos Basin. The field is host to the OSX-3 FPSO, also acquired for USD 140 MM. The deal will provide for a tieback between the Tubarão Martelo + Polvo ('Octopus') fields using OSX-3, thus saving on the FPSO stationed on Polvo, inter alia.

Petro Rio has signed to acquire an 80% interest from Dommo Energia in the Tubarão Martelo ('Hammer Shark') field in BM-C-039.

Vista Oil & Gas, the first Mexican pure E&P listed company on the Mexican Stock Exchange, has agreed to acquire a fully operational oil & gas platform from Pampa Energia and Pluspetrol Resources with interests in certain exploitation concessions, assessment blocks and exploration permits in Argentina. The majority of the Acquired Assets are located in the Neuquina basin. After giving effect to the Transaction, Vista would become the fifth largest oil producer and operator in Argentina, according to the latest available information published by the Argentine Ministry of Energy and Mining. Miguel Galuccio, Chairman and Chief Executive Officer of Vista, commented, 'With this transaction, we found the right balance of current profitable production and reserves coupled with high-growth potential in Vaca Muerta, the most exciting emerging shale play globally – perfectly aligned with our vision. The platform and timing could not be better suited to start delivering on our plan of becoming the leading Latin American independent oil and gas company.' Highlights of the Transaction include: proved reserves of 55.7 MMBoe (based on information as of December 31, 2016) average daily production of 27,472 boed (based on information for the first nine months of 2017) in excess of 137,000 acres in the Vaca Muerta unconventional play, including 54,000 acres in the core of Vaca Muerta's shale oil window that are ready for full scale development  2017 estimated pro-forma EBITDA of US$182 million Upon closing, Vista's enterprise value at US$10.00 per share would be approx. US$860 million, implying a multiple of 4.5x and 3.0x projected calendar 2018 and 2019 EBITDA, respectively, and an equity value of US$960 million. Assuming the backstop credit facility described below is not drawn at closing of the Transaction, Vista expects to be debt-free and have US$100 million of cash on hand to fund future drilling and acquisitions.   As part of the consummation of the Transaction, Riverstone Vista Capital Partners, an affiliate of Riverstone, has agreed to acquire an additional 5,000,000 Series A Shares for an aggregate purchase price of US$50 million pursuant to a forward purchase agreement entered into at the time of Vista's initial public offering. Furthermore, certain other investors, have also agreed to buy 10,000,000 Series A Shares of Vista, for an aggregate purchase price of US$100 million. These, in conjunction with the US$650 million initial public offering proceeds, brings total equity available to fund the Transaction to US$800 million. Vista has also entered into a commitment letter pursuant to which a credit facility, of up to US$300 million, may be used as backstop with the purpose of increasing the certainty of closing the Transaction. Vista has concurrently called for a shareholders' meeting to be held on March 22, 2018, for purposes of obtaining the approval of the Transaction. If Vista's shareholders do not approve the Transaction at the shareholders' meeting, or if there are insufficient funds to fund the Transaction, the acquisitions will terminate without legal consequences for Vista. The Transaction is expected to close in April 2018. Click here for full details of the transaction Click here for Investor Presentation - Feb 2018 Source: Vista Oil & Gas

has agreed to acquire a fully operational oil & gas platform from Pampa Energia and Pluspetrol Resources with interests in certain exploitation concessions,

On 8 December 2017, Jaguar Exploracion y Produccion de Hidrocarburos, S.A.P.I. de C.V. signed the contracts with the CNH and was granted official final awards for the CNH-RO2-L03-VC-02/2017 and CNH-RO2-L03-VC-03/2017 contracts from the CNH-RO2-LO3/2016 Bid Round.  The CNH-RO2-L03-VC-02/2017 contract is also known as the Area 7, VC-02 block.  The CNH-RO2-L03-VC-03/2017 contract is also known as the Area 8, VC-03 block.  Jaguar formed a separate subsidiary, Jaguar Exploracion y Produccion 2.3, S.A.P.I. de C.V. with 100% working interest as the official designated operating company for the blocks.  The 251.40 sq km CNH-RO2-L03-VC-02/2017 contract has a total financial commitment of USD 18.1 million, all in work commitments including two additional wells.  The 231.70 sq km CNH-RO2-L03-VC-03/2017 contract has a total financial commitment of USD 24.9 million all for work commitments including two additional wells. On 12 July 2017 Jaguar Exploracion was the high bidder in the CNH-RO2-LO3/2016 Bid Round for the Area 7 and Area 8 blocks in the Veracruz Basin and was granted preliminary awards.   For the 251.40 sq km Area 7 block there were two other bids.  Jaguar offered the maximum additional royalties of 40% and 1.5 work unit factor equivalent to two additional wells.  It won the block after the second highest bid by Petrosyergy and Quimica Apollo was for 25.66 % royalties and 1.5 work units or two wells.   For the 231.7 sq km Area 8 block Jaguar offered the maximum additional royalties of 40% and 1.5 work unit factor equivalent to two additional wells.  There were no other bids for the block. Jaguar has 100% working interest in the contracts. The general license contract terms include a 1st exploration period of two years with the possibility of a two year extension.  In the case of a discovery the operator can request a two year evaluation phase for oil and a three year evaluation phase for non-associated gas discoveries once the evaluation plan is approved.  The total contract term is for 30 years with the possibility of two five year extensions for a 40 year total contract term from signature date. The base royalty rate is a sliding scale royalty depending on type of hydrocarbon and oil price.  The values for oil range from 5% for USD 40/bbl oil to 25% for USD 200/bbl oil.  The relinquishment schedule is tied to exploration well commitments.  If the exploration period ends but the operator offers to drill an additional well it doesn’t have to relinquish any area.  If the exploration period ends and the contractor doesn’t have any discoveries it must relinquish 100%.  If the exploration period ends and the operator doesn’t offer to drill an additional exploration well it will have to relinquish 50% of the area.  Local content during the exploration period is 26% for the exploration and evaluation period, and varies from 27% to 38% in the development period.

Mexico (Sureste B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: 12 op. by LUKOIL (100.0%) to be check.2 op. by PEMEX (50.0%, RWE 50.0%) to be check.7 op. by ENI SPA (45.0%, CAIRN EN 30.0%, CITLA 25.0%) to be check.8 op. by PEMEX (50.0%, ECOPETROL 50.0%) to be check.

Block 108, Ene sub-basin (Ucayali), 1st well in this part of basin, TD 2,989m reached mid-Mar ’19, gas shows in 2 intvs so far, target light o&g in the Cushabatya, Petrex rig 15. Pluspetrol (op), partner Woodside.

Block 108, Ene sub-basin (Ucayali), 1st well in this part of basin, TD 2,989m reached mid-Mar ’19, gas shows in 2 intvs so far, target light o&g in the Cushabatya, Pluspetrol (op), partner Woodside.

As of 2 November 2018, the Canada-Newfoundland & Labrador Offshore Petroleum Board (C-NLOPB) 2018 Call for Bids closes on 8 November 2018. In April 2018, the Canada-Newfoundland & Labrador Offshore Petroleum Board (C-NLOPB) announced that three Calls for Bids would be held offshore which will include one call in the Eastern Newfoundland region and two calls in the Jeanne d’Arc region. The NL18-CFB01 Call for Bids is offering exploration licenses to 16 parcels (39,410 sq km) in Eastern Newfoundland region. The NL18-CFB02 Call for Bids is for an exploration license for one parcel (1,424 sq km) in the Jeanne d’Arc region. The NL18-CFB03 Call for Bids is for a production license to a single parcel (14 sq km) also in the Jeanne d’Arc region known as the Terra Nova K-08 commercial discovery area. Some of the parcels included in the NL18-CFB01 Call for Bids are located partially or entirely beyond Canada’s 200 nautical mile zone. Successful bidders for these outboard parcels may incur additional obligations arising from article 82 of the United Nations Convention on the Law of the Sea. The sole criterion for selecting the winners for the NL18-CFB01 and NL18-CFB02 Calls for Bids will be the total amount of money the bidder commits to spend on exploration of the parcel during Period I (the six-year first period of a nine-year license). The minimum bid for each parcel offered is CAD 10,000,000 in work commitments. For the production license associated with the NL18-CFB03 Call for Bids, the sole criterion to win the license will be the highest drilling deposit bid. The minimum bid for the parcel offered is CAD 25,000,000. The drilling deposit will be refunded if a well is drilled within 5 years from the effective date of the production license. Sealed bids are to be submitted prior to the closing date of 12:00 p.m. on 7 November 2018 Newfoundland standard time. The bids should be sent to the Canada-Newfoundland and Labrador Offshore Petroleum Board, Suite 101, TD Place, 140 Water Street, St. John's, NL A1C 6H6. Additional information about these Calls for Bids is available at http: www.cnlopb.ca/news/nr20180405.php

Canada East C-NLOPB 2018 Calls for Bids in the Jeanne d'Arc and Eastern Newfoundland Regions deadline is 8 November 2018

Luda 28-3-1d (LD 28-3-1d) was suspended (results TBC) on or around 28 January 2018 after having spudded in late December 2017 using the "Bohai 10" jack-up. The oil and gas exploration well was likely targeting the Guantao, Dongying and Shahejie formations. Luda 28-3-1d is in the CNOOC operated Block 02/31 in the offshore Liaodong Bay, Bohai Gulf Basin.

Luda 28-3-1d (LD 28-3-1d) was suspended (results TBC

P1620 / block 22/19c in the Central Graben, Equinor recently completed the acquisition of 8% from Eni. The block encompasses the Rowallan prospect, currently being drilled (see DEA 2 Jan ’19). New interest: Eni (op) 32%, JX Nippon 25%, Mitsui 20%, Serica 15%, Equinor 8%.

P1620 / block 22/19c in the Central Graben, Equinor recently completed the acquisition of 8% from Eni. The block encompasses the Rowallan prospect, currently being drilled, New interest: Eni (op) 32%, JX Nippon 25%, Mitsui 20%, Serica 15%, Equinor 8%.

As disclosed by JKX Oil & Gas in early July 2018, the process of divesting the company’s six development and production areas (mining plots) located in central-eastern and northeastern Hungary is ongoing and it is believed to have reached final stage, as the deadline for submitting the offers had been set for the end of June 2018. JKX Oil & Gas, acting in Hungary through its subsidiary Folyópart Energia Kft, is selling its solely-owned contracts Emod V (100 sq km), Hajdunanas IV (28 sq km), Hajdunanas V (7 sq km), Jaszkiser II (6 sq km), Pely I (18 sq km) and Tiszavasvari IV (46 sq km). It is understood, the offer attracted strong interest from the potential buyers: some 15 companies had visited the data room. The owner is seeking to conclude the transaction in cash. The blocks on offer are located within the North Alfold, Hajdusag and Nagykunsag sub-basins, tectonic units of the Pannonian Basin. Background Information: The Hajdúnánás IV mining plot was awarded on 29 November 2010 for an unlimited period. On 16 November 2015, JKX Oil & Gas enlarged the area towards northwest to its current size (25 sq km). The tract is enclosing the Hajdunanas gas field (wildcat Hajdúnánás 1 was pronounced as a successful gas well on 11 August 2008. Appraisal Hajdúnánás 2 was pronounced as successful on 8 January 2009, thus confirming the commerciality of the find. Production from the field was started in August 2009). The Hajdunanas V development/production area was granted to JKX Oil & Gas on 16 November 2015. It incorporates the Chevelle structure defined by the presence of gas shows during the drilling of the Tiszavasvari 6 well. The Tiszavasvari IV development/production area was granted to JKX Oil & Gas in early-October 2015. The block is centred on the 2010 discovery well Tiszavasvari 6. The Emod V development/production area was granted to JKX Oil & Gas on 21 January 2016. The contract is valid for a 35-year term. It includes the Mezokeresztes oil field, shut-in in the 1970s, believed to still contain significant undrained reserves. The company believes that upoto 90% of the mapped oil originally in place (OOIP) - circa 15 MMbbl – remains untapped. The Jaszkiser II mining plot was granted to JKX Oil & Gas on 21 January 2016 for 35-years. The licence contains the Jabba structure, defined by the presence of amplitude anomalies similar to those encountered in the Pely 2 well, operated in late 2011/early 2012 (new-field wildcat Pély 2, drilled on a structure discovered on 2011 Jászság 3D seismic survey, encountered hydrocarbon shows, but was abandoned.) The Pely I mining plot was granted to JKX Oil & Gas on 21 January 2016 for 35-years. The Pely contract is centred over a gas discovery made by the Pely 2 well 2010 (operated in 2011). This well tested gas from the sandstone series of the Miocene-age Szolnok Formation, but was abandoned in early 2012. JKX advises that there are other prospects adjacent to the discovery within the Pely I licence area. JKX disclosed the its intention to divest Hungarian assets in early 2018. The company was progressing with the offer in April 2018. Interested parties were asked to contact: Ritchie Wayland, Exploration Manager, e-mail: [email protected], telephone: +44 207 859 8536 (office), +44 7789 926472 (mobile) and/or Slava Kotov ([email protected]).

As disclosed by JKX Oil & Gas in early July 2018, the process of divesting the company’s six development and production areas (mining plots) located in central-eastern and northeastern Hungary is ongoing and it is believed to have reached final stage, as the deadline for submitting the offers had been set for the end of June 2018.

