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Turkmennebit (Turkmenneft) has resumed appraisal (outpost) drilling in the Ekizak gas/condensate field in western Turkmenistan (onshore South Caspian Basin). Well Ekizak 16 has been drilled to a TD of 3,600 m and has tested gas. Although the operator does not provide any further technical details of the test, the well may have discovered a new pool as the previously established reservoir in the Lower Red Bed Series occurs at a shallower depth of 2,770 m. The Ekizak field was discovered in 1977. A total of 17 exploration and appraisal wells had been drilled in the field before drilling operations were terminated in 1981. The field’s initial recoverable 2P reserves are estimated at 146 Bcf of gas and 1 MMb of condensate. The Pliocene Red Bed Series is the main regional hydrocarbon play in the South Caspian Basin’s Turkmenistan sector.

Ekizak-16 appr Ekizak gas/cond field area, South Caspian Basin in W. Turmenistan, TD 3,600m, tested gas from what is possibly a new, deeper pool than the standard Lower Red Bed at 2,770m.

Shell has entered the West African Atlantic Margin exploration basin, with its signature of 2 PSCs for blocks C-10 and C-19. The blocks are located in WDs 20 – 2,000m and cover a joint area of 23,675 sq km. C-10 is composed of former blocks C-10 (relinquished by Tullow in early 2018), C-28 and C-29. Chariot Oil & Gas relinquished C-19 in 2016 and has a back in right for a 10-20% working interest. For now, Shell has a 90% stake and state oil company Société Mauritanienne des Hydrocarbures et de Patrimoine Minier holds 10%.

Shell (90% op. SMHPM 10%) has signed up to explore two blocks C-10 and C-19. The blocks are located in WDs 20 – 2000m and cover a joint area of 23,675 sq km. C-10 is composed of former blocks C-10 (relinquished by Tullow in early 2018), C-28 and C-29. Chariot O&G relinquished C-19 in 2016 and has a back in right for a 10-20% working interest

On 28 January 2019, Gran Tierra Energy (GTE) announced they found hydrocarbons, assumed to be oil, in the Cocona 2 outpost in the PUT-1 Block based on the results of the Vonu 1 discovery. Operations were suspended and GTE indicated the Cocona 2 outpost will have a production test during the first quarter of 2020. The Cocona 2 outpost spudded on 22 December 2019 after the Cocona 1 outpost was junked. The Cocona 2 outpost spudded from a second cellar at the same pad site as the Cocona 1 outpost. The Cocona 2 outpost reached the planned total depth of 10,603 ft (3,232 m). GTE indicated that operations were suspended due to mechanical failure. The Cocona 2 outpost was targeting the Upper Cretaceous N, U sands and the fractured A-Limestone successfully tested with the Vonu 1 discovery. It is assumed the target is a faulted anticline. The 463.96 sq km PUT-1 Block is owned and operated 100% by GTE. The original block was initially awarded in March 2009 to Lewis Energy Colombia (operator, 100%). In August 2010, GTE became the operator of the block with 55% working interest, and Lewis Energy kept the remaining 45%. GTE became the only owner and operator of the PUT-1 Block in November 2018. Background Information GTE reported plans to spud the Cocona 1 outpost well in late November 2019. The Cocona 1 was the first appraisal well to be drilled for the Vonu 1 discovery, GTE's most successful Villeta A Limestone exploration well to date. The Vonu 1 was discovered in 2017 and is currently producing over 400 Bboe/d from the Villeta A. On 5 June 2017 GTE had announced a multi-zone oil discovery in its Vonu 1 new-field wildcat (NFW) located on the PUT-1 Block. Log interpretation indicated oil saturation within six separate reservoirs having a cumulative pay thickness of some 157 ft (48 m) true vertical depth (TVD). The well encountered 8.2 ft (2.5 m) of net oil pay in the Villeta N Sand Member, 3.4 ft (1 m) of net oil pay in the Villeta M1 Limestone Member, 8.7 ft (2.6 m) of net oil pay in the Villeta M2 Limestone Member, 91.1 ft (27.7 m) of net oil pay in the Villeta A Limestone Member, 15.3 ft (4.6 m) of net oil pay in the Villeta U Sand Member and 30.7 ft (9.3 m) of net oil pay in the Villeta T Sand Member. GTE expected to test all zones individually during June 2017. The Vonu 1 NFW was spudded on 6 May 2017 aimed at the multi-zone structural prospect defined on 3D seismic as separate from the adjacent Costayaco field. The directional well targeted the Caballos Formation, the Villeta U, T and N Sand Members and the Villeta A Limestone Member.

Cocona-2 appr Vonu Este pad, appraisal to Vonu discovery in PUT-1 block, Putumayo Basin, spudded 22 Dec '19 in replacement of Cocona-1 (junked), suspended late Jan '20 at TD 3,232m after encountering (believed) oil, testing planned. Target Upper Cretaceous N + U sands and A-Limestone.

On 28 October 2019, the Federal Agency for Subsoil Use announced an auction for six blocks in Yamalo-Nenets Autonomous Okrug (Western Siberia). The auction is scheduled on 17 December 2019 with its application deadline on 25 November. On 13 November, the Agency changed starting prices for the offered blocks and extended an application deadline for the block until 2 December. The winners of the auction will obtain 25-year E&P licenses with a seven-year exploratory stage. Additional information may be requested from: Uralnedra 620014, Yekaterinburg, Vaynera str., 55, office 425, [email protected] The Ladertoyskiy Vostochnyy block covers 952 sq km in the South Kara-Yamal Province. Seismic coverage amounts to 447 km of 2D data. No wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 117 MMbbl of oil, 6.316 Tcf of gas and 132 MMbbl of condensate. The starting price amounts to RUB 73.405 million (USD 1.15 million). The Kharampurskiy Zapadnyy block covers 898 sq km in the Nadym-Taz Province and encompasses the Kharampurskoye Zapadnoye oil discovery with 3P reserves estimated at 31 MMbbl and seven prospects with combined resources estimated at 43 MMbbl of oil and 82 Bcf of gas. Seismic coverage amounts to 1,300 km. Six wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 100 MMbbl of oil, 3.743 Tcf of gas and 69 MMbbl of condensate. The starting price amounts to RUB 402.826 million (USD 6.29 million). The Mitikyakhskiy 1 block covers 1,188 sq km in the Nadym-Taz Province and encompasses several prospects with combined resources estimated at 139 MMbbl of oil, 2.776 Tcf of gas and 93 MMbbl of condensate. Seismic coverage amounts to 2,069 km. Two wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 485 MMbbl of oil, 325 Bcf of gas and 10 MMbbl of condensate. The starting price amounts to RUB 539.81 million (USD 8.43 million). The Yamburgskiy Severnyy block covers 2,101 sq km in the Nadym-Taz Province and encompasses a part of the Mitiyakhskaya prospect with resources estimated at 11 MMbbl of oil, 206 Bcf of gas and 7 MMbbl of condensate. Seismic coverage amounts to 2,994 km of 2D data and 151 sq km of 3D data. One well has been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 750 MMbbl of oil, 22.461 Tcf of gas and 370 MMbbl of condensate. The starting price amounts to RUB 353.833 million (USD 5.53 million). The Yamburgskiy Yuzhnyy block covers 1,590 sq km in the Nadym-Taz Province and encompasses parts of the Urengoyskoye and Olikuminskoye fields with combined 3P reserves estimated at 56 MMbbl of oil, 419 Bcf of gas and 10 MMbbl of condensate. Also, the block includes the Khosyreyskaya Vostochnaya prospect with resources estimated at 16 MMbbl of oil, 184 Bcf of gas and 1 MMbbl of condensate. Seismic coverage amounts to 2,550 km. Three wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 606 MMbbl of oil, 16.724 Tcf of gas and 251 MMbbl of condensate. The starting price amounts to RUB 969.14 million (USD 15.1 million). The Yaptiksalinskiy block covers 1,507 sq km in the South Kara-Yamal Province and encompasses several prospects with combined resources estimated at 69 MMbbl of oil, 2.12 Tcf of gas and 24 MMbbl of condensate. Seismic coverage amounts to 1,715 km. Two wells have been drilled in the area. Hydrocarbon resources of the block (categories D1+D2) are estimated at 71 MMbbl of oil, 4.795 Tcf of gas and 88 MMbbl of condensate. The starting price amounts to RUB 242.515 million (USD 3.79 million).

On 28 October 2019, the Federal Agency for Subsoil Use announced an auction for six blocks in Yamalo-Nenets Autonomous Okrug (Western Siberia). The auction is scheduled on 17 December 2019 with its application deadline on 25 November. On 13 November, the Agency changed starting prices for the offered blocks and extended an application deadline for the block until 2 December.

In August 2020, the Agencia Nacional de Hidrocarburos (ANH) published the status of Exploration and Production (E&P) contracts and Technical Exploration Agreements (TEAs) valid as of 30 June 2020, and indicated that the Merecure Block in the Llanos Basin, is now operated by Cepsa Colombia with 35% working interest, and non-operating partners Parex Resources Colombia Ltd with 35% working interest and Perenco with the remaining 30%. Parex announced on 7 March 2019 it had signed a farm-in agreement to acquire 35% working interest from the 70% working interests owned by operator Cepsa Colombia. As part of the agreement, Parex would pay 100% of the cost to drill two exploration wells. Parex indicated that the Tamariniza 1 new-field wildcat (NFW) was drilled in the second quarter of 2019 as part of the agreement. In March 2007, the original 2,381.90 sq km Merecure Block was awarded to operator Cepsa, with 100% working interest. Petrobras farmed-in in the block in December 2008 acquiring 30% working interest and later in April 2014 Perenco took over the working interest previously owned by Petrobras. In October 2016, Cepsa relinquished part of the block remaining with 1,142.11 sq km, and in April 2020, it made a partial relinquishment again, so that now the Merecure block has an area of 571.11 sq km. Background Information In August 2019, Parex Resources reported oil in the Cepsa-operated Tamariniza 1 NFW. Tests yielded some 800 bo/d gross. The well was spudded on 12 March 2019 and reached a total depth (TD) of some 5,173 ft (1,577 m) on 25 March 2019.

(Llanos-Barinas B.) Merecure block, op. by MUBADALA I (70%), PERENCO (30%) the Agencia Nacional de Hidrocarburos (ANH) indicated that the Merecure Block is now operated by Cepsa Colombia with 35% working interest, and non-operating partners Parex Resources Colombia Ltd with 35% working interest and Perenco with the remaining 30%.

AleAnna Italia has been awarded the Bagnacavallo production concession. AleAnna Italia shareholder BRS Resources advised on 11 December 2018 that the Ministry of Economic Development had confirmed the award. The concession forms part of the Longanesi Field Unit (Padana Energia operated - 66.5%) which was in the final stages of authorisation during H1 2018. The award of the concession follows a Ministerial Decree issued by the Ministry on 7 December 2018 for an extension of the adjacent San Potito production concession (Padana Energia operated -100%). The Longanesi field was discovered by the NFW Abbadesse 1 Dir (2004, Grove, 3,043m) which tested at 15.4 MMcfg/d from three Lower Pliocene sands, and was estimated to hold 3P reserves of 85 Bcfg. AleAnna Energy LLC through subsidiary AleAnna Italia Srl operates the licence with 100% equity.

Italy, Bagnacavallo

CNOOC advises of a new PSC signed with Empyrean for block 29/11, 1,808 sq km in the PRMB, South China Sea, WD 300-600m. As customary, CNOOC has the right to participate with up to 51% in any commercial discoveries made.

CNOOC advises of a new PSC signed with Empyrean for block 29/11, 1,808 sq km in the PRMB, South China Sea, WD 300-600m. As customary, CNOOC has the right to participate with up to 51% in any commercial discoveries made.

According to official reports in late-April 2020, GeoPark has P&A'd the Huillin 1 new-field wildcat (NFW) on its Isla Norte block after encountering non-commercial oil at the total depth (TD) of 2,875 m (9,432 ft) in March 2020. The well was spudded in early-2020 with objective in conventional Springhill and Tobifera formations and planned investment of USD 2.16 million. GeoPark operates with 60% interest, joined by partner state company ENAP with the remaining 40%. Isla Norte block covers 598.3 sq km of land in the Tierra del Fuego region of Magallanes Basin. The block is currently in the second exploration period with commitment of drilling two exploratory wells by 7 November 2020. Beside Huillin 1, GeoPark has also filed an EIA with the Chilean environmental regulator SEIA to drill the Koo X1 exploration well with the same objective and planned investment of USD 0.76 million. However, the company has reduced its 2020 capital expenditures program by 60% in late-March 2020 due to pressure from the low oil price and outbreak of coronavirus disease 2019 (COVID-19). Background Information Geopark received validity extension for all three Tierra del Fuego area blocks from the Chilean government in May 2019. According to official reports in November 2019, GeoPark plans to invest between USD ten to fifteen million in Chile in 2020 with focus on drilling four exploration wells targeting oil in the Tierra del Fuego area blocks of Campanario, Flamenco, and Isla Norte.