Stone Energy Corporation has agreed to acquire 100% working interest in the six-block Ram Powell unit, the Ram Powell tension leg platform (TLP), and related assets from Shell Offshore Inc., the operator of the Ram Powell field, ExxonMobil Corporation, and Anadarko US Offshore LLC. Although the purchase price was not disclosed in the press statement, a subsequent SEC 8-K filing by Stone revealed the total consideration under the 27 April 2018 agreement includes “a purchase price of USD 34 million in cash, subject to customary closing adjustments, and the posting of financial assurance instruments totaling approximately $200 million.” The deal is expected to close in early May 2018 and take effect on 1 October 2017. Due to the pending merger of Stone and Talos Energy LLC, the latter company was required to sign off on this acquisition. The Ram Powell acreage and TLP are situated in the Viosca Knoll area in the deepwater Central Gulf of Mexico, about 125 miles (200 km) southeast of New Orleans, Louisiana. Stone’s Interim CEO and President James M. Trimble stated, "We are very excited to announce that we have reached an agreement to purchase the Ram Powell field. The additional scale and diversification this acquisition provides support the strategies associated with the previously announced combination with Talos Energy.  These assets will add meaningful reserves, production volumes, and cash flow to the combined company.” Viosca Knoll blocks 911 (G06892), 912 (G06893), 913 (G08784), 955 (G08474), 956 (G06896), and 957 (G08475) comprise the Ram Powell unit. The TLP is stationed in some 3,200 ft (975 m) of water in Viosca Knoll block 956. It has a throughput capacity of 60,000 b/d of oil and 200 MMcf/d of gas. Production for the Ram Powell field averaged approximately 6,100 b/d of oil equivalent during 2017, according to the press statement. Discovered in 1985, the field did not come online until 1997 when continuous production began. Since that time, the field has yielded 82.0 MMbbl of oil, 16.3 MMbbl of condensate, 880.3 Bcf of gas, and 19.7 MMbbl of water through December 2017. Production flows from multiple Miocene-aged reservoirs, with the main producing sand located at a depth of approximately 12,600 ft (3,840 m).

United States (Sigsbee Sub-basin (DWGoM B.)) Powell

OKEA has announced that Chrysaor, the leading oil & gas independent, has through its Norwegian subsidiary Chrysaor Norge entered into an agreement with OKEA to acquire a 15% interest in the PL038D license, covering the Grevling oil discovery in the Norwegian North Sea.Once the deal is complete, the partners in the license will be OKEA (55%), Petoro (30%) and Chrysaor (15%). OKEA is operator of the license. As part of the transaction, Chrysaor has an option to further increase its interest in the license to 35%. Partners in the Grevling license are actively reviewing development concepts and expect to conclude on the development concept late this year.Erik Haugane, Chief Executive of OKEA, said:'We welcome Chrysaor to Norway. For OKEA to succeed in our business strategy to develop and produce fields outside the focus of the large oil companies, we need a partner with similar focus. Chrysaor is a company to our liking with scale, infrastructure and expertise. OKEA look forward to learning from their UK experience and work with them on Grevling and other opportunities in Norway.'Grevling, discovered in 2009, is an oil field located south of the Sleipner fieldOriginal article linkSource: OKEA

Norway, PL 038 D

AWE and partner Mitsui are jointly farming out 25% to each of NZOG and O.G. Oil & Gas (Singapore) Pte Ltd in PEP 55768,  133 sq km SE of New Plymouth, onshore Taranaki Basin. AWE retains operatorship and 12.5%, Mitsui 37.5%, all of which effective 1 Mar ’18 subject to usual approvals. The permit will be home to the planned Kohatukai-1 nfw planned 4Q ’18, targets Eocene Matapo + Mangahewa sands.

AWE and partner Mitsui are jointly farming out 25% to each of NZOG and O.G. Oil & Gas (Singapore) Pte Ltd in PEP 55768, 133 sq km SE of New Plymouth, onshore Taranaki Basin. AWE retains operatorship and 12.5%, Mitsui 37.5%, all of which effective 1 Mar ’18 subject to usual approvals. The permit will be home to the planned Kohatukai-1 nfw planned 4Q ’18, targets Eocene Matapo + Mangahewa sands.

Mirpur Khas 2568-7 EL, Indus onshore, Sindh, P&A mid-Jun '20 at TD 1,446m, Anton-2001 rig. UE (op), partners Bow Energy, Zaver + GHPL.

Pakistan (Indus B.) Dharo 1 op. by UNITED EN (95%), GHPL (5%) in Mirpur Khas 2568-7 EL block, had reached a TD=1446m, targeted the Paleocene. The PTD for the well is 1452m. P&A, no further details are available

Kufpec has transferred all working interest in multiple tracts located in the offshore Enderby Terrace / Barrow Sub-basin (North Carnarvon Basin), namely prod licences TL/5, TL/6, TL/8, TL/9, TL/1, TL/10 and expl permits TP/08, EP 307 and EP 358. Operator Quadrant now holds full interest. More from GEPS.

Kufpec has transferred all working interest in multiple tracts located in the offshore Enderby Terrace / Barrow Sub-basin (North Carnarvon Basin), namely prod licences TL/5, TL/6, TL/8, TL/9, TL/1, TL/10 and expl permits TP/08, EP 307 and EP 358. Operator Quadrant now holds full interest.

Great Bear has agreed to sell its Alaskan holdings to UK’s Pantheon Resources. The USD 49 MM sale comprises 98 o&g leases totalling upwards of 1,000 sq km on the North Slope and is pending usual approvals.

Great Bear has agreed to sell its Alaskan holdings to UK’s Pantheon Resources for US$49 MM. Sale comprises 98 o&g leases totalling upwards of 1000km² on the North Slope.

On 7 May 2020, Energy World Corp (EWC) completed its purchase of production licence PL 117, located in the Cooper-Eromanga Basin, from Santos Ltd. EWC now holds 100% interest and operatorship through its subsidiary company Australian Gasfields Ltd. EWC reported that it had entered an agreement to purchase the interest in early 2019. PL 117 contains the Vernon gas field, which was discovered in 1996 and brought onstream in 1999. The licence is already connected to its Eromanga gas processing facility. PL 117 was to be surrendered ahead of the scheduled expiry date on 28 September 2019. However, a renewal application is now in place and is expected to be accepted. PL 117, which covers an area of 49 sq km, was awarded on 29 September 1998. After acquiring 100% interest from Santos QNT Pty Ltd, Australian Gasfields Ltd was registered as interest holders since 7 May 2020.

EWC completed the acquisition of PL 117, 49 sq km in the Cooper-Eromanga (Vernon gasfield), from Santos

Petro Matad reported on 17 September 2019 the company has drilled Red Deer-1 to a TD of 2000 m. No hydrocarbon bearing zones were identified during drilling and this has been confirmed with wireline logs. The well will therefore be plugged and abandoned. The primary target, Lower Tsagaantsav primary Formation, was encountered at 1632 m, 30 m shallower than the pre-drill prognosis, and comprised a thick interval of good quality sandstones interbedded with claystones. During drilling no significant oil shows observed upon entering the reservoir target. Analysis of drilling gas data suggests the presence of potential source rocks shallower in the drilled section, but the absence of significant oil shows indicates that these source rocks are not fully mature for hydrocarbon generation in the vicinity of the Red Deer prospect. Petro Matad spudded Red Deer 1, located in Block XX in the Asgat Sag of the Tasmtsag Basin, in eastern Mongolia on 4 August 2019. This NFW, drilled on a three-way dip fault bounded closure in the basin center in the southern part of Block XX, is a basin play opener well and targeting Early Cretaceous petroleum system proven in surrounding basins. The mean prospective recoverable resource assessment for the Red Deer Prospect is 48 MMbo. The well was planned to be drilled to a PTD of 2,100 m and was expected to take up to 35 days to complete.The well was drilled by the Daton Petroleum Engineering and Oilfield Service LLC rig, DXZ1. Petro Matad has a three wells programme planned in 2019 in Block XX. The first well, Heron-1, has been completed with oil and shows in early September 2019. Red Deer 1 is the second well spudded in Block XX. The Gazelle 1 well, the third well, with 13MMbo mean prospective recoverable resources, is currently planned to spud in Q3 2019. Gazelle 1 will target a similar structure to Petro China's best producing field in Block XIX which is only 12 km to the northeast. Background Information Petro Matad awarded PSCA block XX in 2006. In September 2011, the company has received approval from the Petroleum Authority of Mongolia (PAM) to have a two-year extension to its Production Sharing Contract (PSC) on Block XX. In August 2012 Petro Matad extended Block XX for five years until July 2017. In 2016, Petro Matad reported that the PAM provided a one-year moratorium on Block XX at the company’s request, which freezes for one-year obligations that would have normally been incurred, while at the same time extending the current license period to July 2018. The moratorium enables the company to focus on Blocks IV and V work programmes in the immediate term. Petro Matad announced on 5 January 2018 that it has been formally extended its PSC Block XX for a further two years to 4 July 2020. The company reported this is a very positive development and again indicates the support for Petro Matad within the relevant government departments in Mongolia. It is also significant in that Block XX contains considerable prospective exploration potential close to Petro China's production infrastructure which is in operation immediately to the North. Petro Matad has drilled 11 wells in Block XX between 2010 and 2011. The disappointing drill and test results have resulted in the downgrading of the prospectivity of the Davsan Tolgoi Anticline and drilling and seismic activities will be suspended while further studies are performed. A decision was made in May 2012 by the company that no further drilling or testing will be conducted on Block XX on the status of its review of its 2010 and 2011 drilling programme in Block XX in the Mongolia.   In addition to Block XX, Petro Matad also holds Block IV and V in the Central Gobbi area.  Petro Matad completed two NFWs in 2018 with drilling objective in the Jurassic – Cretaceous Play, but the both wells are failed to achieve oil/gas discoveries. The first well, Snow Leopard-1, is situated in Block V in the Taats Basin, as a basin play opener, was spudded on 9 July 2018 and completed reaching a TD of 2,930 m as a dry hole on 20 September 2018. The second well, Wild Horse 1, is situated in Block IV in the Baatsagaan Basin, was spudded on 23 October and completed reaching a TD of 1,490 m as a dry hole on 26 November 2018.

Red Deer 1 explo. (Petro Matad 100%) in Block XX, P&A, dry.

On 20 March 2018, the Ministry of Natural Resources and Ecology announced the offer of three exploratory blocks located in the Arctic part of Krasnoyarsk Kray (Eastern Siberia). Applications must be submitted by 27 April 2018 to Krasnoyarsknedra (660049, Krasnoyarsk, Karla Marksa Str., 62). If any block receives multiple valid applications, it could be offered through an open auction. The Srednepyasinskiy-2 block covers 2,515 sq km in the central part of the Yenisey-Khatanga Basin, some 25 km east of the Posoyskiy license operated by Yermak Neftegaz (BP/Rosneft). Hydrocarbon resources of the offered block are estimated at 9 MMbbl of oil and 685 Bcf of gas. Clastic reservoirs of the Jurassic-Cretaceous sedimentary section are the main exploratory targets. The Ust-Popigayskiy block covers 4,540 sq km in the south-western part of the Lena-Anabar Basin, close to the Khatanga Bay where Rosneft reported the Tsentralno-Olginskoye discovery in 2017. Hydrocarbon resources of the offered block are estimated at 18 MMbbl of oil and 719 Bcf of gas. The Lukunskiy block covers 2,987 sq km in the south-western part of the Lena-Anabar Basin, west of the Ust-Popigayskiy block. Hydrocarbon resources of the offered block are estimated at 7 MMbbl of oil and 449 Bcf of gas.

Russia, not found

On 13 August 2018 Neptune Energy Group announced that it has agreed to acquire Apache North Sea Ltd’s 35% interest in the Seagull development (P1621 & P1622) and a 50% interest in the Isabella prospect (P1820). However, it was confirmed that Apache relinquished licence P1621 on 8 October 2018 and therefore this licence is no longer part of the transaction. The deal is subject to regulatory approval and it is hoped to complete later in 2018. Isabella is an HP/HT (12,960 psi and 175 degrees centigrade) gas condensate prospect located on one of the largest undrilled fault blocks in the Central North Sea and is thought to hold pre-drill estimated resources of 142 MMboe. Well 30/6-6 on Jasmine is thought to be the best reservoir analogue to Isabella. The Isabella trap is formed by closure on a salt pierced anticline. The reservoir target is the Triassic Joanne and Judy Sandstones. The well which is planned to be slightly deviated has an estimated TD of 5,607 m and dry hole cost of GBP 57 million (125 day well). Seagull was discovered by Shell with well 22/29-2 in 1992. The well was drilled to target a trap comprising an uplifted structure associated with a regional northwest-southeast trending fault and was drilled down-dip to avoid the fault zone. It encountered oil in the Middle Jurassic Pentland and Triassic Skagerrak formations but was plugged and abandoned following mechanical problems while coring the Skagerrak. Sidetrack 22/29-2Z was drilled and tested at a rate of 11,630 bo/d from three zones. In January 2014 Talisman Sinopec spudded appraisal well 22/29c-8 targeting the southern extent of Seagull, the well was suspended as a tight hole in November 2014. The plan for the development of the discovery will involve a multi-well subsea tieback to nearby facilities. Development operations are scheduled to begin in 2019 with first oil set for Q1 2022. Interest in P1820, subject to deal completion, is held by Neptune Energy Group (50% + operator), Total E&P North Sea UK Limited (30%), Edison E&P UK limited (10%), Ithaca Energy (UK) Limited (10%). Interest in P1622, subject to deal completion, is held by Neptune Energy Group (35% + operator), BP Exploration Operating Company Limited (50%) and Japex UK E&P Ltd (15%).