Huillin X 1 nfw. (GeoPark 60% op, ENAP 40%), committed well in Isla Norte block, logged as non-commercial, to P&A. Targets Tobifera + Springhill Fm's. TD=2876m.

Yibal field area in block 6, Fahud Salt sub-basin, ops terminated 19 Oct '19 at TD 1,240m, rig 49. Target Triassic Jilh fm.

Yibal W.-1 expl (PDO 100%) Yibal field area in block 6, Fahud Salt sub-basin, ops terminated at TD 1,240m Target Triassic Jilh fm. Results n/a yet.

South Idku Onshore block 1, Nile Delta, P&A dry at TD 4,074m during late summer '19, EDC rig 57. Main target Miocene.

Idku S.-2 (Jb 54-1) nfw inSouth Idku Onshore block 1, Nile Delta, P&A dry at TD 4,074m, Main target Miocene.

Back in August, Vintage signed with Beach to acquire the latter’s 100% in EP 126,  6,740 sq km mostly onshore in the Bonaparte Basin. The deal remains pending usual approvals.

Vintage signed with Beach to acquire the latter’s 100% in EP 126, 6,740 sq km mostly onshore in the Bonaparte Basin.

Shell Australia announced on 21 Novemebr 2018 that it had reached an agreement to sell its 26.56% interest in the Greater Sunrise asset to the East Timor Government.  Shell becomes the second company to sell its interest in the project to the government, after ConocoPhillips reached a similar agreement in October 2018. The sale and purchase agreement entered into by Shell and the East Timor Government, values the interest at USD 300 million (AUD 414 million).  Shell reported that the sale is in line with its global strategy, which is seeing it become a “simpler and more resilient company”. The sale and purchase agreement is conditional on a number of conditions, including regulatory approvals, joint venture pre-emption rights and funding approvals. Upon completion of the deal, Shell will assign its 26.56% interest in permits JPDA 03-19, JPDA 03-20, NT/RL2 and NT/RL4 to the East Timor Government.  The JPDA contracts are, at this stage, within the previous-Joint Petroleum Development Area (JPDA) waters.  These will be renegotiated as East Timor PSCs, after the new maritime boundary was outlined in March 2018. These are expected in late 2018/early 2019. The permits contain the Sunrise and Troubadour discoveries, that make up the Greater Sunrise assets.  The discoveries were made in 1975 and 1974 respectively and contain over 5 Tcf gas and 225 MMb condensate. Shell’s sale comes after ConocoPhillips reached an agreement to sell its 30% interest in the assets to the East Timor Government, though this also remains subject to similar conditions to the Shell sale.  Both companies outlined that they differed in opinion with the East Timor Government over how the Greater Sunrise fields should be developed. Shell reported that it “[understood] the priorities of the Timor-Leste Government”. The development scenario for the fields has been long debated, with the Greater Sunrise joint venture (JV) preferring a Floating LNG (FLNG) option, over the East Timor Government’s suggestion to pipe the hydrocarbons back to an onshore plant in East Timor.  The JV have indicated this would be more costly, but also difficult as a development due to the bathymetry between the discoveries and East Timor. Both deals will have significance, as the East Timor Government has outlined that its preference remains, and with greater interest in the project it will have additional input into the development decisions. Upon announcement of the initial transaction, the East Timor Government reported that it would proceed with further discussions with the JV to evaluate the future development.  Woodside, operator of the assets, has indicated that the project falls under its “Horizon III” planned developments, which are scheduled for post-2027.   The Great Sunrise fields have been under discussion for development for some time, with Woodside initially planning to make a decision in 2009.  However a number of issues, including differing opinions in the development scenario, disputes around the maritime boundary and drop in oil price have pushed the development back a number of times.  Woodside has had several discussions with the East Timor government over the development, looking to come to an agreement. However the maritime boundary dispute put this on hold with Woodside reporting that it would wait for a resolution.   A new maritime boundary was agreed and the initial documents signed in March 2018.  The boundary is expected to be finalized and put in place in late 2018/early 2019.  The new maritime arrangement has included a “Special Regime” for Sunrise, which will see East Timor get at least 70% of the government revenues from the development, with the split to be 70:30 (in favour of East Timor) if the development sees a pipeline to East Timor, and split 80:20 if a pipeline to Australia is utilised.  It is not known if this will alter if the government has a stake in the project. Participants in the Greater Sunrise joint venture are: Woodside Petroleum Ltd (33.44% + Operator), OG ZOKA Ltd, a wholly owned subsidiary of Osaka Gas Co Ltd (10%) and Shell Australia Ltd (26.56%) and ConocoPhillips (30%) – both selling their respective shares to the East Timor Government.

Timor Sea JPDA, JPDA 03-20

PPL 36, Cooper-Eromanga, drilled and P&A dry between 16-20 Feb '20, TD 983m, Ensign rig 950. Santos (op), partner Beach sub's.

Ulandi-11 appr PPL 36, Cooper-Eromanga, drilled and P&A dry between 16-20 Feb '20, TD 983m, Santos (op), partner Beach sub's.

It has been reported in the media during May 2020, that Eni SPA could be looking to exit its Australia exploration and production position. A divestment process could be launched by end-May 2020 as the company is reported to be working with investment bank Citi to prepare the offering. It is thought that a divestment of its northern Australian portfolio could also include its Timor Leste position also. Eni's operations currently supply natural gas into the Australian Domestic market from the operated Blacktip gas field. Domestic markets are seen to be less exposed to the global demand and price fluctuations making the asset a stable, medium-term acquisition. Eni also holds an 11% stake in the Darwin LNG project, operated by ConocoPhillips (soon to be Santos). Both assets are in natural reservoir decline with Bayu-Undan gas and condensate field expected to cease around 2023. Darwin LNG is planned to be backfilled by the Barossa field, in which, Eni does not participate. Moving past 2023, production for Eni could be limited to the declining Blacktip field until new assets come on stream. The project could keep producing to the domestic market until around 2048. No financial investment decisions have been made for Eni's 'upside' projects including: Evan Shoals, Blackwood or Penguin. Any future development decisions would unlikely see gas production before in the next 10-15 years, but the portfolio is estimated to contain in excess of 700 MMboe of remaining resources (net to Eni). Near filed exploration or field de-development is another option to increase the upside of the portfolio from Eni's existing oil assets, such as Woollybutt and Kitan. Likely if sold, the assets could form one package, but could attract a consortium of buyers to handle the diverse nature of the assets across domestic gas production, LNG in Darwin and plant infrastructure. During Eni's time in Australia and Timor Leste, it has participated in over 90 wells, including 43 new field wild cats, since 1984. Moving to the northern Australian offshore basins in 2000, Eni is now thought to be preparing to divest its remaining gas assets.

Eni Australia Ltd, Eni Timor Leste SpA could be looking to divest its entire Australian gas portfolio

On 14 August 2018 Faroe Petroleum announced that it has agreed to acquire a 50% stake from AziNor Catalyst in the planned Plantain / Agar exploration and appraisal sidetrack well. The 50% in the well corresponds to Faroe picking up a 12.5% interest in licence P1763. The differing interests between the well and the licence interest is due to licence operator, Apache (50%), not participating in the drilling operations. The deal completed on 2 October 2018. The well is scheduled to spud in late August 2018 / early September 2018 with the company using the “Transocean Leader” rig. The plan is to target the Plantain Eocene oil prospect and then drill a sidetrack into the Agar oil discovery. Both Agar and Plantain follow on from the analogous Frosk oil discovery which was made by AkerBP in Norway earlier in 2018. AziNor estimate a mid-case resource of 60 MMboe (98 MMboe upside) for Agar and Plantain. Following completion of the deal interest in P1763 is held by Apache Beryl Limited (50% + operator), Cairn subsidiary, Nautical Petroleum Limited (25%), AziNor Catalyst Limited (12.5%) and Faroe Petroleum (12.5%).

Faroe Petroleum announced that it has agreed to acquire a 50% stake from AziNor Catalyst in the planned Plantain / Agar exploration and appraisal sidetrack well. The 50% in the well corresponds to Faroe picking up a 12.5% interest in licence P1763.

In December 2017, OMNIS and BP signed an agreement about the award of four offshore blocks in the Mahajanga region. The deal is subject to an approval by presidential decree.  

BP has reportedly been awarded 3 licences offshore Madagascar: 2001 C Ampasindava, 2001 A Majunga and 2002 Cape Saint-Andre. The licences are located in 0-3 000m WD in the, covering some 57 000km² in total.

An auction was held 31 Mar '20 for 20-yr rights to the 16.7-sq km Vetosskiy block in the Perm Kray (Volga-Ural Province) and home to the Vetosskoye oilfield. Zagorskiy won the run with a USD 80,000 offer (starting price USD 70,000). * Zagorskiy = Lukoi-Perm - RID Oil-Perm JV.

Lukoil 's JV wins the Vetosskiy license in Perm Kray.

P1028 / 1189, West of Shetlands, over 30m oil column (23 API), 18m net, 491m horiz section, tested on natural flow for 10 days, rate yet n/a (w.o. pressure buildup), West Hercules SS. Siccar Point (op), partner Shell.

204/10a-05 (Cambo) (Siccar Point 70% op. Shell 30%) pos. appr. in P1028/1189, over 30m oil column (23°API), 18m net, 491m horiz section, tested on natural flow for 10 days, rate yet n/a (w.o. pressure buildup). It was target the main Tertiary Hildasay sst. reservoir sequence.

Lundin has agreed to acquire Fortis’ 10% stake in PL 539 + 860 and its 30% in PL 820 S + 825. It also agrees to take a further 20% again in PL 860 but from Statoil, taking its total holding to 40%. Interests-to-be: PL 539 (Skagerrak on Danish border): MOL (op), partner Lundin PL 820 S (adjacent to above):  MOL (op), partners Lundin + Wintershall PL 825 (mid-SNS): Faroe (op), partners Lundin + Spirit Energy PL 860 (Central Graben): MOL (op), partners Lundin + Petoro.

Lundin has agreed to acquire Fortis’ 10% stake in PL 539 + 860 and its 30% in PL 820 S + 825. It also agrees to take a further 20% again in PL 860 but from Statoil, taking its total holding to 40%. Interests-to-be: PL 539 (Skagerrak on Danish border): MOL (op), partner Lundin PL 820 S (adjacent to above): MOL (op), partners Lundin + Wintershall PL 825 (mid-SNS): Faroe (op), partners Lundin + Spirit Energy PL 860 (Central Graben): MOL (op), partners Lundin + Petoro.

Kirthar Pakistan BV (KPBV), a subsidiary of Kuwait Foreign Petroleum Exploration Company (KUFPEC), has assigned 35% of its working interest in Paharpur 3170-5 EL (Indus Basin) onshore concession to Pakistan Petroleum Ltd (PPL) with effect from 29 November 2018. As a result, the revised equity split is as follows: KPBV 60.07% (operator), PPL (35%), Government Holdings (Pvt) Ltd (GHPL) 2.5% and Khyber Pakhtunkhwa Oil and Gas Company Ltd (KPOGCL) 2.43%. The licence, which covers an area of 2,213 sq km in the Dera Ismail Khan, Tank and Bhakkar districts of the Khyber Pakhtunkhwa / Punjab provinces, was exclusively awarded to KPBV on 13 March 2015. KPBV had subsequently assigned 2.5% working interest to GHPL and 2.43% to KPOGCL with effect from 13 March 2015. No wells have been drilled within the licence to date. KPBV had carried out 1,178 LKM 2D seismic acquisition (dynamite source) in the block from October 2016 to March 2017 using the Bureau of Geophysical Prospecting’s (BGP) ‘9501-B’ seismic crew. KPBV was granted a 12-month extension to the Phase-I of initial term of Paharpur EL from 13 March 2018 to 12 March 2019.

Kirthar Pakistan BV (KPBV), a subsidiary of Kuwait Foreign Petroleum Exploration Company (KUFPEC), has assigned 35% of its working interest in Paharpur 3170-5 EL (Indus Basin) onshore concession to Pakistan Petroleum Ltd (PPL)

An auction was held 4 Jul ’18 for the Katrannyy block, 3.3 sq km in the Terek-Caspian Basin in Dagestan (North Caucasus). Local Dagnefteprom won the 20-year rights with a USD 9,000 offer (starting price USD 8,000).

An auction was held 4 Jul ’18 for the Katrannyy block, 3.3 sq km in the Terek-Caspian Basin in Dagestan (North Caucasus). Local Dagnefteprom won the 20-year rights with a USD 9,000 offer (starting price USD 8,000).

5P Energy is selling a 50% stake in the Alfeld-Elze II-Erweiterung block, 64 sq km S. of Hannover in N Germany, to a yet-undisclosed company and is preparing a LoI for the final stage of contract discussions.

5P Energy (->50%), is selling a 50% stake in the Alfeld-Elze II-Erweiterung block, (64km²) S. of Hannover in N Germany, to a yet-undisclosed company.

Block 6, Fahud Salt sub-basin (Oman Basin), target assumed Gharif sst, ops terminated 17 Jan '20, TD 3,994m, results n/a, rig 45.

Al Husain-4 appr Block 6, Fahud Salt sub-basin (Oman Basin), target assumed Gharif sst, ops terminated 17 Jan '20, TD 3,994m, results n/a,

On 12 May 2020, Shell was granted formal approval by the CNH to sell its 40% working interest in the CNH-R02-L01-A15.CS/2017 contract, Block 15 to TOTAL SA. The new working interest breakdown for the block is as follow: TOTAL will hold 82% working interest (operator) and Qatar Petroleum International (QP) keeps the same 18% working interest.   The Block 15 (976.15 sqkm) was awarded on 25 September 2017 under the CNH-R02-L01-A15.CS/2017 contract and it is located offshore in water depths around 10 to 30 m. The previous block working interest were: TOTAL 42% working interest (operator), QP 18% and Shell 40%. This negotiation is subject to customary regulatory and other approvals by contract partners and Mexico's government. CNH will instruct the signing of the agreement modifying the CNH-R02-L01-A15.CS/2017 contract.

Shell was granted formal approval by the CNH to sell its 40% working interest in the CNH-R02-L01-A15.CS/2017 contract, Block 15 to TOTAL SA. The new working interest breakdown for the block is as follow: TOTAL will hold 82% working interest (operator) and Qatar Petroleum International (QP) keeps the same 18% working interest.

According to local reports in early-2020, state company ENAP has completed the Luche ZG 1 new-field wildcat (NFW) wells on its 100%-held Arenal block with tight gas from the Zona Glauconitica Formation in December 2019. A total of eight wells were spudded between August and November 2019 using a drilling pad to reach their total depths (TD) between 2,370 m (7,776 ft) and 2,566 m (8,419 ft) by December 2019. Arenal block covers 1,331 sq km of land in Magallanes Basin. Background Information ENAP’s Arenal block has been the best producer of unconventional gas in Chile the past several years with tight gas from the Zona Glauconitica Formation.

Chile (Austral B.) ? op. by ENAP (100.0%, ENAP 100.0%) in Arenal block

Premier Oil reported in late April 2020 that the company is finalizing the farm out of a 50% participating interest in the Tuna PSC, in the East Natuna Basin, with Zarubezhneft. The new partner also holds interests in exploration block 12/11 located across the border in Vietnamese waters. Premier reported in early January 2020 to have signed a Heads of Agreement with a new investor for the farm out of a participating interest in the block. As part of the agreement, the new partner will fully carry Premier for its share of expenditure in a planned two-well appraisal drilling campaign in the block. The drilling programme is intended to confirm commerciality of the Kuda Laut 1 and Singa Laut 1 gas discoveries (also known as “Tuna Field”) which are estimated to contain gross resources of approximately 100 MMboe. Drilling was previously planned for 2019 then delayed to 2H 2020 pending the farm out deal, but has been now postponed to 2021. Information as of January 2020 indicated that Premier has restarted the search for a suitable rig. In November 2018, Premier Oil reportedly signed an agreement for future gas sales from the Tuna PSC to PetroVietnam Gas (PV Gas). The block operator agreed to supply gas to PV Gas at a rate of 3.3 million cubic m per day (approximately 115 MMcf/d) starting from Q3 2024. Premier currently holds 80% operating interest in the Tuna PSC, partnering with MOECO (20%). Background Information The Tuna PSC was officially awarded to Premier and MOECO on 21 March 2007. The block was offered through regular tender under the second phase of the "Fifth Round" of Migas-controlled acreage releases which was formally announced on 15 August 2006 and closed on 26 December 2006. Signature bonus of USD 2 million was paid and firm commitments for the first three years of exploration included G&G studies worth USD 1 million, acquisition of 2,000 km 2D and 600 sq km 3D seismic data, and drilling two exploration wells. Firm seismic commitments for the block were fulfilled with a 2,526 km 2D seismic data acquisition in 2008, followed by the acquisition of 850 sq km 3D seismic data in 2009. The drilling commitments were fulfilled with wildcats Gajah Laut Utara 1 and Belut Laut 1, drilled in 2011 and encountering oil and gas shows. Despite lack of commercial success, both wells confirmed a working petroleum system in the area. Premier conducted a second drilling campaign in the block in 2014. The Kuda Laut 1 wildcat discovered oil and gas in the Miocene Arang Formation in late April 2014. The operator followed up the discovery with a sidetrack well (Singa Laut 1) targeting the deeper Oligocene Gabus Formation sandstones in an adjacent fault block. Singa Laut 1 was plugged and abandoned as a wet gas discovery on 3 June 2014.

Premier (->30% op, MOECO 20%) is finalising the farmout of a 50% interest in the Tuna PSC (999km²) off East Natuna, with Zarubezhneft.

Chesapeake has reached 3 deals worth USD 500 million total to sell circa 965 sq km of assets in Oklahoma's Mississippi Lime and other parts of the state, with 1 transaction already closed and the other 2 expected to close in Mar ‘18. Included are 3,000 producing wells with 23,000 boe/d of net output to the company.

Chesapeake has reached 3 deals worth USD 500 million total to sell circa 965 sq km of assets in Oklahoma's Mississippi Lime and other parts of the state, with 1 transaction already closed and the other 2 expected to close in Mar ‘18. Included are 3,000 producing wells with 23,000 boe/d of net output to the company.

The authorities report the sole application received under the 4th Round, opened a year ago and now closed, has been withdrawn. The area available mostly E + SE of the islands, namely quads 6004, 6005, 6103, 6104, 6105, 6201, 6202, 6204, 6205 + 6301. The applicant and area of interest remain undisclosed.

Faroe Islands, not found

Siccar Point has concluded its divestment of 26% in the Jackdaw discovery to Dyas for an undisclosed consideration. Deal completion was notified by the OGA on 7 January 2018, after the sale agreement was first announced on 6 November 2017. Jackdaw HPHT gas/condensate discovery is located in the Central North Sea within P098 - 30/2a Post-Tertiary & Pre-Tertiary, P111 - 30/3a Below the Top Danian/Ekofisk, and P672 - 30/2d. It was discovered by 30/2a-6 (2005, ConocoPhillips, 5,722m), which encountered 33m net pay in Late Jurassic Heather Formation turbidites and 32m of net pay in Middle Jurassic Pentland Sands, and appraised in 2007 and 2012. The discovery is estimated to hold recoverable resources of 125 - 250 MMboe in highly permeable sands, and is one of the largest undeveloped discoveries on the UK Continental Shelf. Previous partner plans were for a final investment decision mid-2015 and production start-up in 2019, which stalled in October 2014 due to costs escalating to over GBPS 3 billion (US$ 4.8 billion). Since then partners have considered more economic, lower risk development solutions involving a tie-back from Jackdaw to existing infrastructure such as Repsol Sinopec's Blane Field in 30/3a, 3km E of Jackdaw, or ConocoPhillips-operated Jade Field (Shell 35%) in 30/2c, 9km to the SW. Located in unlicensed acreage 6km W of Jackdaw, is the Palaeocene Forties Sand Courageous discovery 30/2a-5 (2005, Kerr-McGee, 3,331m) which tested 3,000 bo/d, 2 MMcfg/d and 800 bc/d. Siccar Point obtained its Jackdaw interest via its acquisition of OMV (UK) Ltd for US$ 870 million in January 2017. The revised partners in Jackdaw discovery and licences P098 - 30/2a Post-Tertiary & Pre-Tertiary, P111 - 30/3a Below the Top Danian/Ekofisk, and P672 - 30/2d are Shell subsidiary BG International Ltd (74% + Op) and Dyas UK Ltd (26%).

Siccar Point has sold its 26% interest in the Shell-operated (74%) Jackdaw HPHT field (P098 & P111 & P672) to Dyas.

Exxon and partner Qatar Petroleum were officially granted MLO-113, 5,826 sq km in the Malvinas Basin, from Argentina's 1st offshore round. Commitments/plans include 963km 2D seismic, reprocessing of 2,332km of 2D, 1,747 sq km of 3D and reprocessing 1,456 sq km of 3D, 2D 5,156km of gravity-magnetics within 4 yrs, 1 well within 8 yrs. An optional 3rd term would call for a 50% relinquishment.

Exxon and partner Qatar Petroleum were officially granted MLO-113 (5826km²) from Argentina's 1st offshore round.

MontD’or could be offering a farm-in opportunity in the West Salawati PSC, in onshore/offshore West Papua, as of September 2019. The onshore portion of the block, located in the Salawati Island, contains the Baladewa oil field which was brought onstream in early 2018 from the recompletion of discovery well Baladewa 1. Aside from development and production activities, the company is also assessing near-field prospectivity in view of future exploration drilling, likely targeting the Kais Formation. The Baladewa field was producing approximately 130 bo/d in Q1 2019, from Upper Miocene Kais Formation limestones. Initial output from the field was reported at around 350 bo/d. MontD’or received approval for the Baladewa Plan of Development (POD) in 2017. MontD’Or is operator and sole interest holder in the West Salawati PSC since 2011.The block was originally awarded to Pearl Energy in 2003. Background Information The block was awarded to Pearl Energy in November 2003. It was part of the "Third Round" of Migas-controlled acreage releases which closed on 31 July 2003. Pearl paid a signature bonus of USD 1.25 million and committed to invest USD 10 million for the first three years of exploration, which includes reprocessing of 6,000 km 2D and 300 sq km 3D seismic data plus drilling one exploration well. Genting entered the block in 2005, acquiring 49.99 % participating stake, but exited in 2010. Genting’s stake was re-acquired by Pearl Energy. Pearl completed drilling operations at Cilipgo 1 wildcat in 2007. The well was plugged and abandoned as a gas and oil shows well after reaching a total depth of 3,729 m. In late 2007, 97.5 km 2D seismic data was acquired in the block, which was part of a 735.7 km transition zone joint survey with the PT Pertamina/PetroChina JOB, which acquired 638 km of offshore 2D seismic data in its Salawati Kepala Burung JOA. In February 2007, Pearl also completed the acquisition of 1,191 km of 2D marine seismic and before that in 2006, 146 sq km of 3D land seismic was acquired. MontD’Or Asia Ltd acquired 100% shares from Pearl on 19 January 2011. Wildcat Baladewa 1 was spudded in February 2015. The well was primarily targeting carbonate build-up of the Miocene Kais Formation. The well was suspended in May 2015 due to technical issues. Last reported drilled depth was past 1,950 m by late March 2015. Drilling was resumed possibly in early 2016, and the well flowed oil from the Kais reservoir. The well had a PTD of approximately 3,500 m. Baladewa 1 was the first well drilled by MontD’Or after the company received a two-year extension for the exploration phase on 12 March 2014.

MontD’or could be offering a farm-in opportunity in the West Salawati PSC, in onshore/offshore West Papua, as of September 2019. The onshore portion of the block, located in the Salawati Island, contains the Baladewa oil field which was brought onstream in early 2018 from the recompletion of discovery well Baladewa 1.

Zennor Petroleum exited licence P1242 and CalEnergy acquired the 11% interest in licence P1242 from Zennor Energy on 21 July 2020. The licence covers two blocks (47/5b and 48/1a) and an area of 53 sq km. Block 48/1a hosts the Platypus gas discovery and the Platypus East prospect. The Platypus Field Development Plan (FDP) and Environmental Statement was submitted to the Oil and Gas Authority (OGA) and Offshore Petroleum Regulator for Environment and Decommissioning (OPRED) in October 2019 but sanction has been delayed from Q2 2020. The FDP involves drilling two development wells down to around 3,100 m. The wells are to be connected to a subsea manifold and gas will be transported to the Cleeton Wellhead platform through a 23 km pipeline. The field is forecast to achieve peak production of approximately 47 MMcfg/d and have a field life of approximately 20 years. The project was expected to be sanctioned in Q2 2020 but, due to COVID-19 and the low oil and gas price, the project sanction has been delayed. First gas will be achieved less than two years after sanction. The Platypus gas field was discovered by Dana in 2010. The discovery well (48/1a-5) encountered a 66 m thick Rotliegend Lower Leman Sandstone reservoir section and it was suspended as a future producer. In 2012, the 48/1a-6 horizontal appraisal well drilled through 945 m section of reservoir and flowed gas before also being suspended as a future producer. Partner in the licence, Parkmead, disclosed in 2019 that Platypus is estimated to contain 105 Bcfg of recoverable reserves in the mid-case. In addition, the acreage could also have potential upside in the Platypus East prospect, which may contain 51 Bcf of reserves. Interest in P1242 is held by Korea National Oil Corp (KNOC) through subsidiary Dana Petroleum (E&P) Ltd (59% + operator), CalEnergy Gas Ltd (26%) and Parkmead (E&P) Ltd (15%).