Neptune Energy Group announced that it has agreed to acquire Apache North Sea Ltd’s 35% interest in the Seagull development (P1621 & P1622) and a 50% interest in the Isabella prospect (P1820).

On 5 September 2019, the Argentine government granted an exploration permit for CAN-107 offshore block to a partnership of Shell and Qatar Petroleum through the publication of Resolution 524/2019 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 898 km, 2D seismic acquisition of 5,542 km, multibeam acquisition of 5,501 sq km, along with drilling for 60 core samples, 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-107 covers 8,347 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 8.49 million at the end of offshore Round 1 in April 2019. The CAN-107 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

On 30 December 2019, Tiiseza Zambia Ltd (Tiiseza) is understood to have been awarded an exploration licence covering Block 18. Tiiseza is understood to have applied for the block on 30 July 2018. It covers some 17,000 sq km atop the Okawango Graben (Western Basin). Tiiseza is understood to be the sole participant in the licence.

Tiiseza (Tiiseza Zambia Ltd) is understood to have been awarded an exploration licence covering Block 18.

PY 29-3-1 completed without result reported. CNOOC – Shenzhen spudded a new-field wildcat (NFW), PY 29-3-1 (Panyu 29-3-1), in the Pearl River Mouth Basin of the South China Sea on 25 February 2020. The well is located in the Panyu Low Massif, in a water depth of about 187 m area. The well is targeting the Oligo-Miocene clastic play. “Nanhai 8” S/S is used for the drilling operation. PY 29-3-1 is drilled in the east of the PY 30-1 gas/condensate field, which was discovered in May 2002 and onstream in March 2009, it was producing at an average rate of 68.7 MMcf/d in 2018. There are other three gas/condensate fields on production in the area. The three fields Panyu 34-1, Panyu 35-1 and Panyu 35-2 are developed as the Panyu gas field complex. The complex is located 250 km southeast of Hong Kong, about 14 km southwest of the existing PY 30-1 gas field. The development plan of the complex included a central processing platform at Panyu 34-1 field, linked by subsea pipeline at Panyu 35-1 and Panyu 35-2. Gas from the three fields is piped 200 km to Gaolan terminal in Zhuhai City of Guangdong Province along with the Liwan 3-1 gas. PY 34-1, was discovered in August 2002 and onstream in November 2014, gas production is remained growing at a rate of 41 MMcf/d in 2018.  PY 35-1, discovery was made in June 2003 and came onstream in November 2014, gas production is remained growing at a rate of 16.4 MMcf/d in 2018. PY 35-2, discovery was made in March 2008 and came onstream in December 2014, gas production is remained growing at a rate of 28 MMcf/d in 2018. The gas produced from the fields is mainly accumulated in the Oligocene Zhuhai and Miocene Zhujiang formations. Available data in the PY 30-1 indicated a liquid/gas ratio at about 5.89 bbl/MMscf.

CNOOC Shenzhen – PY 29-3-1 – Completed without result reported – PRMB, South China Sea

It was reported that National Iranian South Oil Company (NISOC) signed USD 1.2 billion total value of two agreements the Persian Gulf Petrochemical Industries Company (PGPIC) and Maroon Petrochemical Company for gathering associated gas from fields in East Karoon area. The deals were signed in Asaluyeh, southern Iran, on 4 September 2018 and the signing ceremony was attended by the Iranian President Hassan Rouhani and Minister of Petroleum Bijan Zanganeh. It would involve 32 projects related to the improvement in associated gas gathering facilities in the NISOC operated fields in the area and it could also prevent flaring of around 780 MMcfg/d. It was reported that once the projects become operational, 510 MMfg/d will be supplied to Bidboland II Petrochemical Plant and 250 MMcfg/d to Maroon Petrochemical Plant. This would also contribute in increasing the condensates production by around 38,000 barrels per day which will be supplied as a feedstock.to the Bandar Imam Petrochemical Plant.

Iran National Iranian South Oil Co (NISOC) signed agreement with PGPIC and Maroon for gathering associated gas in East Karoon area

OMV AG, via wholly owned subsidiary OMV New Zealand Ltd. is offering 30-40% equity in its exploration permit PEP 57073, located in the East Coast Basin.  The opportunity is one of several that OMV is currently offering offshore New Zealand.  Under the current work programme a drill or drop decision, along with a 50% area relinquishment, is required before 1 April 2021. The first well would be required to be drilled before 31 March 2022 should the permit be retained. OMV had already secured one partner in the permit, with Statoil ASA (now Equinor ASA) acquiring a non-operated 30% share in February 2016, however Equinor exited the permit in August 2019. OMV has committed to the stage 2 work programme which now includes refinement of the basin modelling analysis based on sequence stratigraphic framework, refined structural model and/or seismic facies analysis, the application of a sequence stratigraphic framework to the stratigraphic succession, and undertake detailed facies mapping based on sequence stratigraphic framework, refined structural model and/or seismic facies analysis. These obligations are due to be completed before 1 October 2020. PEP 57073 is considered frontier acreage, with only minor exploration having taken place to date. No well has been drilled within the permit, however the Tawatawa 1 and Titihaoa 1 wells, both having encountered gas shows, lie just inboard of the permit boundary. The extensive Pegasus MC3D broadband survey acquired by Schlumberger in 2016 covers a significant portion of the permit. Preliminary interpretation of the survey has defined a number of leads and prospects, both structural and stratigraphic, within the Neogene stratigraphy. The primary plays are associated with compressional related anticlines, and drape and pinch-outs of turbidite sands within inverted “mini-basins”. Many of the mapped structural traps have fluid indications or amplitude anomalies. PEP 57073 was awarded on 1 April 2015 and covers an area of 9,800 sq km. OMV New Zealand Ltd holds 100% operated interest in the permit. Interested parties should contact: Alan Clare, Exploration & Appraisal Manager Address: Level 20, The Majestic Centre, 100 Willis Street, Wellington 6011, New Zealand Email: [email protected]

MV AG, via wholly owned subsidiary OMV New Zealand Ltd. is offering 30-40% equity in its exploration permit PEP 57073, located in the East Coast Basin. The opportunity is one of several that OMV is currently offering offshore New Zealand.

AE-0008-3M-Amoca-Yaxche-06, offshore Sureste Basin, TD 2,721m, spudded 17 May with Miocene target, P&A dry on 24 Jun ’18.

Tsaniah 1EXP (Pemex 100%) in the AE-0008 block. The Miocene was the primary objective, P&A dry

On 11 June 2020 3D Oil Ltd reported that, through its wholly owned subsidiary 3D Oil T49P Pty Ltd, it had completed the Farm Out Agreement (FOA) of exploration permit T/49P, located in the Otway Basin, to ConocoPhillips Australia SH1 Pty Ltd (COP), a subsidiary of ConocoPhillips Company. Completion of the deal follows approval of documentation from the National Offshore Petroleum Titles Authority (NOPTA). Under the terms of the agreement, COP now holds 80% interest and operatorship in the permit, with 3D Oil receiving an AUD 5 million cash payment to recognize previous expenditure. COP, now operator, is required to undertake the Dorrigo 3D seismic survey, which is to cover no less than 1,580 sq km, within the permitted area. Once completed the company has the option to drill an exploration well to fulfil the year six work programme. If this option is exercised, 3D Oil will be free carried to a maximum of USD 30 million in drilling costs. After this is reached it will contribute 20% of drilling costs in line with its reduced interest in the permit. On 26 March 2020 3D Oil reported that its FOA with COP, in relation to exploration permit T/49P, was close to completion, with government approval required to confirm the deal. The companies signed a Joint Operating Agreement for the permit, which covers over 4,500 sq km in the Tasmanian Otway Basin. Initially, COP was to acquire 75% interest, but under the terms of the FOA, 3D Oil was to retain 20% to reduce its future operational expenses. The companies entered the FOA on 18 December 2019 and were required to sign a Joint Operating Agreement and gain government approvals to fulfil the conditions of the agreement. Completion of the deal would see COP move into the Otway Basin for the first time At the time of the JOA, the Dorrigo 3D survey was planned for September/October 2020 to gather new data over the central and southern areas of T/49P. Under the work commitments, at least 750 sq km of new data was required. The FOA required COP to acquire, and fully fund, at least 1,580 sq km of data acquisition. 3D Oil had been offering a farm-in opportunity to assist in drilling a well to target the Flanagan Prospect, which lies in the north. Prospective resources of approximately 10 Tcf of gas have been estimated across the permit as a whole. The Dorrigo 3D will be acquired over the Harbinger lead, which has estimated prospective resources of 790 Bcf of gas, and the Seal Rocks lead, which has prospective resources of potentially over 4 Tcf of gas. Both have been mapped on old 2D seismic, and the new 3D is hoped to better define the leads and determine a drill location. T/49P, which covers an area of 4,551 sq km, was awarded on 22 May 2013. 3D Oil T49P Pty Ltd has entered into a farm in agreement with ConocoPhillips Australia SH1 Pty Ltd, which was completed on 11 June 2020. Interest in the permit are now ConocoPhillips Australia SH1 Pty Ltd (80% and Operator), and 3D Oil T49P Pty Ltd (20%).

Australia (Otway B.) T/49P op. by COP (80%), OTHERS (18%), HIBISCUS (2%) 3D Oil Ltd, ConocoPhillips Company farm in agreement for T/49P, Otway Basin - Completed

On 8 December 2017, the consortium of Newpek Exploracion Y Extraccion, S.A. de C.V. and Verdad Exploration Mexico LLC signed the contracts with the CNH and was granted official final awards for the CNH-RO2-L03-BG-02/2017 and CNH-RO2-L03-BG-03/2017 contracts from the CNH-RO2-LO3/2016 Bid Round.  The CNH-RO2-L03-BG-02/2017 contract is also known as the Area 2, BG-02 block.  The CNH-RO2-L03-BG-03/2017 contract is also known as the Area 3, BG-03 block.  The consortium formed a separate subsidiary, Newpek Exploracion Y Extraccion, S.A. de C.V. with 50% working interest and Verdad Exploracion Mexico S.A. de C.V. with 50% working interest as the official designated operating consortium for the blocks.  The 162.95 sq km CNH-RO2-L03-BG-02/2017 contract has a total financial commitment of USD 27.98 million, USD 25 million in work commitments including two additional wells plus the tie-break bonus of USD 2.98 million.  The 199.60 sq km CNH-RO2-L03-BG-03/2017 contract has a total financial commitment of USD 4.7 million, all for work commitments that does not include any extra well. On 12 July 2017, the consortium of Newpek and Verdad Exploration was the high bidder in the CNH-RO2-LO3/2016 Bid Round for the Area 2 and Area 3 blocks in the Burgos Basin and was granted preliminary awards.   For the 162.95 sq km Area 2 block the Newpek consortium offered the maximum additional royalties of 25% and 1.5 work unit factor equivalent to two additional wells.  There were two other bids for the block and one offered the same royalties and work units so ended in a tie. The Newpek consortium won the tie break with a bonus bid of USD 2.98 million beating the 2nd place consortium of Petrosyergy and Quimica Apollo who offered a bonus of USD 1 million.   For the 199.6 sq km Area 3 block the Newpek consortium offered the maximum additional royalties of 25% and 0.0 work unit factor equivalent to no wells.  It won the block after the only other bid by Petrosyergy and Quimica Apollo was for 18.66 % royalties and 1.5 work units or two wells.  It is estimated that the winning Newpek consortium is split 50%-50% but the final official equity breakdown will only be reported at a later date. The general license contract terms include a 1st exploration period of two years with the possibility of a two-year extension.  In the case of a discovery the operator can request a two-year evaluation phase for oil and a three-year evaluation phase for non-associated gas discoveries once the evaluation plan is approved.  The total contract term is for 30 years with the possibility of two five year extensions for a 40-year total contract term from signature date. The base royalty rate is a sliding scale royalty depending on type of hydrocarbon and oil price.  The values for oil range from 5% for USD 40/bbl oil to 25% for USD 200/bbl oil.  The relinquishment schedule is tied to exploration well commitments.  If the exploration period ends but the operator offers to drill an additional well it doesn’t have to relinquish any area.  If the exploration period ends and the contractor doesn’t have any discoveries it must relinquish 100%.  If the exploration period ends and the operator doesn’t offer to drill an additional exploration well it will have to relinquish 50% of the area.  Local content during the exploration period is 26% for the exploration and evaluation period, and varies from 27% to 38% in the development period.

Mexico (Sureste B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: 12 op. by LUKOIL (100.0%) to be check.Area 2 (Hokchi B) op. by HOKCHI EN (60.0%, EP HIDRO 40.0%) to be check.2 op. by PEMEX (50.0%, RWE 50.0%) to be check.6 op. by PETRONAS (50.0%, ECOPETROL 50.0%) to be check.Area 2 (Hokchi A) op. by HOKCHI EN (60.0%, EP HIDRO 40.0%) to be check.

Location n/a in the Thrace Basin, recently drilled to TD 393m, shallow gas sand intvs, completion options under evaluation. Target Eocene.

Karli-1 nfw Location n/a in the Thrace Basin, recently drilled to TD 393m, shallow gas sand intvs, completion options under evaluation. Target Eocene.

SSJN1 block, Sinú-San Jacinto Basin in Caribbean, reportedly gas find in prospect shallower than the 2015 Bullerengue-1 discovery now on stream, several intvs encountered, no details. Hocol (op), partner Lewis Energy.

Bullerengue 3 expl. (Lewis Energy 50 % op, Hocol 50%) in SSJN1 block, in Caribbean, reportedly gas find in prospect shallower than the 2015 Bullerengue-1 discovery now on stream, several intvs encountered, no details.

F18-C / F19-D1 / F19-D4 block (Banarli), Thrace Basin in NW Turkey, TD 4,196m, 60-day testing programme started early Nov ‘17 comprising 4 tests + 2 frac stages / tested intv starting at the bottom of the well. The 1st such test was completed in the Kesan fm, 151m fracced below 3,996m, flowed 800 Mcfg/d + 60-70 bc/d (56 API) avg for 24 hrs (DEA 28 Nov ’17). The 2nd test in the Kesan has now also been completed after 2 slick-water fracs to access 34m of net gas pay below 3,819m.  The 39-hour test resulted in also 800 Mcfg/d avg. A failure of downhole equipment may possibly have restrained flow, which also yielded 30-40 bc / MMcf.

Turkey (Thrace B.) Yamalik 1 op. by VALEURA (100.0%, STATOIL 0.0%) in F18-C (deep) block

Further to DEA 10 Oct '19, MOL has agreed to acquire Chevron's 9.57% stake in the Azeri-Chirag-Guneshli (ACG) field, Chevron + Exxon having each signaled an intention to exit the Caspian Sea field December last. The USD 1.57 bn deal comprises an 8.9% stake in the Baku-Tbilisi-Ceyhan (BTC) pipeline and will be retro-effective 1 Jan '19. Rights had so far been run by BP (op) 30.37%, Socar 25%, Chevron 9.57%, Inpex 9.31%, Equinor 7.27%, ExxonMobil 6.79%, TPAO 5.73%, Itochu 3.65% and OVL 2.31%. Release here.

MOL (BP 30,37% op, Socar 25%, Inpex 9,31%, Equinor 7,27%, ExxonMobil 6,79%, TPAO 5,73%, Itochu 3,65%, OVL 2,31%) has agreed to acquire Chevron's 9,57% stake in the Azeri-Chirag-Guneshli (ACG) field, for US$1,57 billion (comprises an 8,9% stake in the Baku-Tbilisi-Ceyhan (BTC) pipeline).

On 27 March 2018, the consortium of PEMEX and CEPSA, was granted a preliminary award for the 813 sq km Area 18, G-TMV-08 block from the CNH-RO3-LO1/2017 Bid Round.  The final official contract signature award is to take place within 90 days or 1 July 2018. The consortium bid 40.51% state take over the minimum of 22.5% for the Area 18 block.  No additional work unit factors were offered by the consortium. The provisional consortium working interest breakdown is estimated to be PEMEX, operator with 50% working interest, and CEPSA with 50% working interest. There were no other bids for the block.

the consortium of PEMEX and CEPSA, was granted a preliminary award for the 813 sq km Area 18, G-TMV-08 block from the CNH-RO3-LO1/2017 Bid Round.

Petrobras issued a teaser to sell its 100% interest in the Anambe, Arapaçu, Cidade de São Miguel dos Campos, Furado, Paru, Pilar and São Miguel dos Campos fields (aka Alagoas package) in the Sergipe-Alagoas Basin. All fields are onshore bar Paru, which is in WD 24m. EoIs by 6 Jul '20 to [email protected], qualification docs by 24 July.

Brazil (Sergipe-Alagoas B.) Anambe op. by PETROBRAS (100%) Petrobras issued a teaser to sell its 100% interest in the Anambe, Arapaçu, Cidade de São Miguel dos Campos, Furado, Paru, Pilar and São Miguel dos Campos fields (aka Alagoas package) in the Sergipe-Alagoas Basin.

Ural Nefte has reportedly announced the discovery of the Mikhalevskoye oilfield in the Krasilnikovskiy block (licence SVE03680NR) Sverdlovsk Oblast, Volga-Urals Basin. Reserves are pegged at 36.5 MMbbl presumably in the Upper Carboniferous.

(Volga-Urals b.), Mikhalevskoye field was discovered by URAL NS (100%). Reserves of the field are estimated at 5 MMt (36.5 MMbbl) of oil, assumed to be held within the Upper Carboniferous section. The field was discovered within the Krasilnikovskiy block (exploration and production license SVE03680NR).

East Sepinggan PSC, deepwater Makassar Strait, WD 1,580m, gas-cond discovery, tested 30 MMcfg/d + 100 bc/d. PTMD 3,420m, target Sepinggan turbidites, Scarabeo 7 SS. Eni (op), partner Pertamina.

Merakes E.-1 (Eni op. 85%, Pertamina 15%) in East Sepinggan PSC, gas-cond discovery, tested 30 MMcfg/d + 100 bc/d from target Sepinggan turbidites, WD=1580m PTMD=3420m.

Colombo has enlisted Equinor as a partner to Total for joint studies of the hc potential of blocks JS-5 & 6 in deepwaters off the east coast, central Cauvery Basin. It is recalled (DEA 28 Nov ’18) that Equinor had talked to Total over a possible farmin to the latter’s JS-5 & 6 study areas. Plans otherwise likely still include 3D seismic ahead of possible drilling.

Colombo has enlisted Equinor as a partner to Total for joint studies of the hc potential of blocks JS-5 & 6 in deepwaters off the east coast, central Cauvery Basin. It is recalled (DEA 28 Nov ’18) that Equinor had talked to Total over a possible farmin to the latter’s JS-5 & 6 study areas. Plans otherwise likely still include 3D seismic ahead of possible drilling.

-  Nyarmeyskaya-1: Rusanovskoye discovery general area, W. of Yamal peninsula in Kara Sea, W. Siberian Basin, Arkticheskaya SS offsite 23 Oct ’18 therefore ops terminated. PTD was 2,300m.    -  Rusanovskoye-3 appr, Nanhai VIII SS likewise released.

Russia (Izhma-Pechora Depression (Timan-Pechora B.)) Rusanovskoye (Komi)

On 27 August 2019, BP announced it had agreed to sell its entire Alaska business to Hilcorp Alaska for USD 5.6 billion. According to the BP press release, the sale includes BP Exploration (Alaska) which owns all of BP’s upstream oil and gas interests in the state, as well as BP Pipelines (Alaska) which owns BP’s interest in the Trans Alaskan Pipeline System (TAPS). Hilcorp’s total consideration will include USD 4.0 billion payable near-term and USD 1.6 billion through an earnout thereafter. The transaction is expected to be completed in 2020, subject to state and federal regulatory approval. BP, active in the state since 1959, expects its net oil production to average about 74,000 bopd in 2019. This includes production from its 26% operated interest in the Prudhoe Bay field, which came online in 1977 and has produced over 13 billion bbl of oil, with potential to produce an additional 1 billion bbl. BP also owns non-operated interests in the producing Milne Point and Point Thompson fields, as well as non-operated interests in the Liberty project and exploration lease interests in the Arctic National Wildlife Refuge (ANWR). BP’s net holdings in the state comprise 736 sq km (181,870 acres) Having operated in Alaska since 2012, Hilcorp is the largest privately-owned oil and gas operator in the state with over 75,000 boe/d gross production. The company previously purchased interests from BP in four operated North Slope fields in 2014. Hilcorp’s net holdings in the state comprise 2014 sq km (497,670 acres). Harvest Midstream, Hilcorp’s pipeline subsidiary, will assume BP’s midstream assets which include the 49% interest in the 800-mile Trans-Alaskan Pipeline System.

Privately held Hilcorp has agreed to aquire entire BP’s business in Alaska for US$5,6 billion.

Earlier this summer, Murphy completed its acquisition of a 5% stake and operatorship from PetroVietnam in block 15-1/05, 3,075 sq km in the Cuu Long Basin. Murphy (new op) now holds 40%, partnered with PVEP + SK Innovation. Background from GEPS.

Earlier this summer, Murphy completed its acquisition of a 5% stake and operatorship from PetroVietnam in block 15-1/05, 3,075 sq km in the Cuu Long Basin. Murphy (new op) now holds 40%, partnered with PVEP + SK Innovation.

PL 832, NW of Ormen Lange field in Norwegian Sea, WD 1,228m, TD 3,604m, 9m of poor quality reservoir rocks in the Egga and Springar fm’s, to be P&A dry. Shell (op), partners Petoro, Spirit Energy + DEA. Scarabeo 8 SS will now drill the 6406/6-5 (Jasper) well for Total.

6304/03-01 (Coeus) (Shell 45% op, Petoro 20%, Spirit Energy 20%, DEA 15%) in PL 832, NW of Ormen Lange field, WD=1 228m, TD=3 604m reached, P&A dry.

As of 8 November 2018, the Canada-Newfoundland & Labrador Offshore Petroleum Board (C-NLOPB) announced there were five preliminary awards made from the 2018 Call for Bids. A total of four blocks were awarded from the NL18-CFB01 Call for Bids which offered exploration licenses to 16 parcels (39,410 sq km) in Eastern Newfoundland Region. The total commitment bids received on the four blocks was CAD 1.3-billion which included BHP being awarded two of the four blocks (Parcels 8 and 12) for a total bid of CAD 622-million (see related articles). This entry marks BHP’s return to the province following an exit in 2014 after partnering with ConocoPhillips in the Laurentian Sub-basin. The remaining two blocks awarded were to a partnership headed up by Equinor which included Parcels 14 and 15 for a combined bid of CAD 512-million. The remaining block receiving bids was Parcel 1 from the NL18-CFB02 Call for Bids in the Jeanne d’Arc Region which went to a partnership of Suncor 40%, Husky Oil 30% and Equinor 30% for a bid just under CAD 51-million. The NL18-CFB03 Call for Bids for a production license to a single parcel (14 sq km) in the Jeanne d’Arc region did not receive any bids. In April 2018, the Canada-Newfoundland & Labrador Offshore Petroleum Board (C-NLOPB) announced that three Calls for Bids would be held offshore which included one call in the Eastern Newfoundland region and two calls in the Jeanne d’Arc region. The NL18-CFB01 Call for Bids offered exploration licenses to 16 parcels (39,410 sq km) in Eastern Newfoundland region. The NL18-CFB02 Call for Bids was for an exploration license for one parcel (1,424 sq km) in the Jeanne d’Arc region. The NL18-CFB03 Call for Bids was for a production license to a single parcel (14 sq km) also in the Jeanne d’Arc region known as the Terra Nova K-08 commercial discovery area. Some of the parcels included in the NL18-CFB01 Call for Bids are located partially or entirely beyond Canada’s 200 nautical mile zone. Successful bidders for these outboard parcels may incur additional obligations arising from article 82 of the United Nations Convention on the Law of the Sea. The sole criterion for selecting the winners for the NL18-CFB01 and NL18-CFB02 Calls for Bids was the total amount of money the bidder commits to spend on exploration of the parcel during Period I (the six-year first period of a nine-year license). The minimum bid for each parcel offered is CAD 10,000,000 in work commitments. For the production license associated with the NL18-CFB03 Call for Bids, the sole criterion to win the license was the highest drilling deposit bid. The minimum bid for the parcel offered is CAD 25,000,000. The drilling deposit will be refunded if a well is drilled within 5 years from the effective date of the production license. Sealed bids were to be submitted prior to the closing date of 12:00 p.m. on 7 November 2018 Newfoundland standard time. The bids had to be sent to the Canada-Newfoundland and Labrador Offshore Petroleum Board, Suite 101, TD Place, 140 Water Street, St. John's, NL A1C 6H6. Additional information about these Calls for Bids is available at http: www.cnlopb.ca/news/nr20180405.php

As of 8 November 2018, the Canada-Newfoundland & Labrador Offshore Petroleum Board (C-NLOPB) announced there were five preliminary awards made from the 2018 Call for Bids. A total of four blocks were awarded from the NL18-CFB01 Call for Bids which offered exploration licenses to 16 parcels (39,410 sq km) in Eastern Newfoundland Region. The total commitment bids received on the four blocks was CAD 1.3-billion which included BHP being awarded two of the four blocks (Parcels 8 and 12) for a total bid of CAD 622-million (see related articles).

Further to DEA 5 Dec ’17:  Bukhari ML (Badin I), Lower Indus onshore, TD 3,001m in late Aug ’17, tested 2 MMcfg/d on 58/64” choke likely from the Lower Goru fm, TCPDC-4002 rig.  

Pakistan (Indus B.) Mohri 1 op. by UNITED EN (100.0%) in Bukhari ML (Badin I) block

Kosmos is looking to dilute its 45% in Shell-operated PEL 39 / blocks 2913A & B, 12,628 sq km in Orange Basin deepwaters, drilling planned in early 2021. Prospects Graff, Cullinan and unnamed could be targeted. Shell (op), partners Kosmos + Namcor.

Kosmos is looking to dilute its 45% in Shell-operated PEL 39 / blocks 2913A & B, 12,628 sq km in Orange Basin deepwaters, drilling planned in early 2021. Prospects Graff, Cullinan and unnamed could be targeted. Shell (op), partners Kosmos + Namcor.

OMV has completed its sale of OMV Tunisia Upstream GmbH subsidiary to Panoro Energy. Involved are a 49% stake in the Cercina/Cercina Sud, El Aïn/Gremda, El Hajeb/Guebiba and Rhemoura blocks and 50% in the Thyna Petroleum Services S.A. Operating Company (TPS). The agreed purchase price is USD 65 million, retro-effective 1 Jan ‘18. ETAP retains the balance in all rights, while OMV retains the Nawara devt rights in S. Tunisia.