United Kingdom (Anglo-Dutch B.) Cleeton op. by PERENCO (100%)

On 30 October 2019, the Federal Agency for Subsoil Use held an auction for two blocks in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). Four companies submitted bids and Rosneft and Gazprom Neft-Khantos emerged as the winners. The winners of the auction will obtain 25-year E&P licenses. The Galnadskiy block covers 310 sq km in the Middle Ob Province and encompasses the Galnadskoye oil discovery with 3P reserves estimated at 7 MMbbl. Seismic coverage amounts to 480 km. Three exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 84 MMbbl of oil. The starting price amounted to RUB 94.049 million (USD 1.47 million). Rosneft offered RUB 103.454 million (USD 1.62 million). The Ingolskiy Severnyy block covers 416 sq km in the Middle Ob Province and encompasses the Ingolskoye Severnoye oil discovery with 3P reserves estimated at 13 MMbbl and a prospect with oil resources estimated at 4 MMbbl. Seismic coverage amounts to 700 km. Four exploratory wells have been drilled in the block. Resources (categories D1+D2) of the block are estimated at 89 MMbbl of oil. The starting price amounted to RUB 185.77 million (USD 2.9 million). Gazprom Neft-Khantos offered RUB 204.347 million (USD 3.19 million).

Russia, not found

N-C part of AE-0042-5M-Agua Dulce-01 block (AE-0135-Cuichapa), onshore Salina (Sureste) Basin, TD 7,540m reached mid-May '20, target M. Cretaceous salt-related structure.

Mexico (Sureste B.) Rabasa 1001EXP op. by PEMEX (100%) in AE-0042 block onshore Salina (Sureste) Basin, TD 7,540m, Cretaceous salt-related structure. No results

Oxy has been assigned 35-year rights to onshore block 3 offered in the Apr ’18 round by ADNOC, the move endorsed by Abu Dhabi’s Supreme Petroleum Council. Block 3 covers 5,782 sq km in the Al Dhafra area as per the official map extract below. ADNOC has has a 60% back.in right in a production phase.

Occidental Petroleum (100%) has been awarded onshore Block 3 (5782 km²). ADNOC has the option to hold a 60% stake in the production phase of the concession.

Kirthar 2667-7 EL, Kirthar Fold Belt in Sindh, P&A dry (tested) early Sep ’18, Exalo-304 rig. PTD was 3,537m, target Pab sst. PGNiG (op), partner PPL.

Pakistan, Kirthar 2667-7 EL

According to reports in October 2018, the government of Neuquen Province has approved Vista Oil & Gas takeover as operator with 90% interest on the Aguila Mora block from Shell’s Argentinean subsidiary, O&G Developments. Provincial company GyP Neuquen holds the remaining 10% interest in the block. The transaction was executed as an addendum to a prior agreement from September 2018, where Vista previously assigned 35% of its 45% non-operating interest (held by to O&G Developments on the latter’s operated Coiron Amargo Sur Oeste (CASO) block, where a new unconventional exploitation concession was recently granted for the development of a shale oil pilot from the Vaca Muerta Formation on the Neuquen Basin. Aguila Mora block covers 170 sq km of land in the Northeast Platform part of Neuquen Basin. The block is situated adjacent to to ExxonMobil’s Bajo del Choique - La Invernada block where the operator is also developing a project in the Vaca Muerta Formation. Background Information Vista Oil & Gas is an energy company that was incorporated in early-2017 based in Mexico, and is headed by former CEO of Argentinian state company YPF, Miguel Galuccio.

the government of Neuquen Province has approved Vista Oil & Gas takeover as operator with 90% interest on the Aguila Mora block from Shell’s Argentinean subsidiary, O&G Developments. Provincial company GyP Neuquen holds the remaining 10% interest in the block.

Further to DEA 26 Feb ’19, Kosmos is diluting its position in the Greater Tortue / Ahmeyim offshore project to retain 10%, bids expected late summer ’19. BP operates the devt phase on behalf of Kosmos, Petro Tim + Petrosen (Senegal) and Kosmos + SMHPM (Mauritania).

Kosmos is diluting its position in the Greater Tortue / Ahmeyim offshore project to retain 10%, bids expected late summer ’19. BP operates the devt phase on behalf of Kosmos, Petro Tim + Petrosen (Senegal) and Kosmos + SMHPM (Mauritania).

On 22 August 2017 Premier announced that it had reached an agreement to farm down its entire 33.8% interest in the Wytch Farm field (licences PL89 and P534) for a consideration of USD 200 million. The company stated that it will release letters of credit amounting to USD 75 million in connection with future field decommissioning liabilities. On 12 September 2017 the acquiring company was named to be Verus Petroleum SNS Limited. However, in an update on 16 November 2017 Premier stated that existing operator Perenco UK Limited had pre-empted the deal and it was in fact Perenco which will be acquiring the 33.8% interest. Premier announced that it and Perenco have entered a Sale and Purchase agreement on 20 November 2017. The deal is subject to regulatory approval. Wytch Farm is located in southern Dorset, in an area of extreme environmental sensitivity. It was discovered in 1974 and was brought onstream five years later. The field's onshore sector has been developed with conventional sub-vertical producers, while its offshore extension under Poole and Bournemouth bays has been exploited with extended reach wells, with one of the longest wells having a step-out approaching 11 km. Production from the field was approximately 5,000 boe/d net to Premier as of 30 June 2017. Following completion of the deal interest in Wytch Farm will be held by Perenco UK Limited (87.6% + operator), Ithaca Energy (UK) Limited (7.4%) and Repsol Sinopec North Sea Limited (5%).

United Kingdom (Wessex B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: Wytch Farm op. by PERENCO (53.81%, VERUS SNS 33.81%, DELEK GRP 7.43%, REPSOL NS 4.95%) to be check.

Drilling started 13 Apr ’19 in the Yufutsu field area off Hidaka coastline of Hokkaido, NE Japan, WD 1,070m, TD 2,530m, gas encountered + tested, Ensco 8504 SS (soon to be re-named Valaris 8504). Some background from GEPS.

Hidaka 1 explo, completed by JAPEX as part of the offshore exploration project commissioned by the Agency for Natural Resources and Energy of the Ministry of Economy, Trade and Industry (ANRE in early July 2019, gas disc. a production test was run on a gas reservoir "where indications of natural gas existence was recognized, and achieved stable gas production. WD=1070 m with PTD= 2000 m below seabed.

The NPD confirmed on 9 June 2018 that DEA has transferred its 30% interest in PL 771 to operator MOL with effect from 31 May 2018. This deal follows two earlier deals relating to PL 771 and also PL 617: in April 2018 Fortis withdrew from both licences, transferring its 30% interest to MOL. MOL then passed this equity to OMV with effect from 22 May 2018. The licences are located immediately east of Valhall on the Norwegian / Danish border. PL 617 covers 112 sq km over part of block 2/9 and PL 771 covers 260 sq km over parts of blocks 2/8 and 2/9. Valhall was discovered in 1975 by well 2/8-6 drilled by Amoco and first oil was produced in October 1982 from the field’s Upper Cretaceous chalk reservoir (Tor and Hod formations). By January 2017 the field, together with Hod, had produced 1 Bboe, more than three times what was expected in the original PDO. The operator has ambitions to produce at least another 500 MMboe over the field’s lifetime. Following completion of all deals, MOL Norge AS operates both PL 617 and PL 771 with a 70% interest and is partnered by OMV (Norge) AS (30%).

DEA has transferred its 30% interest in PL 771 to operator MOL with effect from 31 May 2018. This deal follows two earlier deals relating to PL 771 and also PL 617:

Crown Point reports the recent acquisition of the Pluspetrol shares of its former Apco stake representing 25.78% of the Rio Cullen, Angostura and Rio Cullen licenses in the Tierra del Fuego portion of the Austral Basin. Crown Point now holds a 51.56% share of these contracts. Roch will continue as operator with 20.28% interest. San Enrique will still keep 12.62%, DPG 11.54% and Secra 4% in all three blocks. Local company, Liminar Energia, a subsidiary of the Grupo ST, has recently acquired 51% of the shares of Crown Point Energy. Crown has recently requested a contract extension to 2026 for the Angostura and Rio Cullen licenses.

Argentina, Angostura

12 blocks are to be released under the PLR2020-1 round in the Bowen-Surat Basin in April. Applications between Apr – Jun '20, awards Sep '20. Block sizes 76 - 1,414 sq km:

PLR2020-1 round 12 blocks are to be released under the PLR2020-1 round in the Bowen-Surat Basin in April. Applications between Apr – Jun '20, awards Sep '20. Block sizes 76 - 1,414 sq km:

On 27 February 2020, the Federal Agency for Subsoil Use held an auction for four blocks in Orenburg Oblast (Volga-Ural Province). About 20 companies submitted applications and the winning bids were offered by Neftisa, Rosneft, Zarubezhneft and UDS Neft. Winners of the auction will obtain 25-year E&P licenses. Details of the offer are as follows: The Yuzhnyy block covers 510 sq km and encompasses the Teplovskoye and Uralskoye gas fields with combined 2P reserves estimated at 47 Bcf. Hydrocarbon resources (category D1) of the block are estimated at 12 MMbbl of oil and 86 Bcf of gas. The starting price amounted to RUB 43.8 million (USD 0.67 million). Neftisa-subsidiary Sladkovsko-Zarechnoye, competing against Tatneft-Samara and Belkamneft, won the auction with the offer of RUB 48.18 million (USD 0.74 million). The Babichevskiy block covers 392 sq km. Hydrocarbon resources (category D1) of the block are estimated at 30 MMbbl of oil and 58 Bcf of gas. The starting price amounted to RUB 6.85 million (USD 0.11 million). Rosneft-subsidiary Orenburgneft, competing against 15 companies, won the auction with the offer of RUB 1,507 million (USD 23.2 million). The Novobarabanovskiy block covers 272 sq km. Hydrocarbon resources (category D1) of the block are estimated at 20 MMbbl of oil and 51 Bcf of gas. The starting price amounted to RUB 6.05 million (USD 0.09 million). UDS Neft, competing against 14 companies, won the auction with the offer of RUB 1,204.555 million (USD 18.5 million). The Turgayskiy block covers 96 sq km. Hydrocarbon resources (category D1) of the block are estimated at 8 MMbbl of oil. The starting price amounted to RUB 2.05 million (USD 0.03 million). Zarubezhneft-Dobycha Samara, competing against 8 companies, won the auction with the offer of RUB 81.18 million (USD 1.25 million).

Neftisa winning rights to Yuzhnyy block (510km²), Turgayskiy block (96²km) won by Zarubezhneft-Dobycha Samara, Babichevskiy block (392km²) won by Rosneft-sub Orenburgneft and Novobarabanovskiy block (272km²), won by UDS Neft.

On 1 July 2020, BP Exploration & Production was awarded Mississippi Canyon Block MC 123, situated in the Louisiana Coastal Basin. MC 123 is sited directly to the east of the Hoffe Park discovery, which encompasses blocks MC 122, MC 165 and MC 166. In early July 2020, Chevron USA acquired deep operating rights in the Hoffe Park discovery from Murphy Exploration & Production. Hoffe Park is located in the Middle Miocene and has a gross resource potential of between 75-120 MMboe, according to figures from June 2019. MC 123 was originally offered as part of Gulf of Mexico Lease Sale 254, which was held on 18 March 2020 and attracted a total of US$ 93 million in high bids. Lease Sale 254 was the sixth offshore sale under the 2017-2022 Outer Continental Shelf (OCS) oil and gas leasing. Following official award, BP Exploration & Production is the operator and sole interest-holder (100% WI + Op) in MC 123.

United States (GOM B.), BP Exploration & Production was awarded Mississippi Canyon Block MC 123. MC 123 is sited directly to the east of the Hoffe Park discovery, which encompasses blocks MC 122, MC 165 and MC 166. BP Exploration & Production is the operator and sole interest-holder (100% WI + Op) in MC 123.

A tender call was issued yesterday for blocks II + III in the Black Sea. The auction will be held upon the application deadline (20 Apr '20). Block II covers 5,282 sq km in the central part of the Georgian Black Sea sector, block III 3,468 sq km south of block II. Data packages as of 1 Feb '20. Contacts: Vazha Mikeladze – [email protected], or Alexander Chabukiani, [email protected]. The map below shows block II, with III immediately below it along the Turkey boundary:

A tender call was issued yesterday for blocks II + III in the Black Sea. The auction will be held upon the application deadline (20 Apr '20). Block II covers 5,282 sq km in the central part of the Georgian Black Sea sector, block III 3,468 sq km south of block II. Data packages as of 1 Feb '20.

DNO ASA confirmed on 26 November 2018 that it has announced the terms of an offer to be made for the whole of the issued and to be issued share capital of Faroe Petroleum Plc. The offer stands at 152 pence in cash per Faroe share which values Faroe’s existing share capital at approximately GBP 608 million (USD 781 million). Faroe responded to the announcement by DNO stating that DNO did not engage with Faroe before making the announcement of its unilateral offer. Further announcements will follow once the Board of Faroe has met with its advisers. DNO already holds 28.22% of Faroe Petroleum’s issued share capital.

Norway, not found

Mari acquired Tullow’s 95% in block 28, Sulaiman Fold Belt (Balochistan), effective 8 Jun ’18, the deal having been announced a year ago (DEA 20 Jul ’17). OGDC operates the 5,833-sq km block with 5%, Mari how folding the balance (95%).

Mari acquired Tullow’s 95% in block 28, Sulaiman Fold Belt (Balochistan), effective 8 Jun ’18, the deal having been announced a year ago (DEA 20 Jul ’17). OGDC operates the 5,833-sq km block with 5%, Mari how folding the balance (95%).