Tunisia, Rhemoura

On 16 April 2020, SODEPS completed the Debbech B 1 ST exploration well in the Debbech permit, Ghadames Basin, southern Tunisia. The company successfully tested the well which flowed 700 b/d of oil and 21,315 cm/d of gas from the Acacus "A" and the Tannezuft formations. In January 2020, Debbech B1 ST was kicked-off from Debbech B1. On 27 February 2020, the well reached its TD at 4,260m in the Lower Ordovician Sanrhar Formation. The well was then logged. Objectives were the Silurian Acacus and Tannezuft formations which were intersected at 3,473m and 3,708 m, respectively. In early November 2019, industry sources indicated that Eni, through the joint venture company SODEPS plans to drill an exploration well in the Debbech permit. The company was to use the rig which was working on the Hawa 1 well in the nearby Adam permit. This is likely to be the continuation of a near-field exploration campaign which saw Sodeps drilling three wells in 2017, one in each concession (Makhrouga, Laarich and Debbech). At least two of these wells were successful. Due to the low oil price environment prevailing since 2015, ENI concentrates on near-field exploration which is less risky and less costly than frontier wildcatting. The well in the Debbech concession was KRDSW-1, it found gas shows and oil in the Acacus A and B sandstones and in the Trias Argilo Greseux Inférieur (TAGI) sandstones. Light oil was also found in the Ordovician. The Debbech permit is operated by Sodeps with a 100% interest. Sodeps, is held by Eni 50% and Etap 50%. In 2012 Sodeps made a discovery with new-field wildcat Kothbane Ramlia Debech 1 (KRD-1) in the Debbech concession. The well was completed as a producer. Oil was encountered in the Acacus and Jeffara formations. KRD-1 had the Triassic TAGI (Kirchaou) and Silurian Acacus as targets. The well was drilled to a TD of 4,302m in the Ordovician Sanrhar Formation.

Debbech-1ST expl (Sodeps 100%), Debbech lease, Dahar Uplift of Ghadames Basin, onshore, S. Tunisia, compl. at TD 4620m in the Lwr Ordovician Sanrhar Fm. tested 700 bo/d + 7.5 MMcfg/d from the Acacus + Tannezuft targets , intersected at 3473m and 3708 m, respectively. Sodeps (Société de Développement et d’Exploitation du Permis du Sud = Eni-Etap JV 50%,50%).

Total has signed agreements to acquire interests into two exploration licenses offshore Guyana, the Canje Block and the Kanuku Block. These agreements come after entering into an option agreement for the nearby Orinduik Block. Subject to the approval of relevant authorities, Total will thus own exploration rights to an area covering over 12,000 sq kms in the Guyana Basin.   'Total is very pleased with this significant entry in the prolific Guyana Basin,' says Arnaud Breuillac, President, Exploration & Production at Total. 'The Canje, Kanuku and Orinduik blocks are located in a very favorable petroleum context, evidenced by the Liza discovery in 2015. Acquiring interests in these highly prospective licenses is in line with the new exploration strategy in place since 2015.'   Total acquires a 35% working interest in the Canje Block, located in water depths of 1,700 to 3,000 meters, under the terms of the agreement signed with an affiliate of Canadian company JHI Associates and Guyana-based company Mid-Atlantic Oil & Gas. These two companies will retain a shared 30% interest alongside operator ExxonMobil (35%).   Total acquires a 25% working interest in the Kanuku Block, located in water depths of 70 to 100 meters, under the terms of the agreement signed with operator Repsol (37.5%), and will be a partner alongside Tullow (37.5%). Total holds an option to purchase a 25% working interest in the Orinduik Block, located in water depths of 70 to 100 meters, under the terms of the agreement signed in September 2017 with an affiliate of Canadian company Eco Atlantic Oil & Gas, who will retain a 15% interest following exercise of the option, alongside operator Tullow (60%).   Original article link Source: Total

Guyana (Guyana B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Canje op. by EXXONMOBIL (35.0%, JHI ASSOC 40.0%, MID ATLANT 25.0%) to be check.Kanuku op. by REPSOL (70.0%, TULLOW 30.0%) to be check.Orinduik op. by TULLOW (60.0%, ECO ATL 40.0%) to be check.

Hibiscus’ Anasuria Hibiscus UK unit has a conditional SPA with Caldera Petroleum to acquire a 50% interest + operatorship in PL 198 / blocks 15/13a + 15/13b off Aberdeen for USD 37.5 MM. Block 15/13a comprises an oil discovery, and 15/13b has a smaller field. The deal is subject to OGA approval, hoped by 16 Oct ’18.

Hibiscus has signed a conditional sale and purchase agreement with Aban Offshore subsidiary Caldera (->50% op.) for a 50% share in production licence P198, which contains blocks 15/13a and 15/13b, for US$37.5 MM.

Hisal 3372-23 EL, Potwar Basin in Punjab, P&A dry at TD 5,167m (Eocene) late Jan ’19, CCDC-23 rig. PPL (op), partners POL + Attock Oil Co.

Misrial X-1 (PPL 65% op, Pakistan Oilfields 25%, Attock Oil 10%) in the Hisal 3372-23 EL onshore concession, P&A after it failed to flow hydrocarbons during testing.

The NPD confirmed on 10 January 2020 that Idemitsu has farmed-in to PL 882, taking 10% interests from both Concedo (on 20 December 2019) and Petrolia (on 31 December 2019). PL 882 covers a 188 sq km area over parts of blocks 33/6 and 34/4 to the northwest of Snorre. A well will be drilled by operator Neptune on the Dugong prospect in mid-2020. Dugong exploration well 34/4-15 S will be drilled using the “Deepsea Yantai” S/S. The well’s objectives are the Upper Jurassic Intra-Draupne Formation and the Middle Jurassic Brent Group. TD is planned at 3,740 m (3,647 m TVD). If a potential sidetrack is drilled (TD 3,790 m / 3,565 m TVD) operations could last for up to 97 days. The PDO for Equinor’s Snorre Expansion Project (Snorre 2040) was approved in July 2018. The project aims to increase the field’s recovery rate from 46% to 51% by producing a further 195 MMbo and extending field life beyond 2040. At a total estimated cost of NOK 19.3 billion (USD 2.31 billion) the development includes six subsea templates each with four wells. Of the 24 new wells half will be producers and the other half will be used for alternating water and gas injection. The templates will be tied back to Snorre A where upgrades will take place (to receive production and provide injection gas and water). First oil is expected in Q1 2021. PL 882 is operated by Neptune Energy Norge AS with 40%. Concedo ASA, Idemitsu Petroleum Norge AS and Petrolia NOCO AS are partners, holding 20% each.

Petrolia NOCO (->20%, Neptune 40% op.) and Concedo (->20%) each transferred 10% equity in PL 882 to Idemitsu Petroleum.

MOR is looking to dilute its 100% in licence applications APPLs 511 + 512 (ex-PPLs 306 + 307), total 7,342 sq km in shelf waters in the North New Guinea Basin. Applications were submitted in 2014 and a farmout has been sought since.

MOR is looking to dilute its 100% in licence applications APPLs 511 + 512 (ex-PPLs 306 + 307), total 7,342 sq km in shelf waters in the North New Guinea Basin. Applications were submitted in 2014 and a farmout has been sought since.

As of early 2019, Impact Oil and Gas Gabon Ltd (Impact) is seeking partners to test both pre-salt or post-salt prospects along the salt basin margins within its deepwater Osulu (D14) and Nyuma (D13) blocks. On 8 August 2014, Impact was awarded the deepwater D14 and D13 blocks in Gabon’s tenth licensing round. Impact is understood to be the sole participant in the licences. Block D14: Covers some 2,514 sq km within the Lower Congo Basin - Congo Fan and is located some 200 km off Gabon’s coast. Water depths across the acreage range between 3,200 m and 3,600 m. No well drilled in the block area. Block D13: Covers some 2,514 sq km primarily within the Lower Congo Basin - Congo Fan however, the north western corner falls within the Gabon-Douala Deep Sea Basin. The block is located adjacent and to the north of Block D14 in water ranging in depths between 2,800 m and 3,600 m. The area is still undrilled.

Impact Oil and Gas Gabon Ltd (Impact) is seeking partners to test both pre-salt or post-salt prospects along the salt basin margins within its deepwater Osulu (D14) and Nyuma (D13) blocks.

Pan Orient is progressing with a 90-day production test for new-pool wildcat L53 AA2 in the L53/48 Reserve Area A, onshore Chao Phraya Basin, since late July 2020. Based on wireline logs interpretation, the well is estimated to have encountered approximately 6 m of good quality net oil pay in the targeted AA sand and possible additional 5 m in the overlying SH1 sand, at a gross interval of 940 to 994 m TVD. The well was drilled to a total depth (TD) of 1,677 m and suspended on 25 February 2020 as an oil well. Located approximately 1.4 km west of the L53-DD drilling pad, the well was targeting a structural closure approximately 970 m northwest and up-dip from the sub-commercial hydrocarbons encountered in the L53-DD6ST1 well, in late 2019. Spudded on 12 February 2020, the L53 AA2 well is the second exploration well drilled under the Phase 2 exploration drilling program. The L53/48 concession is fully owned and operated by Pan Orient (Siam) Ltd, which is in turn controlled by Pan Orient Energy Corp (50.01%) and Sea Oil Public Company (49.99%). The exploration Area A and B will expire in January 2021, after which the production areas (A, B, D, G and DD) will be retained. Background Information Eight oil discoveries were encountered in the L53/48 block from 2009 to 2019. As of early 2020, a total of five fields are producing (L53-A, L53-G, L53-D East, L53-DD and L53-B), two fields are appraising (L53-D and L53-D C-EXT) while L53-AA South field has been temporarily shut-in while waiting for environmental and production license approvals. The oils were trapped in the Lower to Middle Miocene structural play which was sealed by Middle Miocene Series mudstone. The original 3,997 sq km L53/48 block was awarded to Pan Orient Energy on 8 January 2007 as the operator and sole interest holder, under the 19th Licensing Round. The concession agreement allows Pan Orient to explore for hydrocarbons over a period of six years with a minimum three years first phase commitment of approximately US$ 2.1 million, which includes 3D seismic acquisition and two exploratory wells.

(Chao Phraya B.) L53 AA2 npw in L53/48 Reserve Area A block, operated by PAN ORIENT (100%), TD = 1667 m, based on wireline logs interpretation, the well is estimated to have encountered approximately 6 m of good quality net oil pay in the targeted AA sand and possible additional 5 m in the overlying SH1 sand, at a gross interval of 940 to 994 m TVD.

The Hydrocarbons Secretariat of Ecuador (SH) divulged in August 2018 that talks began between state-run Petroamazonas and the government agency in July 2018 to evaluate the most suitable time to return exploratory areas of interest for the planned round from Petroamazonas to the state. Around 14 undeveloped fields possibly in 11 blocks currently held by Petroamazonas are being considered. These assets are considered as small assets with 157.4 MMbo of reserves estimated, which are more likely to appeal to smaller companies. An investment of around US$ 1.2 billion is estimated in total for all the areas. Petroamazonas does not have the inclination or the budget to invest in these undeveloped assets. Petroamazonas has offered to hire international consultants to assess and certify the estimated volume of hydrocarbons in these blocks. The blocks will be offered under the 'Participation' contract (PSC) model.

The Hydrocarbons Secretariat of Ecuador (SH) divulged in August 2018 that talks began between state-run Petroamazonas and the government agency in July 2018 to evaluate the most suitable time to return exploratory areas of interest for the planned round from Petroamazonas to the state. Around 14 undeveloped fields possibly in 11 blocks currently held by Petroamazonas are being considered. These assets are considered as small assets with 157.4 MMbo of reserves estimated, which are more likely to appeal to smaller companies. An investment of around US$ 1.2 billion is estimated in total for all the areas. Petroamazonas does not have the inclination or the budget to invest in these undeveloped assets. Petroamazonas has offered to hire international consultants to assess and certify the estimated volume of hydrocarbons in these blocks. The blocks will be offered under the 'Participation' contract (PSC) model.

Nigerian Niger Delta E&P has been invited by the authorities for negotiations over block PT5-B, 4,321 sq km onshore in the Mozambique coastal plain around the Pande field. Likewise Canadian Overseas Petroleum, a partner in the Shoreline CanOverseas consortium, who had been pre-awarded this block issued under the 5th round, but later reported as not having won it by the authorities. At that time, partners were to be Shoreline CanOverseas (op), Bluegreen Investments, Indico Dourado + ENH.

Mozambique (Mozambique B.) PT5-B op. by COPL (29%), SHORELINE (29%), BLUEGREEN (23%), INDICO DOU (10%), ENH (10%), Nigerian Niger Delta E&P has been invited by the authorities for negotiations over block PT5-B, 4,321 sq km onshore in the Mozambique coastal plain around the Pande field.

ATP-1189-P, Cooper-Eromanga, drilled 30 Nov – 8 Dec '19, TD 2,456m, suspended gas. Santos (op), partner Beach.

Piute 1 nfw. (Santos 60,66% op, Beach 33,34%) in ATP 1189-P, suspended gas. TD=2456m.

Bozhong 19-6-5 (BZ 19-6-5) was suspended (results TBC) in mid-June 2018 after having been spudded in early April 2018 using the "Haiyangshiyou 932" jack-up. The oil and gas appraisal well was likely targeting the Guantao, Dongying and Shahejie formations and buried hill reservoir. Bozhong 19-6-5 is in the CNOOC operated Bozhong Block in the offshore Bohai Gulf Basin and is approximately 1.5km S of discovery well Bozhong 19-6-1 drilled by CNOOC in April 2017.

Bozhong 19-6-5 (BZ 19-6-5) was suspended (results TBC)

OKEA announced on 13 November 2019 that it has transferred a further 20% interest in PL 038 D and an 18.57% interest in PL 974 to Chrysaor. The deal has been approved by the Ministry of Petroleum and Energy and is expected to be finalised by the end of 2019. The two licences contain the Grevling and Storskrymten discoveries for which OKEA is aiming to submit a PDO in 2020, with first oil possible in 2021. Chrysaor gained its initial 15% interest in PL 038 D in November 2018 (this was the company's first NCS licence). OKEA had been considering four options for the development of Grevling in PL 038 D (a standalone development using either an FPSO or a jack-up platform with Mobile Offshore Production Unit (MOPU), or a tie-back development using either subsea wells or an unmanned wellhead platform) and made its choice in May 2019 to proceed with the MOPU option. It intends to use four horizontal producers and two water-alternating gas injectors, with some element of artificial lift. Expected life is 10 years, with plateau production likely to be 20,000 boe/d. Storskrymten (PL 974) will be developed as part of the Grevling project, most likely by a well drilled from Grevling. Grevling was discovered by Talisman in 2009 by 15/12-21 which encountered 67 m of net pay in the Middle Jurassic Hugin and Sleipner formations and the Upper Triassic Skagerrak Formation. Two DSTs were performed, flowing at a rate of 780 bo/d from the Sleipner and Skagerrak formations and 472 bo/d from the Hugin Formation (through a 20/64" choke). The OWC was not penetrated so a sidetrack (15/12-21 A) was drilled in a down-dip location to the east. This well confirmed oil in the same formations with a total of 36 m of net pay but the OWC was still not found. Appraisal well 15/12-23 was drilled in 2010 and found the OWC (or an ODT) at 3,251 m. The Hugin Formation was absent and the reservoir comprised just the Sleipner and Skagerrak formations which tested at a rate of 648 bo/d through a 16/64" choke. Sidetrack 15/12-23 A deviated to the west and found water-wet Hugin sands (with oil shows) and oil-bearing Sleipner sands (it TD’d in the Sleipner). Recoverable reserves are estimated at 43 MMboe. Storskrymten was discovered by Det norske in 2007 with well 15/12-18 S. A 23 m oil column was proven in the Paleocene Ty Formation and a sidetrack was drilled to delineate the discovery but the Ty Formation came in low to prognosis and was below the OWC. However, the overlying Heimdal Formation was oil-bearing. Det norske estimated reserves at 10-45 MMbo at the time of discovery but in late 2008 the company reported that Storskrymten did not have any commercial potential as an independent discovery and the licence was relinquished in 2013. A new licence was awarded in March 2019 and OKEA now believes that it can produce 16 MMboe. Following completion of the deal, interest in PL 038 D is divided between OKEA ASA (35% + operator), Chrysaor Norge AS (35%) and Petoro AS (30%) and interest in PL 974 is held by OKEA ASA (60% + operator) and Chrysaor Norge AS (40%).

Chrysaor acquired 18,57% stake in PL 974 (Storskrymten) from OKEA.

In early December 2019, IHS Markit's sources confirmed that two licence agreements had been signed in Ethiopia, one of them still pending for Government's approval. As of November 2019, six blocks in the Afar and Somali basins (see map below) were under negotiations with the British New Age and other unknown companies as applicants. The best-positioned blocks to be awarded are Block 10 and Block 14 due to their proximity to Poly CGL gas assets in the Somali Basin, and the Adigala Block in the Afar Basin. In January 2017, New Age applied for its previously operated Adigala Block where it had performed seismic operations and planned to drill a prospect. New Age currently operates Block 08 in the Somali basin with 100% interest. As of late November 2019, the Ethiopian Government offered 23 open blocks in addition to six blocks that were under discussions. An update of the Petroleum Policy was also ready to be approved by the Council of Ministers.

2 licence agreements had been signed in Ethiopia, one of them still pending for Government's approval. As of November 2019, six blocks in the Afar and Somali basins were under negotiations with the British New Age and other unknown companies as applicants.

Pemex in 2019 discovered 58deg API oil in the Vinik 1 NFW, AE-0133-Cuichapa contract area. According to sources, 3P reserves are on the order of 50 MMboe. In mid-October 2019, Pemex had set 7" casing, the final casing expected at Vinik 1, to 4,198m. On 20 September 2019 Pemex began the "termination" process after reaching a final TD of 4,199m (3,773m TVD) in the Vinik 1 NFW, sited in the AE-0133-Cuichapa contract area, thus surpassing its PTD of 4,099m. To date, 30" casing has been set to 50m, 20" casing to 1,013m, 13-3/8" casing set to 2,139m, and 9-5/8" casing to 2,885m. The well was spudded on 26 May 2019, on the then AE-0047 Block (officially AE-0047-3M-Agua Dulce-06). The well initially targeted the Middle Cretaceous interval 3,287-4,099m. Pemex used the "IPC-511" rig.There is one other firm, or base prospect, sited in the contract area, namely Yaxjut 1 (which spud in August 2019, see related article), while Andarani 1 is an incremental well. On 27 September 2019, the rig slated to drill Andarani 1 was mobilised to the drillsite (see related article). Pemex was awarded AE-0047 in Round Zero in 2014. On 28 August 2019, the CNH finalised the reconfiguration of a swathe of Round 0 blocks, including the AE-0047-3M-Agua Dulce-06, which is now known as AE-0133-Cuichapa.

Target Cretaceous. According to sources, 3P reserves are on the order of 50 MMboe.

The Council of Ministers has ratified the Feb ’17 PSA between Pennine Petroleum and Albpetrol for the 310-sq km Velca licence in S. Albania, offered in a 2015 tender call. The contract will become effective upon gazettal.  The block contains the Amonica oilfield, however, it is not clear whether this has been carved-out. Commitments include 2 explo wells to 2,500m. Pennine (op) 90%, Alpetrol 10%.

Albania (Ionian Zone) (It's a petroleum rights. Please summarize by yourself). In IHS database: Velca op. by PENNINE (90.0%, ALBPETROL 10.0%) to be check.

The government has issued a renewed invitation for hydrocarbon exploration and production (E&P) licence applications. An open call to bidders was posted in the EU Journal on 3 April 2020, with all unlicensed acreage available. OMV dominates the current licensing and is focussed on the Vienna Basin and adjacent eastern flank of the Molasse Basin in the NE of the country. The company reported success with Dobermannsdorf 4 appraisal in 2019, whilst results from Maustrenk Tief 1 and Altlichtenwarth Tief 1 are still awaited. RAG has been exiting E&P but holds some remaining acreage in the Central Molasse Basin, near to Salzburg in Upper Austria. ADX Energy acquired the producing Zistersdorf and Gaiselberg oil and gas fields from RAG for EUR4 million (US$ 4.5 million) in July 2019, and also has pending exploration applications for Molasse Basin acreage previously surrendered by RAG. Interested parties can contact the Federal Ministry of Agriculture, Regions and Tourism, Section IV (Telecommunications, Postal Services and Mining), Stubenring 1, 1010 Vienna, Austria.<P /><P />

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Further to DEA 7 Feb ’19: Committed well in AC/P54, Vulcan sub-basin (Bonaparte), Timor Sea, WD 125m, TD 2,925m 29 Jan, gas + cond. discovery, 34m net pay in line with expectations. GSF Development Driller I SS. Results will be incorporated in devt plans for the Cash-Maple field, with a total of 3.5 TCF resources.

Orchid 1 (PTTEP 100%) in the offshore exploration permit AC/P54 was drilled in the Timor Sea to a TD=2925m and encountered g&c with the net pay thickness sands around 34m from the Middle-U. Jurassic Sandstone Play. The result is in line with PTTEP’s expectation and will be incorporated into development planning of Cash-Maple field, which contains 3,5 Tcfg of resources.

Mentari Garung Energy offered a farm-in opportunity in the Garung PSC, located in onshore/offshore southern Kalimantan, in April 2019. The contract carries an outstanding exploration commitment of 300 km 2D seismic acquisition which is due by May 2021. Mentari Garung Energy is operator and sole interest holder in the block. The PSC, covering an area of more than 7,000 sq km, was awarded in May 2015. Shortly after the award, the company commenced advance geological studies in preparation for future exploration in the block. The interpretation of pre-existing seismic, gravity and well data, in addition to surface evidence and gas seeps, allowed the identification of at least five leads within Upper Oligocene-Lower Miocene Berai Formation carbonates and Eocene Tanjung Formation sandstones. Prospective recoverable resources in the block have been estimated at approximately 77 MMbo. No further exploration activities have been conducted in the block after 2015, due to the oil price collapse. On 26 June 2015, PT Mitra Investindo Tbk executed an agreement with shareholders of Mentari Garung Energy for the subscription of 33% of the total shares capital in Mentari Garung. Mitra Investindo is an investment company focused on the development of natural resources, such as hydrocarbons and granite quarries. Moyes & Co. is the representative of Mentari Garung Energy for this opportunity. For further information, interested parties may contact: Ian Cross Managing Director [email protected] +65 9776 0753 Background Information The eastern portion of the Garung block is situated in the southern portion of the Barito Basin, primarily onshore, while the western portion of the block is mostly offshore, straddling the northeastern edge of Karimunjava Arch and the northern edge of Barito Shelf. Only two exploratory have been drilled within the block, in the eastern portion of the current contract area. The Tanjung Tawas 1 wildcat was spudded by BPM in 1936. The well was plugged and abandoned as dry, with a total depth of 160 m in the Late Miocene to Early Pliocene Dahor Formation. The Kahajan 2 well, located some 16 km northwest of Tanjung Tawas 1, was spudded by BKPM on 8 December 1937. The well had a total depth of 1,216 m with bottom-hole in the pre-Tertiary metamorphic basement. Kahajan 2 was plugged and abandoned as a dry well on 23 May 1938. Garung PSC was officially awarded to Mentari Garung Energy Limited on 18 March 2015 with official signing ceremony was conducted in Jakarta on 22 May 2015. The block has firm commitments of conducting G&G study and 300 km 2D seismic data acquisition. Fiscal terms and conditions for the block include: 1) after tax splits of 65%/35% for oil and 60%/40% for gas, 2) signature bonus for the block was set at USD 1 million. The block was offered via direct tender mechanism in the First Petroleum Bidding Round 2014 in late May 2014. The 7,407 sq km block has firm commitments of G&G study and 300 km 2D seismic data acquisition. Fiscal terms and conditions for the block include: 1) after tax splits of 65%/35% for oil and 60%/40% for gas, 2) Signature bonus for the block is set at USD 1 million. The block was initially offered as a joint study area on 30 November 2012.

Indonesia, Garung PSC

Armour Energy Ltd is interested in farming-down its 100% held exploration acreage surrounding the Kincora Gas Plant in the Bowen-Surat basins, northern Queensland. Armour holds exclusive rights to seven exploration permits which are interlaced with production licences around the Kincora Gas Plant – ATP 2029-P, 2030, 2032, 2034, 2035, 2041 and 647, covering around 1,400 sq km. Within the Roma Shelf and Taroom Trough, Armour operates 23 exploration and production licences and holds interest in a further two through part ownership of Lakes Oil and a farm in agreement with AGL. A particular exploration focus by Armour lies in the Taroom Trough within a Triassic-Permian tight gas play. The play is considered to occur along a wedge of over-pressured, hydrocarbon saturated sands and shales below depths of around 2,100 m. The play is thought to extend beneath Armour's existing acreage down-dip of mature commercial fields and outside of the highly production structural and stratigraphic plays which occur in the depth range of around 1,500 to 2,100 m. Drilled in 2018, Armour's Myall Creek 4A and 5A wells encountered gas along the deeper play. The 5A well was not fully completed but reached a depth of 2,245 m with gas in the Triassic Basal Rewan and Permian Tinowan sandstones. Myall Creek 4A, which spudded earlier in the year, began commercial production on 5 October 2018 at an average rate of approximately 700,000 cfg/d. Armour has reported that the new regional play could covers around 10,000 sq km with possible targets in the depth range of 2,100 to 4,000 m. In Q2/Q3 2020, new high-resolution 3D seismic surveys are planned over Armour's 100% owned existing acreage in the Bowen-Surat Basin to seek new drill locations. Any commercial gas discoveries would likely be tied back to the Kincora Facility, which, in 2019, produced at an average of 8.6 MMcfg/d (9.1 TJ/d), which included gas from the Newstead Storage asset. Armour Energy has previously stated that it plans to achieve a target of 18.9 MMcfg/d (20 TJ/d). To support production growth ongoing exploration and development is seen as critical to Armour, particularly in ATP 2030-P, which was awarded on 2 October 2018 to link Armour's already existing PL71 and ATP 2029 and secure the deep tight gas play. ATP 2029, 2030, 2032, 2034, 2035 & 2041 were all awarded in 2018 to Armour with conditions for future domestic gas production which can be accommodated through the Kincora facility. ATP 647 was awarded back in 2001, meaning it was scheduled for expiry on 31 July 2017. A renewal application has already been submitted by Armour to extend its tenure. Armour is seeking farm-in partners to advance a potential multi-Tcf play in its 100% held exploration permits. Interested parties should contact: Richard Fenton – Armour Energy, CEO Email: [email protected]

Armour Energy Ltd is interested in farming-down its 100% held exploration acreage surrounding the Kincora Gas Plant in the Bowen-Surat basins, northern Queensland. Armour holds exclusive rights to seven exploration permits which are interlaced with production licences around the Kincora Gas Plant – ATP 2029-P, 2030, 2032, 2034, 2035, 2041 and 647, covering around 1,400 sq km.