On 13 November 2018, PVG(*) GmbH - Resources Services & Management was granted the Lippe-Nord contract in northwestern Germany. The contract is valid for five years, until 12 November 2023. The 106 sq km Lippe-Nord area is located in the Nordrhein-Westfalen political province, within the Münsterland Basin. The target of the operation was related to the extraction of the methane gas from the Carboniferous coal series (CBM). Background Information PVG applied for the Lippe-Nord contract on 28 February 2018. The application was covering the exact same area as the Herbern-Gas contract held by Mingas-Power GmbH from 13 January 2010 to 12 January 2018.   (*) PVG = Patentverwertungsgesellschaft (full name: Patentverwertungsgesellschaft für Lagerstätten, Geologie und Bergschäden)

Germany, Lippe-Nord

Senex Energy Ltd, through wholly owned subsidiary Victoria Oil Exploration (1977) Pty Ltd, spudded vertical exploration well Flanker 1 in PRL 149, located in the Cooper-Eromanga Basin, on 12 November 2018.  On 22 November 2018 the well was plugged and abandoned, at a total depth of 2,172 m, having only encountered oil shows. The well was drilled to the southwest of the Charo oil discovery, which was made in 1984 and is currently producing. PRL 149, which covers an area of 95 sq km, was awarded on 27 October 2014.  Participants in the permit are Victoria Oil Exploration (1977) Pty Ltd (40% + Operator) Permian Oil Pty Ltd, another Senex subsidiary, (20%), and Beach Energy subsidiaries Impress (Cooper Basin) Pty Ltd (25%) and Springfield Oil and Gas Pty Ltd (15%).

Flanker 1 (Senex 60%, op, Beach 40%) in PRL 149 block, having failed to intersect any hydrocarbons.

The 1,212-sq km Yambotysskiy block in Nenets AO (Timan-Pechora) has been added to a list of assets planned for auctions in 2019. It is understood that this block will be offered in 3Q ‘19.

Russia, not found

P1998, target Fulmar equivalent, tight hole spudded 21 Dec ’17, P&A on 2 Feb ’18, no further information, WilPhoenix SS. Apache (op), partners DNO + Euroil (Origo farming-in for 22.5%).

021/10b-11 (Val d’Isere) op. by Apache (60%, DNO 22,5%, Engie via Edison's subsidiary Euroil Expl. 17,5%) in P1998 block, had been P&A, result unreported.

Parnaiba Gas Natural (PGN) is assumed to have plugged and abandoned dry the 1-PGN-BL103E-MA (1-PGN-028-MA) new-field wildcat (NFW) in the PN-T-103 contract during mid-October 2018. The operator has not filed and gas show reports for the well with the ANP through late-October 2018. The NFW was spudded on 27 September 2018.   The well had a proposed total depth (PTD) of 1,633 m.  The Devonian Cabecas Formation and the Mississippian Poti Formation were the primary targets.  The NFW is located in the north central border area of the block with the nearest well the Petrobras operated 1-BXC-001-MA (1-BRSA-1362-MA) located 25 km northwest in the PN-T-086 block. Parnaiba Gas Natural has 100% working interest in the contract.

Brazil, PN-T-103

Pending partner and government approval, Lundin has agreed a licence swap with Edison whereby the former will take 10% in PL 850 and the latter will gain 10% in PL 952. The two licences lie adjacent to each other in the Barents Sea, and surround the Nucula oil and gas discovery (in separate PL 393). PL 952 contains well 7125/4-3 which was drilled by Statoil in 2014 when the area was held under PL 393 B. The well targeted the Ensis prospect. 35 m of poor quality sandstone was present in the Lower Cretaceous intra-Knurr Formation and 7125/4-3 was abandoned as a dry hole. According to partner Cairn, Ensis had potential recoverable reserves of 291 MMboe. The stratigraphic prospect stretched the length of the licence and had a 1 in 3 chance of success. Nucula was discovered in 2007 by Norsk Hydro’s 7125/4-1. Oil and gas was proven in the Triassic Realgrunnen Group and the Kobbe Formation with estimated reserves put at 210-420 MMboe. However, following an appraisal well in 2008, which proved just a small oil column in thin sands, reserves were downgraded to the lower part of the range. As of 31 December 2017 the NPD lists the find as ‘production is unlikely’ and does not give any associated volumes. Following completion of the deal, interest in PL 850 will be divided between Edison Norge AS (30% + operator), KUFPEC Norway AS (20%), Lime Petroleum AS (20%), PGNiG Upstream Norway AS (20%) and Lundin Norway AS 910%) and interest in PL 952 will be held by Lundin Norway AS (50% + operator), Suncor Energy Norge AS (40%) and Edison Norge AS (10%).

Lundin has agreed a licence swap with Edison whereby the former will take 10% in PL 850 and the latter will gain 10% in PL 952.

Jinzhou 17-2E-1 (JZ 17-2E-1) was suspended (results TBC) on or around 13 April 2020 after having been spudded on or around 24 March 2020, using the "Zhongyouhai 6" jack-up. The oil exploration well was likely targeting the Guantao, Dongying and Shahejie formations. Jinzhou 17-2E-1 is in the CNOOC operated Jinzhou 09 Block in the Liaodong Bay, Bohai Gulf Basin and is located east of the Jinzhou 17-2-1 well drilled by CNOOC in October 2003. <P />

Jinzhou 17-2E-1 (JZ 17-2E-1) was suspended (results TBC)

The new licences provide further exploration potential around the Company’s Karish and Tanin development Energean Oil & Gas has been awarded five offshore exploration licences within the Israeli Exclusive Economic Zone (EEZ) by the Israeli Petroleum Commissioner following a recommendation by the Petroleum Council. The initial exploration period under each Licence is three years.    The awarded Licences comprise Blocks 12, 21, 22, 23 and 31, which were published for bidding in the recent First Israeli Offshore Bid Round. The blocks are located near the Karish and Tanin gas fields which are currently moving towards development by Energean.   Energean believes that the Licences awarded are highly prospective and would benefit, in the event of any economic hydrocarbon discoveries, from being developed via tie-backs to the FPSO that Energean will construct for the development of the Karish and Tanin fields.    Energean believes these five additional Licences, which will raise the total number of licences held by the Company and its subsidiaries to 13, will provide upside potential for future growth and complement the Company’s portfolio within the East Mediterranean region. This portfolio includes low cost production from Greece, a world class development project from the Karish and Tanin gas fields, as well as exploration potential in Israel, Greece and the Adriatic.Energean awarded five exploration licences, offshore Israel Original article link Source: Energean Oil & Gas

Energean (100%) was awarded 12, 21, 22, 23 and 31 blocks in the recent first Israeli offshore bid round.

PTTEP is believed to have plugged and abandoned wildcat Pundarika 1ST located in the western part of block M-09, Moattama Basin, around mid-November 2019, as a dry well. It is understood that several formation tests failed due to tight reservoir. The original borehole was likely sidetracked at a depth of approximately 1,000 m. A series of wireline logs were run in the sidetrack hole, down to a depth of around 3,200 m. The well, spudded around late August 2019, was drilled using the "Noble Clyde Boudreaux" S/S. Possible drilling targets may include Pliocene sandstones of the Moattama Series and Oligo-Miocene carbonates of the Burman Limestone. Pundarika 1 was the first of three wildcats planned to be drilled in the "M9 West" area between late 2019 and early 2020. The other wells in the programme are Aungpyitan 1 (spudded in late November 2019) and Uppala 1 (likely to be drilled in early 2020). The "Noble Clyde Boudreaux" has been operating for PTTEP since late 2018 to conduct an appraisal drilling campaign in the central and eastern part of block M-09 (Zawtika field area) and exploration drilling in block M-11. The latter activity consisted of wildcat Pyae Wa Chan Thar 1. The well was plugged and abandoned in June 2019 as dry. PTTEP is operator of block M-09 with 80% interest, while MOGE holds the remaining 20%. The adjacent exploration block M-11 to the south is operated by PTTEP with 100% interest. Background Information The last exploration well in the western part of block M-09 was Bawga Siddhi 1. The well was plugged and abandoned in September 2010. The well experienced abnormal over pressured zone and gas influx in the wellbore which caused the operator to terminate drilling at 3,052 m, shallower than the PTD of 4,089 m, due to safety reasons. The well failed to reach its drilling objectives but the operator confirmed the presence of net pay, 19 m of gas bearing sandstone above the not-reached objectives. PTTEP reported that the Zawtika Project commenced gas production for the domestic market on 14 March 2014, with initial sales rate of 40 MMscfg/d and planned peak of 100 MMcfg/d. Domestic gas is used for power generation. Gas export to Thailand commenced on 5 August 2014. Production gradually ramped up to the daily contract quantity of 240 MMscfg/d as stipulated in the Gas Sales Agreement with buyer PTT. Due to the highly faulted structures, numerous platforms and wells are required to develop the Zawtika and nearby fields. The initial phase of the Zawtika project (Phase 1A) consisted of three wellhead platforms (ZWP1, ZWP2 and ZWP3, located in the Shwepyihtay, Kakonna and Zawtika fields respectively) and one integrated central processing/living quarter’s platform (ZPQ). Further development phases will be necessary in order to maintain the stipulated production plateau.

PTTEP is believed to have plugged and abandoned wildcat Pundarika 1ST located in the western part of block M-09, Moattama Basin, around mid-November 2019, as a dry well. It is understood that several formation tests failed due to tight reservoir.

Stabroek block, offshore Guyana Basin, location S. of Turbot discovery, WD 1,018m, TD 5,0134m, 10th discovery in block, 37m of HQ sst encountered, estimate of discovered recoverable resources for Stabroek now > 5 Bboe (up from previous >4 Bboe. Noble Tom Madden DS now off to drill Tilapia-1. Exxon (op), partners Hess + CNOOC Nexen. http://www.hess.com.

Pluma-1 nfw Stabroek block, offshore Guyana Basin, location S. of Turbot discovery, WD 1,018m, TD 5,0134m, 10th discovery in block, 37m of HQ sst encountered, estimate of discovered recoverable resources for Stabroek now > 5 Bboe (up from previous >4 Bboe. Noble Tom Madden DS now off to drill Tilapia-1. Exxon (op), partners Hess + CNOOC Nexen

Boxi block, W. Bohai Gulf Basin, WD 20m, terminated 21 Jul '20, Bohai 5 JU. Target Oligo-Miocene clastics, 1st well in area for 10 years.

(Bohai Gulf b.), Caofeidian 7-5-1 new-field wildcat was completed without result reported. The well is located in Boxi Block operated by CNOOC LTD (100%) in the western part of the Bohai Gulf, in a water depth of approximately 20 m. The well is targeting the Mio-Oligocene clastic play.

Likely cooled by tepid response to date, the authorities have extended the deadline for EoI's on 5 offered blocks* to 31 Mar '20. Contact: Petroci, email [email protected]. * CI-102, CI-503, CI-800, CI-801 + CI-802, sketched out in red on the official concession map extract below:

Likely cooled by tepid response to date, the authorities have extended the deadline for EoI's on 5 offered blocks* to 31 Mar '20.

It has been reported in the media during May 2020, that Eni SPA could be looking to exit its Australia exploration and production position. A divestment process could be launched by end-May 2020 as the company is reported to be working with investment bank Citi to prepare the offering. It is thought that a divestment of its northern Australian portfolio could also include its Timor Leste position also. Eni's operations currently supply natural gas into the Australian Domestic market from the operated Blacktip gas field. Domestic markets are seen to be less exposed to the global demand and price fluctuations making the asset a stable, medium-term acquisition. Eni also holds an 11% stake in the Darwin LNG project, operated by ConocoPhillips (soon to be Santos). Both assets are in natural reservoir decline with Bayu-Undan gas and condensate field expected to cease around 2023. Darwin LNG is planned to be backfilled by the Barossa field, in which, Eni does not participate. Moving past 2023, production for Eni could be limited to the declining Blacktip field until new assets come on stream. The project could keep producing to the domestic market until around 2048. No financial investment decisions have been made for Eni's 'upside' projects including: Evan Shoals, Blackwood or Penguin. Any future development decisions would unlikely see gas production before in the next 10-15 years, but the portfolio is estimated to contain in excess of 700 MMboe of remaining resources (net to Eni). Near filed exploration or field de-development is another option to increase the upside of the portfolio from Eni's existing oil assets, such as Woollybutt and Kitan. Likely if sold, the assets could form one package, but could attract a consortium of buyers to handle the diverse nature of the assets across domestic gas production, LNG in Darwin and plant infrastructure. During Eni's time in Australia and Timor Leste, it has participated in over 90 wells, including 43 new field wild cats, since 1984. Moving to the northern Australian offshore basins in 2000, Eni is now thought to be preparing to divest its remaining gas assets.

Eni Australia Ltd, Eni Timor Leste SpA could be looking to divest its entire Australian gas portfolio

ZCCM was granted sole rights to blocks 39 + 44, resp. 3,833 sq km + 6,269 sq km in the Western + Kariba basins, latter in S. Zambia. Block 44 was previously Swala’s.  The licence terms provide for 4+3+3 years.