Add. DEA 27 Apr ’18: The CNH has approved Pemex’s plans to farmout 7 mature onshore o&g field clusters under the CNH-A6-7 Asignaciones/2018 round process, bid submittal date likely 31 Oct ’18. There are also 7 state-controlled blocks that were incorporated into several of the contracts. One bid document and joint operating agreement (JOA) applies for the 7 blocks but one separate contract for each unit, namely Artesa, Bacal-Nelash, Bedel-Gasífero, Cinco Presidentes, Giraldas-Sunuapa, Juspí-Teotleco and Lacamango in the Veracruz, Chiapas + Tabasco (Sureste Basin, block details from GEPS). Pemex will retain a 55% interest in each of the fields, the farminee 45% in the case of a single firm or 30% in the case of a consortium. The only bidding criteria will be additional royalties above the minimum offered.

Mexico, not found

According to local reports in early-February 2018, operator Compania Petrolera Paraguaya SA was granted a Concession Law Contract for the Estrella Parana block. The work commitments reportedly include seismic activities and drilling of a stratigraphic well, with total investment set at USD 4.1 million over 2.5 years. Estrella Parana block covers approximately 7,895 sq km of onshore land in the San Pedro Sub-basin of the Chaco-Parana Basin and the Parana Basin. Estrella Parana block was awarded to Compania Petrolera Paraguaya as a Prospection Permit in November 2011.

Compania Petrolera Paraguayana was granted a Concession Law Contract for the Estrella Parana (7895km²) block.

Lakes Oil NL, via wholly owned subsidiary Otway Energy Pty Ltd, is undertaking logging operations at the Nangwarry 1 gas exploration well in PEL 155, located in the Otway Basin, as of January 2020. On 7 January, joint venture partner Vintage Energy reported that the operator was recovering logging equipment, which became stuck in hole, before resuming logging operations. It was reported that initial results of logging had indicated a 120 m gas saturated gas column, within the Upper Pretty Hill Formation. The middle and lower section will be evaluated in the coming operations. There is a possible 160 m gas column within the mid-Pretty Hill section. Lakes Oil spudded the Nangwarry 1 well on 1 December 2019. The Easternwell owned “Rig 106” has been contracted to drill the well, which was mobilized to site in late November 2019. On 2 January 2020, Lakes Oil reported that the well had reach a total depth of 4,300 m on 31 December 2019 with gas shows across two intervals in the Pretty Hill Formation. Logging of these sections is currently underway to confirm the shows and potential for flow testing. The secondary target in the Sawpit Sandstone was found to be dry at location. The Pretty Hill Formation was encountered at approximately 2,940 m with Lakes Oil reporting elevated gas reading over an interval of 140 m. It is planned, that after reaching total depth, the interval will be logged to assess the significance of the readings. The Sawpit Sandstone is expected to be intersected at around 4,094 m and it is anticipated by Lakes Oil that the well could enter this secondary target before 29 December 2019. Nangwarry 1 had a planned total depth of 4,350 m. The well is targeting the Lower Cretaceous Pretty Hill and Sawpit sandstones, which were expected to be encountered at around 2,993 m and 4,094 m respectively. The well will take approximately 45 days to drill and log. If gas is encountered, the well is planned to be flow tested. The Nangwarry prospect is a three-way dip fault dependent closure at the Pretty Hill Sandstone and the Sawpit Sandstone levels and has an estimated prospective resource of 57 Bcf. The prospect is covered by the 34 sq km Nangwarry 3D seismic survey, acquired in February 2008. An airborne gravity, gradiometry and magnetics survey was acquired in October 2018 to provide further data on the structural trends, including faults and fault blocks, within the permit but also to assist in de-risking the Nangwarry 1 well. The prospect thought to be analogous to the proximal Katnook, Haselgrove and Ladbroke Grove gas condensate fields which have all produced from the Pretty Hill Formation. In the event of success at Nangwarry 1, hydrocarbons could be rapidly commercialised given its proximity to existing production infrastructure which includes the Katnook gas processing plant. The drilling of Nangwarry 1 forms part of a farm-in agreement that was completed on 28 May 2018. Under the terms of the agreement, joint venture partner Vintage Energy Ltd acquired an additional 25% interest in the licence by assisting with the funding of the Nangwarry 1 exploration well on a 50:50 basis with Rawson. The joint venture had previously been successful in applying for a PACE (Plan for Accelerating Exploration) gas grant from the South Australian government, receiving AUD 4.95 million after executing the PACE Funding Deed. The funds will cover approximately 50% of the cost of the planned Nangwarry 1 well. PEL 155, which covers an area of 226 sq km, was awarded on 30 June 2003. Interests in the permit are: Lakes Oil subsidiary Otway Energy Pty Ltd (50% plus operatorship) and Vintage Energy Ltd subsidiary Vintage Oil & Gas (50%).

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

South Natuna Sea Block B, ops terminated early Nov ’18 after gas tested in October, w.o. results, COSL Boss JU released. Medco (op), partner Prime Natuna Egy.

SW Bawal-1 expl South Natuna Sea Block B, ops terminated early Nov ’18 after gas tested in October, w.o. results, Medco (op), partner Prime Natuna Egy.

PEMEX suspended with results unreported the Bedel 101EXP directional new-pool wildcat (NPW) in the AE-0040-2M-Tesechoacan-02 (AE-0131-Llave) entitlement block in the onshore Veracruz Basin during mid-December 2019. The NPW was spudded on 27 August 2019. The NPW had a proposed total depth (PTD) of 3,535 m measured depth (MD) and 3,490 m true vertical depth (TVD). The well is located in the southwestern area of the block, south of the Bedel Field, and was targeting the middle Miocene in a separate fault block in two intervals, one at approximately 3,000 m and one at 3,910 m. The unrisked prospective resources for the NPW was estimated to be 9 MMboe. The total estimated drilling cost was USD 7.25 million with USD 1.50 million estimated to be for completion operations. On 8 August 2019, the CNH approved the drilling permit request submitted by PEMEX for the Bedel 101EXP new-pool wildcat (NPW) in the AE-0040-2M-Tesechoacan-02 entitlement block which was converted to the AE-0131-Llave entitlement block on 28 August 2019. The 1,168.11 sq km AE-0040-2M-Tesechoacan-02 entitlement block was granted by SENER to Pemex 100% through Ronda 0 on 27 August 2014. The entitlement expired on 27 August 2019 and replaced by the AE-0131-Llave entitlement block on 28 August 2019. On 6 August 2019, the CNH approved modifications to the exploration plan submitted by PEMEX for the AE-0040-2M-Tesechoacan-02 entitlement block in the onshore Veracruz Basin. The approved modifications include the drilling of 1 firm commitment exploration well and one contingent, incremental exploration well.

Mexico (Veracruz B.) Bedel

NW Razzak block, W. Desert, TD 3,767m, compl. o&g late Sep ’18, ST-10 rig. Targets Bahariya, Kharita, Alamein + Alam El Bueib 1.

Egypt (Alamein Sub-basin (Northern Egypt B.)) Alamein

Verkhne-Salymskoye licence, Khanty-Mansiysk AO, W. Siberia), TD 3,300m, new pool in the Neocomian Cherkashinskaya fm, tested 598 bo/d from 2,580-2,593m and 1,151 b/d from follow-up Verkhne-Salymskaya-58, 2,267-2,278m. Both wells TD’d in 1Q ’18.

Verkhne-Salymskaya-65 npw Verkhne-Salymskoye licence, Khanty-Mansiysk AO, W. Siberia), TD 3,300m, new pool in the Neocomian Cherkashinskaya fm, tested 598 bo/d from 2,580-2,593m and 1,151 b/d from follow-up Verkhne-Salymskaya-58, 2,267-2,278m. Both wells TD’d in 1Q ’18.

Angostura Sur block in TdF, Austral Basin, TD 2,128m, re-entered late 2017 for more testing of the Tobifera fm, well now completed.  Roch (op), partners Crown Point, Pluspetrol, San Enrique Petrolera, Desarrollo Petrolero Ganadero + Secra.  

San Martin-1001 nfw op. by Roch (op), partners Crown Point, Pluspetrol, San Enrique Petrolera, Desarrollo Petrolero Ganadero + Secra. re-entered late 2017 for more testing of the Tobifera fm, well now completed.

On 17 March 2019, Abu Dhabi National Oil Company (ADNOC) announced the award of the 6,116 sq km Onshore Block 4 Exploration concession, offered in the Abu Dhabi Licensing Block Bid 2018, to INPEX Corporation. The contract, which includes provision for the appraisal of existing discoveries, will be operated 100% by INPEX subsidiary JODCO Exploration Limited throughout an exploration period extending up to nine years. It stated that the company will invest up to US$ 176 million (AED 646 million), including a participation fee. The contract will be valid for 35 years if extended through to development stage, when ADNOC will have the opportunity to back in and assume a 60% working interest. Following approval from the Supreme Petroleum Council (SPC) the contract was signed in Abu Dhabi by UAE Minister of State and ADNOC Group CEO Dr. Sultan Ahmed Al Jaber and President and CEO of INPEX CORPORATION Takayuki Ueda. Block 4 is contiguous to the Emirate of Dubai and encompasses over 70km of Abu Dhabi coastline. Much of the acreage has not been licensed for many years and remains underexplored. SPC had indicated on 4 November 2018 that it expected the first exploration and production licenses relating to the Abu Dhabi Licensing Block Bid 2018 to be awarded during the first quarter of 2019. It subsequently approved the initial award of two offshore blocks to a consortium led by Eni SpA in January 2019.  INPEX Corporation participated in a highly competitive bid round process. UAE Minister of State and Chief Executive Officer of ADNOC Group H.E. Dr. Sultan Ahmed Al Jaber confirmed that “39 bidding parties from all over the world” had elected to actively join the bid round process, which closed during October 2018. ADNOC had launched its inaugural bid round in early April 2018 after delineating four onshore and two offshore blocks for commercially competitive bidding. Abu Dhabi remains underexplored and the blocks on offer encompass significant, multi-billion barrel yet-to-find potential.  Some of the blocks offered in the 2018 bid round contain existing discoveries and ADNOC estimated that blocks offered encompassed 310 undrilled reservoirs located within 110 mapped prospects and leads. In addition to the country’s conventional potential, the offered blocks also contain significant unconventional resource potential. Successful bidders entered agreements that, providing defined targets are achieved in the exploration phase, will give them the opportunity to then develop and produce any discoveries with ADNOC, under terms set out in the bidding package.

Inpex (6116km²) has been awarded an onshore Block 4 exploration block as part of Abu Dhabi’s first ever competitive bid round for new licensing opportunities.

In June 2019 industry sources confirmed that the Federation of Bosnia and Herzegovina is planning a bidding round. Preparation are ongoing and the bid may be launched in late 2020. It is yet to early to know how many blocks will be available for the bidding. The area to be on offer is believed to be situated in the western part of the Federation. The Republic of Bosnia and Herzegovina is divided in two political entities – the Federation of Bosnia and Herzegovina and the Republic of Srpska – and the district of Brcko which is a self-governing administrative unit in the northeastern part of the country. In early November 2011 the government of the Federation of Bosnia and Herzegovina signed a Memorandum of Understanding (MOU) with Shell to explore potential natural oil and gas accumulations and develop a data room. According to Shell studies the Dinaridi area have oil especially in the area of Gornja Dreznica. Oil was also spotted near the Posavina enclave (north) and Majevica (northeast). The findings made by Amoco between 1989 and 1991 showed up a large oil basin located in the area covering the Glamoc and Livno plains, Gornja Dreznica, and the inland area of Neum. In those areas of the Federation of Bosnia and Herzegovina, oil is estimated to be at depth ranging from 4,000 m to 8,000 m and could reach up to 500 million tons. In the eastern part of the Federation – near Tuzla - Amoco reported four locations with oil at depth between 1,000 m and 1,300 m which could hold around 70 million tons. Following Shell’s decision of early October 2015 to put an end to its exploration project in the country, local paper Dnevni Avaz announced that Croatian INA, Australian Key Petroleum, French Total and British Spectrum had sent letters of intent to the Federation between late October 2015 and mid-February 2016.   .

The authorities are planning for a licensing round, tentative opening in late 2020. The proposed offering would lie in the W. part of the B-H, too early for any inventory.

JP-1 prospect in Rabat Deep Offshore block, Doukkala Basin, P&A’ing dry at TD 3,180m, Saipem 12000 DS. Target Jurassic. Eni (op) partners Woodside, Chariot, Onhym 25% carried.

Morocco, Rabat Deep Offshore

On 21 June 2018, the ANP approved the 50% working interest transfer in the 42.73 sq km Rio Ipiranga production concession to Imetame Energia Lta by operator IPI Oil Exploracao de Petroleo Ltda.  IPI will remain the operator with 50% working interest and Imetame has 50% non-operated working interest.  On 19 March 2014, the ANP approved the sale of 100% working interest that Cheim Transportes SA held in the 42.73 sq km Rio Ipiranga production concession to IPI Oil Exploracao de Petroleo Ltda.  Cheim Transportes produced an average of 14.92 bo/d in 2013 from the 1-CAN-003-ES (1-BRSA-057-ES) wildcat completed by Petrobras in 2001 but never developed.  Cheim Transportes was awarded the block on 4 December 2006 after being the high bidder in the ANP 2nd Marginal Fields Round.