ZCCM (Investments Holding) was granted sole rights to blocks 39 (3833km²) + 44 (6269km² previously Swala’s) in S. Zambia.

South Disouq block, onshore Nile Delta, TD 3,167m, encountered 1.7m net gas sand in the Kafr El Sheikh, 1m net gas sand in the Abu-Madi (143m high-qual net reservoir) + 258m high-qual net reservoir in the Qawasim, neither of which commercial. Rig to SD-12X (Sobhi), 6km westwards, spudding by end-month. SDX (op), partners IPR + EGPC.

SD-6X (Salah) expl. (SDX op, IPR + EGPC) in South Disouq block onshore, encountered 1,7m net gas sand in the Kafr El Sheikh, 1m net gas sand in the Abu-Madi (143m high-qual net reservoir) + 258m high-qual net reservoir in the Qawasim, neither of which commercial. TD=3167m

RockRose Energy is taking over former operator Dana Petroleum’s 20.43% interest in the Arran North and South fields in P359 + 1051 / blocks 23/11 + 23/16, for a nominal consideration. Not yet known who will take over as operator, but it is likely to be Shell as they already operate some adjacent licences and the 2 wells planned at Arran N&S will be tied-back to their Shearwater platform. FDP to be filed by end-Sep ’18, production is targeted from late ’20 for 12 years. RockRose will be partnered with Dyas, Shell + Zennor.

RockRose Energy is taking over former operator Dana Petroleum’s 20,43% interest in the Arran North and South fields in P359 + 1051 / blocks 23/11 + 23/16, for a nominal consideration. Not yet known who will take over as operator, but it is likely to be Shell as they already operate some adjacent licences and the 2 wells planned at Arran N&amp

BP has taken on a 22% its interest from Shell in P1807 and 5.5% from ExxonMobil. P1807 covers part-block 22/30e and contains the 2015 Baroli HP/HT discovery. Partnership now Shell (op, 28%), ExxonMobil (44.5%), BP (27.5%).

United Kingdom (Central Graben Province) P1807 op. by EXXONMOBIL (50%), SHELL (50%), BP has taken on a 22% its interest from Shell in P1807 and 5.5% from ExxonMobil. P1807 covers part-block 22/30e and contains the 2015 Baroli HP/HT discovery. Partnership now Shell (op, 28%), ExxonMobil (44.5%), BP (27.5%).

It is understood that Chevron could be offering a farm-in opportunity in Block A-5 and Block AD-03, located in offshore Rakhine Basin, as of January 2019. The company holds a 55% operating interest in both blocks, following a 2018 deal with Ophir Energy. Ophir holds 42% participating interest in the blocks, while local partners Parami Energy and RM Engineering hold respectively 2.5% and 0.5% interests. Ophir is looking at divesting from these assets, upon which Chevron’s rightholding would likely increase to 97%. The study period for Block A-5 and Block AD-03 has been extended until March 2019. The extension will allow the operator to continue evaluations of existing data towards the maturation of potentially drillable prospects. In January 2018, Ophir and Chevron agreed to consolidate the respective interests in the two adjacent blocks. Prior to the agreement, Chevron was operating Block A-5 with 99% (with RME Engineering 1%) and Ophir was the operator of Block AD-03, with 95% (with Parami holding 5%). For further information about the potential opportunity, interested parties may contact: Sid Jones Asia-Pacific New Ventures Team Lead (Houston) Email: [email protected] Background Information Block A-5 Unocal Myanmar Offshore Co. Ltd., a wholly owned subsidiary of Chevron Corporation, and Royal Marine Engineering Co. (RME), a Myanmar company, entered into a Production Sharing Contract (PSC) for Block A-5 with the national oil and Gas Company, on 24 March 2015. Block A-5 is located offshore along the Arakan coast, around 240 km southeast of the Shwe gas project operated by POSCO Daewoo in Blocks A-1 and A-3. This was Chevron’s first significant investment in Myanmar after the Yadana Project with Total EP Myanmar and partners. The block was offered as part of the 2013 Myanmar offshore bid round. The block covers an area of 10,531 sq km in water depths of up to 2,000 m. Two wells have been drilled by Compagnie Francaise des Petroles in the shallow portion of the block in 1976. Rubis 1 was junked at a depth of 1,041 m due to high pressure problems, while Rubis 1A was plugged and abandoned as dry having reached TD at 3,324 m. Chevron acquired approximately 4,900 sq km of 3D seismic data in the block between late 2015 and early 2016, covering areas from shelf to deep water. Block AD-03 On 4 December 2014, Myanmar Ministry of Energy officially awarded the Production Sharing Contract (PSC) for deepwater block AD-03, located in the Rakhine Basin, to Ophir Energy and local partner Parami Energy. The contract commenced with a two-year study period and commitments of 2D seismic re-processing and new 3D seismic acquisition. Ophir paid signature bonus of USD 6.5 million, USD 1.26 million for data fee and committed to spend USD 258.3 million for exploration work. The latest exploration activity in the block was a 3D seismic survey in mid-2015. The survey, covering approximately 10,000 sq km, fulfilled seismic commitments for the first two years of the contract (study period). The survey was conducted with newly built “Sanco Sword” survey vessel. Ophir Energy was previously planning to drill one well in the block in 2018 or 2019, targeting the Aung Sakyar prospect. The prospect, located at water depths exceeding 2,000 m, would likely target gas in Pliocene turbidite sandstones within a low relief channel system. No wells have been drilled in the block.

Myanmar, AD-03

It has been reported in the media during May 2020, that Eni SPA could be looking to exit its Australia exploration and production position. A divestment process could be launched by end-May 2020 as the company is reported to be working with investment bank Citi to prepare the offering. It is thought that a divestment of its northern Australian portfolio could also include its Timor Leste position also. Eni's operations currently supply natural gas into the Australian Domestic market from the operated Blacktip gas field. Domestic markets are seen to be less exposed to the global demand and price fluctuations making the asset a stable, medium-term acquisition. Eni also holds an 11% stake in the Darwin LNG project, operated by ConocoPhillips (soon to be Santos). Both assets are in natural reservoir decline with Bayu-Undan gas and condensate field expected to cease around 2023. Darwin LNG is planned to be backfilled by the Barossa field, in which, Eni does not participate. Moving past 2023, production for Eni could be limited to the declining Blacktip field until new assets come on stream. The project could keep producing to the domestic market until around 2048. No financial investment decisions have been made for Eni's 'upside' projects including: Evan Shoals, Blackwood or Penguin. Any future development decisions would unlikely see gas production before in the next 10-15 years, but the portfolio is estimated to contain in excess of 700 MMboe of remaining resources (net to Eni). Near filed exploration or field de-development is another option to increase the upside of the portfolio from Eni's existing oil assets, such as Woollybutt and Kitan. Likely if sold, the assets could form one package, but could attract a consortium of buyers to handle the diverse nature of the assets across domestic gas production, LNG in Darwin and plant infrastructure. During Eni's time in Australia and Timor Leste, it has participated in over 90 wells, including 43 new field wild cats, since 1984. Moving to the northern Australian offshore basins in 2000, Eni is now thought to be preparing to divest its remaining gas assets.

Eni Australia Ltd, Eni Timor Leste SpA could be looking to divest its entire Australian gas portfolio

Claren Energy announced on 24 June 2019 having entered into an agreement with Zeta Petroleum to acquire 60% interest in the Bobocu licence. Upon closing of the transaction interest in the licence will be held solely by Claren Energy. The licence is situated in the eastern part of the country about 150 km northeast of Bucharest. The licence contains the Bobocu field which was discovered in the mid-sixties and put onstream in 1977. In 2012 Zeta Petroleum drilled and suspended the Bobocu 310 appraisal well with gas shows. The hole reached a total depth of 2,704 m. In December 2016 Zeta Petroleum started the Bobocu 310ST using the “MR-8000” rig. The sidetrack stepped out horizontally 600 m from the Bobocu 310 with three Upper Miocene sandstones objectives at depth ranging from 2,526 m to 2,712 m. In January 2017 a lighter rig had been mobilized for the testing operations. In late February 2017 Zeta Petoleum suspended the Bobocu 310ST appraisal with gas shows. The hole reached a total depth of 2,765 m in the Pontian. Zeta Petroleum completed cased-hole well tests on the “Lobe G” and Corcova sandstone reservoirs and also tested the “Lobe H” above the “Lobe G”. The cased-hole logging program showed gas saturations between 30% and 40% but none of the perforated zones yielded commercial quantities of gas. Before the deal, interest in the Bobocu licence was held by Zeta Petroleum (Bobocu) SRL (60% + operator) and Claren Energy Corp (40%).

Claren Energy (->100%) is acquiring remaining 60% operator share in Bobocu concession from GM Investment (GMI) for an undisclosed consideration.

Hong Kong based High Luck Energy in mid November 2017 plugged and abandoned the El Pacara x-2001 new field wildcat on the Tartagal Oriental license, Oran-Olmedo Basin. The well was spud on 1 September with a PTD of 2,913m and had oil shows. The Tupambi and Los Monos formations were the geological targets. High Luck operates and holds 75.25% interest, JHP 0.75%, Maxipetrol 6% and South American Hedge Fund has an 18% working interest.

Not Found

Nanggroe Ache Darussalam 1 PPC in N. Sumatra, ops terminated Jul ’18, tested small amounts of gas early in 2018, co. rig.

Titanum 1 (TTN 1), (Pertamina 100%) in the Nanggroe Ache Darussalam 1 PPC, completed, have flowed a small amount of gas from Up. Miocene Besitang River Sandstone.

Coro Energy with Conrad Petroleum and Empyrean Energy have received the required regulatory approvals for Coro's 15% acquisition in the Duyung PSC, located in the West Natuna Basin, on 22 May 2020. The new interest holding in the block is composed by Conrad (76.5%, operator), Empyrean (8.5%) and Coro (15%). In February 2020, the partners extended the long stop date for the transaction to 30 June 2020, in view of the delayed government approval which was initially due by 31 December 2019. Coro completed the required payment to Conrad and Empyrean on 16 April 2019. The final outstanding payment made to the existing partners amounted to USD 1.2 million in cash, USD 9.3 million as a contribution towards the 2019 drilling campaign, plus the issuance of 60,905,037 new Coro shares with a value of USD 1.85 million. Conrad and Empyrean received the payments pro-rata, based on the initial participation in the PSC of 90% by Conrad and 10% by Empyrean. By the time of the initial sale and purchase agreement on 11 February 2019, Coro paid USD 1.75 million of the total cash consideration, plus USD 1.2 million towards the 2019 drilling campaign. The balance payment from Coro was due by 31 December 2019. The total consideration payable by Coro included USD 4.8 million (consisting of USD 2.95 million in cash and USD 1.85 million in Coro shares), plus a contribution of USD 10.5 million to partially fund the exploration drilling programme. Prior to the Coro farm-in, the block was operated by West Natuna Exploration Limited (WNEL), a subsidiary owned by Conrad (90% shares) and Empyrean (10% shares). WNEL has now transferred all of its interest in the block to the respective companies. The block includes the Mako field, estimated to contain 2C gas resources of 276 Bcf and 3C resources of 392 Bcf. A Plan of Development (POD) for the field was approved by authorities in March 2019 and a Heads of Agreement with a Singapore gas buyer is in place. The gas will be likely exported via the West Natuna Transportation System (WNTS). The drilling campaign conducted in 2H 2019 consisted of two wells, Tambak 1 and Tambak 2, which confirmed the presence of an extensive gas reservoir across the Mako structure. The first well in the campaign, Tambak 2, intersected approximately 10 m of Muda Formation sandstones, but did not flow due to formation damage sustained following a gas kick and mud loss. The second well, Tambak 1, tested 11.4 MMcf/d of dry gas from the Muda Formation between 389 and 391 m TVDSS. On 17 January 2019, Conrad and Empyrean signed an amendment of the Duyung PSC to convert the existing contract to Gross Split terms. Following the contract amendment, the operator submitted a revised POD for the field. The original POD had been submitted to authorities in August 2018. Background Information The Duyung PSC was originally awarded to Transworld (100%) in January 2007. The block was offered under the direct mechanism during the second phase of the "Fifth Round" of Migas-controlled acreage releases which opened on 15 August 2006. A signature bonus of USD 1.5 million was paid and firm commitments included G&G studies worth USD 1 million, acquisition of 400 sq km 3D seismic data and drilling one exploration well. The seismic commitment was conducted from late 2008 to early 2009 using PGS's 'Orient Explorer’ vessel. Around 360 sq km of data was acquired. WNEL acquired 100% interest in the block in 2013. In September 2015, WNEL had agreed to farm out 85% interest to Hague and London Oil, however the agreement was terminated as of 1 April 2016 due to lack of the necessary regulatory approvals. On 12 May 2017, Empyrean reported the completion of the first stage of a proposed deal with Conrad Petroleum for the acquisition of a 10% stake in WNEL for an initial consideration of USD 2 million, pursuant to a Sale and Purchase Agreement (SPA) signed on 4 April 2017. Under the terms of the SPA, Empyrean had the option to pay further cash consideration of USD 2 million that would grant the company an additional 10% interest in WNEL. However, Empyrean reported on 30 May 2017 that it would not proceed to acquire the additional 10% interest, thus retaining only the initial 10% stake in WNEL while Conrad Petroleum retained the remaining 90% stake plus operatorship. The Mako structure is estimated to have a lateral extent of 304 sq km with tested reservoir of approximately 7 m of fine sand layer within the Intra Muda Formation. In August 2018, Empyrean reported that modeling studies on the field indicated estimated gas initially in place (GIIP) of 705 Bcf, with upside potential case of 1,317 Bcf. The company at the time also reported recoverable contingent resources of 433 Bcf (2C) and 646 Bcf (3C). The structure was originally drilled in 1999 by Lasmo with wildcat Mako 1, which encountered 7 m gas-bearing sandstones from logs, but was not tested. The structure was reinvestigated in mid-2017 by WNEL, with Mako South 1. The well flowed gas at a stabilized rate of 10.9 MMcf/d, with no CO2 recorded. According to the operator, test results indicated a laterally continuous reservoir with permeability in the order of multi-Darcy. The well reached a depth of 1,330 feet (approximately 405 m) on 19 June 2017.