IPI (->50% op.) tranfered 50% non op. WI in Rio Ipiranga production concession to Imetame Energia

Eriell Group, the drilling company, has reported a large flow of gas from well Uzunshor 11. The well was spudded at the end of October 2019. At the end of January, it tested 434,000 cu m/d (14.9 MMscf/d) of gas and 6.4 tonnes (ca. 50 b/d) of condensate, from a depth of 2,675 m. The well has been drilled in the transborder Uzunshor-Kishtivan gas field shared between Uzbekistan and Turkmenistan. Its Uzbek part is operated by Uzbekneftegaz. The Turkmen part was discovered in 1970, while the Uzbek part was originally drilled in 1975. The field's reserves, prior to the latest test, were estimated at 188.7 Bcf of gas and ca. 1 MMb of condensate and oil, in Callovian-Oxfordian Carbonates. The field has not been developed since its discovery.

Eriell Group, the drilling company, has reported a large flow of gas from well Uzunshor 11, it tested 434,000 cu m/d (14.9 MMscf/d) of gas and 6.4 tonnes (ca. 50 b/d) of condensate, from a depth of 2,675 m. The well has been drilled in the transborder Uzunshor-Kishtivan gas field shared between Uzbekistan and Turkmenistan.

On 1 December 2017, Chevron USA was awarded Garden Banks Block GB 978 (lease G36101), situated in the East Texas Coastal Basin. GB 978 was originally offered as part of Western Gulf of Mexico Lease Sale 249, which was held on 16 August 2017. The lease is expected to expire on 30 November 2024. Following formal award, Chevron USA is now the operator and sole interest-holder (100% WI + Op) in GB 978.

Not Found

On 17 January 2018, industry sources revealed that Glencore Exploration Ltd (Glencore) sold 50% of its interest in the Bolongo block to Perenco plc (Perenco) who took over operatorship of the tract. The resulting ownership of the Bolongo permit is Perenco (50% operated interest), alongside with Glencore (50% working interest). Of note, the Bolongo block has been reduced in size at the end of 2017 (232 sq km) in order to delineate a new Bolongo Exploration permit that is included in the Licensing Round 2018. The company deal is understood to be driven by the upcoming development and production from the Oak oil field, discovered by Glencore in November 2012 and expected to bring an additional 10,000 bo/d to the country’s output in 2018. Oil production in 1H 2017 in Cameroon averaged 80,000 bo/d.  

Glencore sold 50% of its interest in the Bolongo block to Perenco who took over operatorship of the tract. The resulting ownership of the Bolongo permit is Perenco (50% operated interest), alongside with Glencore (50% working interest).

Abu Dhabi National Oil Company (ADNOC) announced on 13 November 2018 that it has signed an agreement, awarding Eni a 25% interest in its offshore ultra-sour gas mega project. The Ghasha Concession consists of nine fields, which include the Hail, Ghasha, Dalma and other offshore fields. It will be valid for a 40-year term. ADNOC will retain a 60% interest in the concession and is in discussions with other potential partners for the remaining 15% interest, which is earmarked for foreign oil and gas companies.<P />The award follows the Supreme Petroleum Council's approval of ADNOC's new gas strategy. The company wants to unlock and maximize value from the Emirate's substantial available gas reserves, as the United Arab Emirates moves towards gas self-sufficiency and aims to transition from a net importer of gas to a net gas exporter.<P />The Hail, Ghasha and Dalma ultra-sour gas project will tap into the Arab basin, which is estimated to hold multiple Tcf of recoverable gas. The project is expected to produce more than 1.5 Bcfg/d when it comes on stream around the middle of the next decade. The Ghasha Concession is expected to produce enough gas to provide electricity to more than two million homes. Once complete, the project will also produce over 120,000 barrels of oil and high value condensate per day.<P />In developing the Hail, Ghasha and Dalma Arab reservoirs, ADNOC will capitalize on its world-leading expertise and successes in ultra-sour gas development, gained from the development of the Shah Arab reservoir, creating an ultra-sour gas hub for the region.

Abu Dhabi National Oil Company (ADNOC) announced on 13 November 2018 that it has signed an agreement, awarding Eni a 25% interest in its offshore ultra-sour gas mega project. The Ghasha Concession consists of nine fields, which include the Hail, Ghasha, Dalma and other offshore fields.

In early March 2020, Beni Suef Petroleum Co reported to have successfully tested the West of Nile X 33 development well at the West of Nile X field, East Beni Suef (Dev) West of Nile X block, Gindi Basin. The well was spudded on 18 November 2019 and drilled to a TD of 2,130 m. The company was targeting the Upper Cenomanian sandstones of the Abu Roash G Member. The West of Nile X field was discovered in January 2015 after de new field wildcat West of Nile X 01 encountered oil in the Abu Roash Formation at around 2,500 m. The field was developed with 16 wells, from which three were completed as water injectors. It was brought on stream in 2015. Beni Suef Petroleum Co is a JV between EGPC (50%), Dana Petroleum (25%), Apache (16.75%) and Sinopec (8.25%). It is operating the East Beni Suef (Dev) West of Nile X block since July 2015.

Beni Suef Petroleum Co successfully tested West of Nile X 33 development well, West of Nile X field, East Beni Suef (Dev) West of Nile X block, Gindi Basin

Premier reports a sale agreement in relation to its interests in PL 089 and P 534 containing the Wytch Farm field to Perenco. This would imply the sale to Verus Petroleum has not pushed through as announced on 12 Sep ’17, and includes an unchanged cash consideration of USD 200 MM and the release of Premier from letters of credit totalling approximately USD 75 MM.  The effective date of the sale to Verus would have been 1 Jul ‘17. Partnership so far Perenco (op) 53.365%, Premier 34.135%, Ithaca 7.5%, Repsol Sinopec 5%.

Premier Oil has entered into a sale and purchase agreement to sell its interests in Licences PL089 and P534, containing the Wytch Farm field, to Perenco (->87.6% + op, Ithaca 7,4%, Repsol Sinopec 5%).and no to Verus Petroleum SNS.

E. part of OML 100, SE Delta shallow waters, ops terminated 24 Feb ’18, results n/a, Frigg JU. Note: earlier referred to as ENO-1. Total (op), partner NNPC.

E. part of OML 100, SE Delta shallow waters, ops terminated 24 Feb ’18, results n/a, Frigg JU. Note: earlier referred to as ENO-1. Total (op), partner NNPC.

Santos Ltd spudded the Ute 1 exploration well in ATP 1189-P, located in the Cooper-Eromanga Basin, on 22 December 2019. The well was drilled to a total depth of 2,401 m, before being suspended as a gas discovery on 1 January 2020. The well was part of Santos' ongoing exploration programme within the ATP 1189-P permit. ATP 1189-P, which covers an area of 3,452 sq km, was awarded on 1 January 2015. The well was located in the Aquit. B block, in which participants are Santos Ltd (25% + Operator), Santos subsidiaries Vamgas Pty Ltd (5%) and Santos Petroleum Pty Ltd (25%) and Beach Energy subsidiaries Lattice Energy Ltd (25%) and Delhi Petroleum Pty Ltd (20%).

Ute 1 (Santos 55% op. Beach Energy 45%) in ATP 1189 Aquitaine B Block, gas discovery.

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

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

In April 2017, Qarun Petroleum completed the Yamama-5 development well as an oil producer in the Farasha development block. The well spudded on 6 April 2017 with the “EDC-65” land rig and was completed in late-April 2017, after reaching a TD of about 2,250 m. The main targets of the well were the Abu Roash ”G” and Upper Baharyia Members. Qarun Petroleum Co is a JV between the EGPC (50%), Apache Oil Egypt (25.125%), Dana Petroleum (12.5%) and Sinopec IP Corp (12.375%). Yamama is an oil field located in the Farasha development block, Abu Gharadiq Basin. The field was discovered in 2003 and it is still developing since 2004.

Egypt (Gindi B.) ? op. by APACHE (50.25%, KNOC 25.0%, SIPC 24.75%, QPC 0.0%) in Qarun (Dev) block

N. part of 21/97/p Lubaczow-Zapalow block, Outer Carpathian Foredeep in SE Poland, gas find (commercial) in several horizons below 700m, testing underway. Early results show a prod. potential of >50 MMcf/d. Appraisal drilling is planned. PTD was 900m, target Sarmatian-Badenian clastics.

Nowe Siolo 1 op. by PGNiG (100%) in the 21/97/p Lubaczow-Zapalow permit, encountered commercial quantities of gas in several horizons. The preliminary results of the tests indicate that the annual output from the field, found in several shallow Miocene horizons, could reach 0,7 Bcfg.

PL 295, Cooper-Eromanga, drilled late Dec ’17, susp. oil at TD 1,352m, 3.7m net pay in the Birkhead fm. The well is being assessed as a water injector to assist future field production.  Santos (op), partner Beach.

Mulberry 37 oil appraisal well, Santos QNT Pty Ltd (48% + Operator), Vamgas Pty Ltd, a Santos subsidiary, (12%) and Drillsearch Energy Pty Ltd, a Beach Energy subsidiary, (40%)., a total 3.7 m net oil pay was encountered.

The ANP granted the 2.85-sq km Fazenda Sori and 5.06-sq km Pojuca Norte field leases in the onshore Recôncavo to Brasil Refinarias on 5 May '20. Both had been issued under the 1st ANP Open Door Bid Round.

The ANP granted the Fazenda Sori (2.85km²) and 5.06km²) Pojuca Norte field onshore leases to Brasil Refinarias. Both had been issued under the 1st ANP Open Door Bid Round.

Theia is offering a 30-50% equity in EP 493, 4,628 sq km in the Canning Basin, in return for contributions to the next phase of exploration + historical costs on the permit and possibly the drilling of Helios-1 once a fracking moratorium is (ever) lifted. Contact:Ryan Taylor-Walshe, email: [email protected]. * Theia Energy, previously Finder Shale.

Theia is offering a 30-50% equity in EP 493, 4,628 sq km in the Canning Basin, in return for contributions to the next phase of exploration + historical costs on the permit and possibly the drilling of Helios-1 once a fracking moratorium is (ever) lifted.

On 5 September 2018 the NPD announced that Equinor has acquired a 10% interest in PL 644 and PL 644 B from Spirit Energy. The deal is effective from 31 August 2018. PL 644 covers part of blocks 6506/8, 6506/10 and 6506/11 and PL 644 B covers a 28 sq km area over the northern part of block 6506/11, and was awarded in APA 2015. The 2018 Hades / Iris discovery is located in PL 644 B. In the first half of 2019 OMV will return to the licence to drill an appraisal well targeting upside potential to the south of the discovery well (see separate article for more information). Exploration well 6506/11-10 was drilled between November 2017 and April 2018 on the HPHT Hades and Iris prospects and confirmed gas condensate discoveries in both prospects. The Hades reservoir is the Lower Cretaceous Lange Formation at 3,932 m. A 35 m gas condensate column was proven with 15 m of net sandstone. No GWC was found. Estimated recoverable reserves range from 19 to 113 MMboe. The Iris reservoir was confirmed at 4,223 m. The Middle Jurassic Garn Formation contains a 95 m gas condensate column with 85 m of net sandstone. The GWC lies at 4,295 m subsea and recoverable reserves are estimated at 19-132 MMboe. Pressure data has shown that the two hydrocarbon columns are not in communication. In an August 2018 update, partner Faroe reports contingent resources of 63-322 MMboe for Hades and Iris (with a 2C of 210 MMboe). Following completion of the deal interest in both licences is split between OMV (Norge) AS (30% + operator), Equinor Energy AS (40%), Faroe Petroleum Norge AS (20%) and Spirit Energy Norge AS (10%).

Norway (Voring) Equinor (->40%, OMV 30% Op, Faroe 20%) has acquired 10% from Spirit Energy (->10%) in licences PL 644 and 644 B.

BP is looking to dilute its 100% ownership of the Ampasindava (7,360 sq km), Majunga North (13,368 sq km) + Majunga South (10,900 sq km) offshore blocks, recently extended with a seismic-or-drop decision due in Sep '20. Commitments would include 2,000 sq km of 3D seismic in each permit. Locations mostly in the Majunga Basin.

BP is looking to dilute its 100% ownership of the Ampasindava (7,360 sq km), Majunga North (13,368 sq km) + Majunga South (10,900 sq km) offshore blocks, recently extended with a seismic-or-drop decision due in Sep '20. Commitments would include 2,000 sq km of 3D seismic in each permit. Locations mostly in the Majunga Basin.

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

Argentina, El Porvenir (CNQ-15 M)

On 29 January 2018, Imetame with 100% working interest was granted official awards by the ANP for the ES-T-354, ES-T-373, ES-T-441, ES-T-477, and ES-T-487 blocks in the onshore Espirito Santo Basin from the ANP Round 14.    

Imetame with 100% working interest was granted official awards by the ANP for the ES-T-354, ES-T-373, ES-T-441, ES-T-477, and ES-T-487 blocks in the onshore Espirito Santo Basin from the ANP Round 14.

Andalas has reached a conditional agreement to acquire a 25% interest in the 447-sq km Bunga Mas PSC (Bungamas) in South Sumatra, with the right to increase to 49% and then 100%. Completion is subject to usual conditions including the extension of the explo term of the PSC, which comprises rights to the Bunga Mawar oilfield (45 API oil at ab. 700m).  The Bunga Mas PSC was last held by Bunga Mas Intl (op), Bunga Mas Energi and Dorato Fiore Pacifico until relinquishment in July 2017. Its current status is unclear.

Andalas has reached a conditional agreement to acquire a 25% interest in the 447-sq km Bunga Mas PSC (Bungamas) in South Sumatra, with the right to increase to 49% and then 100%.