Coro Energy with Conrad Petroleum and Empyrean Energy have received the required regulatory approvals for Coro's 15% acquisition in the Duyung PSC, located in the West Natuna Basin

On 4 May 2020, local news reported that Gas y Petroleo del Neuquen has sold its 10% interest in the Aguada Federal Block to partners Wintershall Dea and ConocoPhillips – therefore exiting the concession. With the formal approvals granted, Wintershall Dea is the operator with 45% working interest, ConocoPhillips holds the remaining 45% working interest - no clarification how the companies split the 10%. In December 2019, Wintershall Dea was granted formal approvals to transfer half of its working interest to ConocoPhillips in the Aguada Federal and Bandurria Norte blocks in the Province of Neuquen. Wintershall Dea is the operator of the block. The 97.38 sq km Aguada Federal is situated in the Neuquen Embayment portion of the Neuquen Basin in the oil and gas window trend. Wintershall Dea has drilled nine unconventional horizontal wells in the Aguada Federal block since 2018. Previously Wintershall Dea was operator with 90% working interest in the Aguada Federal block and provincial company GyP Neuquen holding the remaining 10%. On 7 January 2014 German oil and gas company Wintershall AG announced signing a joint venture (JV) farm-in agreement with provincial oil and gas company GyP to jointly develop an unconventional pilot project in the Vaca Muerta Formation Background Information The Aguada Federal block is situated directly next to state company YPF’s La Amarga Chica block where the operator and its Malaysian state partner Petronas recently agreed to enter the development phase on their Vaca Muerta shale oil project in late-2018. Meanwhile, Bandurria Norte is located adjacent to YPF’s San Roque and Bajada de Anelo blocks, where the company intends to develop shale oil in 2020 as part of its 1.6 billion investment plan for 2020 to 2021. On 7 January 2014 German oil and gas company Wintershall AG announced signing a JV farm-in agreement with provincial oil and gas company GyP to jointly develop an unconventional pilot project in the Vaca Muerta Formation. The governor of Neuquen Province Jorge Sapag signed a decree ratifying the agreement. The “Aguada Federal” project covers a 97 sq km area in the Aguada del Chanar Block. Between the years 2014 and 2016 Wintershall and GyP will evaluate the potential of the Vaca Muerta Formation in a first exploration phase which will involve drilling of up to six wells and an investment of approximately USD 110 million (100%). If successful the JV partners will move to a pilot project phase estimated at USD 300 million and requiring approximately 20 vertical and/or horizontal wells. A third phase, contingent upon the results of these E&P efforts, would involve the drilling of more than 320 wells and cost approximately USD 3 billion. Effective 13 January 2014, Wintershall will assume a 50% participation interest from GyP and become operator. Wintershall, ranked as the fourth largest natural gas producer in Argentina, has been present in the country since 1978. With working interests in 15 oil and gas fields, it produces 26 MMboe a year (~70,000 boe/d). The largest part of the output comes from offshore fields off the coast of Tierra del Fuego, including Carina and Aries. Wintershall is Total’s partner in the Vega Pleyade offshore gas development, set for production in 2016. The company is also present in the Neuqen Basin, with the production of conventional hydrocarbons since 1994 and the current evaluation of the Vaca Muerta shale. In 2012, two more assets were added to its portfolio. The CN-V and Ranquil Norte blocks, which cover a total area of 3,190 sq km in the province of Mendoza, are interpreted to hold potential for both conventional and unconventional hydrocarbons. The area is said to hold both shale gas and shale oil potential. In CN-V, Wintershall has a 100% interest, while in Ranquil Norte Total is partner with a 50% interest.

GYP Neuquén has reportedly withdrawn from the Aguada Federal block (97km²), its 10% to partners Wintershall Dea (op) + ConocoPhillips.

According to reports in early-October 2018, Noble Energy and Edison International have notified Argos Resources of their intention to withdraw from the PL001 License. Noble was the block operator with 75% interest as partner Edison held the remaining 25%, while Argos held a 5% overriding interest in the block by virtue of the farm out agreement signed between the companies in April 2015. Once the exit is complete, Noble and Edison will have no assets left in the Falklands. It was said that Argos plans to maintain the license while seeking new partners. PL001 covers 1,126 sq km in the North Falkland Basin and located west of Premier’s Sea Lion discovery, which is still awaiting a final investment decision. Noble and Edison initially planned to drill an exploration well on the Rhea prospect in the block, but plans were terminated in 2016. The partners disclosed plans to drop the Northern and Southern licences in 2017, following the non-commercial results of the Humpback 1 exploration well. Background Information Argos Resources received an official approval for a three year extension to the PL001 License in August 2016. The extension pushed the current 2nd exploration phase expiration date out to November 2019.

Noble Energy (75% op.) and Edison International (25%) have notified Argos Resources (->100%) of their intention to withdraw from the PL001 License. Once the exit is complete, Noble and Edison will have no assets left in the Falklands.

It was reported on 6 February 2020 that Amity Oil International Pty Ltd has transferred its full 50% participating interest in E18-C3-2 production lease to Petrogas Petrol Gaz ve Petrokimya Ürünleri Ins. San. ve Tic. A.S. on 28 January 2020. As a result of this transaction the revised equity split for E18-C3-2 lease is as follows: Turkiye Petrolleri A.O. (TPAO) 50% (operator) and Petrogas 50%. Amity Oil and Petrogas, both are the subsidiaries of TransAtlantic Petroleum. Amity Oil had submitted the application to the government on 16 September 2019 for the approval of this transaction. The licence, located towards northwest of the country in Thrace Basin, covers an area of 28 sq km and it was awarded to TPAO on 12 October 2017 for four-year term.

Turkey, E18-C3-2

On 31 January 2019, the CNH approved the 30% working interest farm-out by operator CNOOC to PC Carigali in the CNH-R01-L04-A4.CPP/2016 contract, Area 4 block.  CNOOC remains the operator with 70% working interest and PC Carigali has 30% working interest.  CNOOC is planning the drilling of at least one commitment well in the block during 2019. On 24 April 2018, the CNH approved the exploration plan submitted by operator CNOOC for the CNH-R01-L04-A4.CPP/2016, Area 4 block that includes the drilling of one commitment well and conducting geological and geophysical (G&G) studies during the four year exploration phase.  The approved exploration plan includes the drilling of sub-salt new-field wildcat (NFW) Xakpun 1EXP provisionally scheduled for 1st quarter 2019.  The proposed total depth (PTD) is 5,500 m with the Wilcox formation being the primary target at approximately 5,000 m.   The prospect underlies a 2,000 m salt canopy in this area of the basin.  The prospective resources for the well have been estimated to be 323 MMboe with an estimated risked reserves to be incorporated of 135 MMboe.  The prospect water depth is 1,528 m which puts its location somewhere in the east central to southeastern area of the block.  Total well cost was estimated to be USD 160 million.  Total investment in the exploration plan was reported by the CNH to be approximately USD 172 million for 79,511 total work units, the well is 74,300 work units. On 10 March 2017, the CNH signed the official award for an exploration and production license contract with China Offshore Oil Corporation (CNOOC) 100% for the CNH-R01-L04-A4.CPP/2016, Area 4 block the company won through the CNH-R01-L04/2015 Bid Round. The official contract name is CNH-R01-L04-A4.CPP/2016. On 5 December 2016 China Offshore Oil Corporation (CNOOC) was granted a preliminary award as the high bidder for Area 4 - Perdido block through the CNH-R01-L04/2015 Bid Round.  The ratification of the preliminary award was approved by the CNH on 7 December 2016.  The company offered a total of 15.01% additional royalties and 1.00 as the additional work investment factor which is equivalent to one commitment well and a total minimum investment commitment of USD 33.61 million which also includes the minimum investment commitment of USD 3.61 million.  There were no additional bids for the block. The Area 4 - Perdido block covers an area of 1,876.70 sq km in the Deep-Water Gulf of Mexico, Perdido area and the minimum work commitments were set in the bid documents of 3,611 work units.

Mexico (Rio Grande Embayment (Gulf Coast B.)) China

IHS Markit understands that Pertamina’s deeper pool wildcat Belimbing Deep 1 (BED 1), in the Sumbagsel 2 PPC, located in the South Sumatra Basin, has been plugged and abandoned around February 2019, with results unreported. The well, located in the Belimbing Jaya Village, in the Muara Enim Regency, was probably spudded in early November 2018, drilling using PDSI’s Rig no.42 N-1500-E, and may have a PTD of around 3,500 m. Typical exploration targets in the area are the Lower Miocene Batu Raja Formation and Talang Akar Formation. The last exploration well in the block was Sekarwangi 1, completed in late October 2018. The well may have encountered gas, however the three DST tests performed at depths of 3,218 m to 3,228m, 3,074 m to 3,080 m and 2,071 m to 2,074 m have likely shown intermittent flow. The well was since plugged and abandoned. Sekarwangi 1 was possibly spudded in May 2018, using PDSI-operated Rig no.42 N-1500-E. The well is located within the vicinity of Darmo village, in the Muara Enim Regency. Drilling operations was reportedly to be ongoing as of July 2018.  Earlier in April 2018, Pertamina conducted socialization activities with the local community in preparation for the drilling activity. The previous drilling activity in the block was drilling of wildcat Sakura 1, spudded in September 2017. The well, with a PTD of 3,800 m, was targeting the deeper sandstones of the Upper Eocene-Lower Oligocene Lahat Formation, and secondarily the Upper Oligocene Talang Akar Formation. It is understood that the well encountered only minor gas indications. In November 2017, the company likely completed a 2D seismic survey over the Selingsing area. As of June 2017, approximately 85% of the planned 608 km had been acquired. The survey was conducted by PT Elnusa. Acquisition commenced in January 2017. Over 50% of the acquisition had been completed as of February 2017. The seismic campaign was initially expected to last for approximately four months. A socialization event to inform the local community about the planned survey was held on 6 October 2016. Data acquisition will cover areas in the vicinity of the Talang Akar-Pendopo field, within the Talang Ubi sub-district of South Sumatra Province. Preparations for the survey were ongoing in 2H 2015. In late 2014, Elnusa issued a pre-qualification tender for a subcontract related to the acquisition. Initial socialization activities with the locals were likewise conducted in late November 2014. Pertamina holds 100% operatorship of the block. Background Information Upstream holding company PT Pertamina EP was established on 13 September 2005. PPC terms cover a 30 year lifespan with a 10% relinquishment after 10 years and also include a 25% DMO on both oil and gas and a 67.2269%/32.7731% profit split for oil and gas between PT Pertamina EP and the government. The conversion to PSC status under BPMigas supervision was part of the ongoing process of privatization of PT Pertamina required under Oil and Gas Law No 22/2001. PT Pertamina's upstream operating areas, converted to "Production Sharing Cooperation Contracts" (subsequently termed "Pertamina Petroleum Contracts" or PPCs), were signed with BPMigas on 17 September 2005. The signature was delayed from its original scheduled date of 25 June 2004 due to undisclosed "internal problems" within PT Pertamina. This was then rescheduled to take place on 12 December 2004 at a PSC signing ceremony but it was again delayed as the PPC model was still being examined by the government. PT Pertamina then stated that it would be ready to establish operating subsidiaries on 17 September 2005. Numerous exploration wells have been drilled by Pertamina in the block, to find additional reserves and support domestic production. Exploration drilling in 2011 Semparuti 1 wildcat was suspended as a gas with condensate discovery in March 2011. It was reported to have flowed 5MMcfg/d plus condensate during testing. Further details were not provided. Testing operation commenced in late January 2011. The well, located within the vicinity of the Kuang field, was spudded in late December 2010 using the “National 80” rig and was drilled to a TD of 1,650m as planned. It targeted sandstones of the Upper Oligocene to Lower Miocene Talang Akar Formation, carbonate build-up of the Lower Miocene Batu Raja Formation and the Pre-Tertiary Basement. Prabumenang 7X (oil shows), Prabumenang 8X (oil and gas), Tasim 4X (oil and gas), Kuang EX (oil and gas) and Semparuti 1 (gas and condensate discovery) were the other exploration wells drilled in 2011. Exploration drilling in 2012 Hibiscus Selatan 1 was suspended as an oil and gas discovery on or around 5 January 2012. IHS understands that at least five DSTs were conducted, with the well testing a cumulative rate of more than 300bo/d plus 2MMcfg/d. The well, located about 2.3km west of the Tanjung Tiga Barat oil field, was spudded on 3 October 2012 and was drilled to a TD of 2,250m using the “N55XC” rig. It had a PTD of 2,250m and primarily targeted Upper Oligocene to Lower Miocene Talang Akar sandstones trapped in an anticline. Secondary target is the fractured Pre-Tertiary Basement. Lavatera 1 wildcat was reported on 20 February 2012 to have successfully encountered gas in the Middle to Upper Miocene Air Benakat sandstones, which is one of the well’s objectives. The test interval at 820-825m from the said formation flowed 5.7 MMscfg/d through a 36/64” choke. A local press report has also mentioned test flow rates of 4 MMscfg/d through a 48/64” choke from the well but further details were not reported. A Put on Production (POP) plan was intended to be submitted, targeting production in early 2013 at a rate of 3 MMscfg/d. Gas will be sent to PGN. Lavatera 1, located 3.4km northwest of the Pager Dewa gas and condensate field, was spudded on 25 November 2011 using the “XJ-750” rig and it was drilled to a TD of 1,958m. It had a PTD of 1,987m and it targeted multiple reservoirs. Aside from the Air Benakat sands, other reservoir targets are carbonates of the Lower Miocene Batu Raja Formation and sandstones of the Upper Oligocene to Lower Miocene Talang Akar Formation. Testing commenced in January 2012. Rig was released on 14 February 2012. According to a local press report on 16 April 2012, Pertamina discovered gas and condensate in the Piretrium 1 wildcat. The well was reported to have tested a cumulative rate of 15.35MMcfg/d plus 557bc/d in sandstones of the Middle to Upper Miocene Air Benakat Formation and the deeper Eocene to Oligocene Lahat Formation. The well, located 4.4km southeast of the Tasim gas and condensate field, was spudded on 29 January 2012 using the “NYT-19” rig and was drilled to a TD of 1,845m. It had a PTD of 1,845m. It targeted multiple reservoirs – carbonates of the Lower Miocene Batu Raja Formation, sandstones of the Air Benakat Formation and the Pre-Tertiary Basement. Pertamina also drilled several appraisal wells in 2012, namely Pemaat 3X (gas with condensate), Pemaat 4X (dry), Pemaat 6X (dry), Tasim 5X (gas with oil), and Kuang DX (oil and gas). Exploration drilling in 2013 The Puring 1 wildcat was suspended as an oil discovery on 13 February 2013. The well, located about 1.5km north of the Kuang field, was spudded on or around 13 December 2012 and was drilled to a TD of 1,839m. It had a PTD of 1,840m and primarily targeted the Lower Miocene Baturaja carbonates. Puring 1 is the eighth exploratory well was spudded in the block in 2012 following the Hibiscus Selatan 1 wildcat. Gandaria 1 wildcat was suspended as a gas and oil discovery in late August 2013, with at least six DSTs was completed by 19 August 2013. According to local press report, the fifth DST yielded 2 MMscfg/d and 215 bop/d. It was drilled down to a TD of 2,025 m on or around early July 2013. The well was spudded on 21 May 2013 and it could have PTD of around 2,200 m. It will primarily target Lower Miocene Baturaja carbonates with Upper Oligocene to Lower Miocene Talang Akar sandstones as secondary targets. The well located around 8km southwest of Puring 1 oil discovery well in Muara Enim regency. Gandaria 1 is the first exploration well spudded in the block in 2013. Mandevilla 1 was plugged and abandoned in early December 2013. According to a local report, the well flowed non-commercial gas amounts during testing. The operator commenced well-testing operations in late October 2013 and prior to the test, it was drilled past 1,125 m on 4 October 2013. The well was spudded on 9 September 2013, located within the Rejang Lebong Regency of Bengkulu province, around 28km southwest of Musi field. It could have PTD around 1,100m to 1,200m. It will primarily target Lower Miocene Batu Raja Formation and Upper Oligocene to Lower Miocene Talang Akar Formation as secondary targets Akaliva 1 ST1 wildcat was abandoned as a gas shows well on 27 December 2013. The operator conducted at least three DSTs in the well, with two DSTs was completed on 21 December 2013. Well testing operation commenced in late November 2013. Last reported drilled depth was at around 1,550 m within the first sidetrack hole on 20 November 2013. From previous report, the well was drilled down to 870 within the original hole on 12 October 2013. The well was spudded using “N-80” land rig on 27 September 2013, located south of Selo field of Betun-Selo KSO. It had a PTD around 1,540 m, primarily targeting Upper Oligocene to Lower Miocene Talang Akar Formation and sandstone reservoirs of Eocene to Oligocene Lahat Formation. The Pre-Tertiary Basement provided secondary target for the well.

IHS Markit understands that Pertamina’s deeper pool wildcat Belimbing Deep 1 (BED 1), in the Sumbagsel 2 PPC, located in the South Sumatra Basin, has been plugged and abandoned around February 2019, with results unreported.

Angus Energy Plc announced on 22 January 2018 that it has agreed to acquire a 25% interest in PEDL 244 which contains the Balcombe discovery from Cuadrilla subsidiary Cuadrilla Balcombe Limited. Under the terms of the deal Angus plans to assume operatorship of the licence and the company will take forward the fully approved well test programme of the Balcombe-2Z horizontal well. Angus must pay GBP 2 million within 20 working days of the 20 January 2018 (less GBP 150,000 paid under confidentiality agreement with the sellers) and GBP 2 million following consent for the transaction from the OGA. If a successful well test programme is completed Angus will assume the associated costs of a Field Development Plan (FDP) submission to the OGA. On 9 January 2018 Cuadrilla announced that it had received approval from West Sussex County Council’s Planning Committee for the company to flow test and monitor its Balcombe-2Z well in PEDL 244. The company initially submitted an application to undertake this work in 2014. The well requires no hydraulic fracturing due to the rock being naturally fractured. The planning permission runs out in 2021 where Cuadrilla will have needed to had tested, plugged and abandoned the well and restored the site to a suitable condition. Cuadrilla spudded the appraisal well, Balcombe-2 on 2 August 2013 after several delays on the site due to protesters. The well had a planned vertical depth of 3,000 ft (914 m) with potential to kick-off a 2,500 ft (762 m) horizontal sidetrack. Cuadrilla used the same site that Conoco used in 1986 to drill the Balcombe-1 well. Cuadrilla had no plans to frack the well but initially it was understood that it will use hydrochloric acid to stimulate the reservoir which is Middle Jurassic (Great Oolite) Limestone. On 16 August 2013 operations were temporarily suspended at the site following police advice regarding potential disruptions from protesters (resumed 22 August). On 5 September 2013 the company kicked-off sidetrack Balcombe-2Z. On 23 September 2013 Cuadrilla announced that operations had been completed at the well which encountered oil and gas. The well reached a TD of 2,700 ft (823 m) collecting 294 ft (90 m) of core. The horizontal leg of the well (Balcombe-2Z) was drilled through the Middle Kimmeridge Micrite Limestone for a distance of 1,700 ft (518 m). Cuadrilla was awarded PEDL 244 in 2008 following the 13th Onshore Licensing Round. The licence covers an area of 153 sq km. Conoco’s Balcombe-1 encountered oil shows in the upper of two Middle Kimmeridge micrite units. An open hole DST resulted in no fluids back to surface however, a post acid wash cased hole DST resulted in flow rates of 50 bo/d. Interest in PEDL 244 following completion of the deal will be held by Angus Energy Plc (25% + operator) Cuadrilla subsidiary Cuadrilla Balcombe Limited (56.25%) and AJ Lucas subsidiary Lucas Bolney Limited (18.75%).  

Angus Energy is taking a 25% stake in PEDL 244 in the Weal basin, which hosts the Balcombe find, from Cuadrilla (->56,25% op, Lucas Bolney 18,75%).

E-C part of AE-0073-M-Puchut-01 block, onshore Tampico-Misantla Basin in Puebla, compl o&g at TMD 4,370m in mid-May ’19 after testing 500 bo/d + 1.1 MMcfg/d. Target Santiago fm.

Maxochitl 1 (Pemex 100%) in AE-0073 block, compl o&g at TMD=4370m in mid-May ’19 after testing 500 bo/d + 1,1 MMscfg/d. Target Santiago fm.

The 405-sq km Proninskiy block in the Samara Oblast, Volga-Ural, was auctioned on 7 Dec ’17, Region-Neft winning the 25-year rights with a USD 2.125 MM offer (starting price USD 0.7 MM).

Region-Neft (100%) awarded Proninskiy block in the Samara Oblast

According to official reports in January 2020, Interoil has completed its acquisition of 8.34% and operatorship in five Roch-operated blocks in the Santa Cruz Province. It was said that Interoil's partner in its other Argentinean assets, Selva Maria Oil, will be operating the blocks until the company receives the operator license from the Argentine government. Other partners in the blocks are Echo Energy with 70% stake, and a subsidiary of Integra Oil & Gas, IOG Resources SA, with the remaining 21.66%. Echo entered the block in October 2019 following a purchase agreement with Phoenix Global Resources, while Integra Oil & Gas reportedly acquire its stake from previous operator Roch's original 30% interest. The blocks consisted of Campo Bremen, Chorrillos, Moy Aike, Oceano, and Palermo Aike, and all situated in onshore and shelf of Austral Basin. Block Name Basin Name Onshore/Offshore Contract Sqkm Onshore Sqkm Shelf Sqkm Deep Water Sqkm Campo Bremen Austral Basin Onshore 809.16 809.16 Chorrillos Austral Basin Onshore 650.7 650.7 Moy Aike Austral Basin Onshore 728.45 728.45 Oceano Austral Basin Onshore/Offshore 102.73 77.99 24.74 Palermo Aike Austral Basin Onshore 525.13 525.13   In August 2019, daily production in Campo Bremen block was 3.7 MMscfg/d and 92 bo/d, Chorrillos block was 11.1 MMscfg/d and 651 bo/d, Moy Aike was 146 Mscfg/d and 82 bo/d, and Oceano was 2.9 MMscfg/d and 34 bo/d. Meanwhile, the Palermo Aike block only has several discoveries and abandoned fields.    Background Information Interoil entered Argentina in April 2019 through a joint venture with Selva Maria Oil on Mata Magallanes Oeste and Canadon Ramirez blocks in San Jorge Basin and La Brea block in Neuquen Basin.

Interoil closed an agreement with Roch under which it acquired an 8.34% interest from the latter in 5 mature prod. leases designated Santa Cruz Sur Assets (Campo Bremen, Palermo Aike, Oceano, Chorillos..).

On 19 October 2017, Woodside reported that wildcat Khayang Swal 1 in Block AD-7, in deepwater Rakhine Basin, was dry. The well was plugged and abandoned in late September 2017 after encountering water-wet sandstones in the Pliocene turbidite target. Final TD for the well was 3,693 m. Khayang Swal 1 was spudded on 28 August 2017 using Transocean’s “Dhirubhai Deepwater KG2” drillship, at a water depth of 1,487 m. After completing the well, the drillship was released by the operator. The high-impact well was likely targeting a previously undrilled channel complex located at the southern edge of the block, some 25 km south of the significant Thalin 1A discovery. The Khayang Swal prospect was estimated to contain resources in the order of multiple Tcf of gas. PTD of the well was 3,815 m. Khayang Swal 1 was the fifth and final firm well drilled by the “Dhirubhai Deepwater KG2” which was contracted by Woodside for a long-term exploration drilling campaign in blocks AD-7 and A-6. Woodside previously reported plans to drill at least one additional contingent well in block AD-7 in late 2017, and potentially further wells in 2018. However the 2017 campaign has been completed, and the future drilling plan could depend on the full evaluation of results from the latest campaign. The drilling campaign commenced in late February 2017 with appraisal sidetrack well Thalin 1B in block AD-7, followed by the second appraisal Thalin 2. Thalin 1B successfully tested gas at a rate of 50 MMcf/d. Thalin 2 was completed in early June 2017, encountering gas shows in the targeted reservoir. The rig subsequently moved to block A-6 for a two-well programme (Pyi Thit 1 and Pyi Tharyar 1). The rig mobilized to the Khayang Swal 1 location in late August 2017 after the completion of the two wells in block A-6. Woodside has reported an estimated expenditure of around USD 100 million for exploration activities in Myanmar in 2017. A seafloor sampling campaign over blocks AD-7 and A-6 was conducted between around 22 December 2016 and 15 January 2017, using the “Fugro Supporter” MV. Approximately 990 km of MBES data were likewise acquired during the survey. An Environmental Impact Assessment (EIA) for the campaign in Block AD-7 was ongoing in early September 2016 with project report, scoping report and terms of reference submitted to the government. Drilling scoping report for Block A-6 had not yet been submitted as of October 2016. A positive outcome of the 2017 exploration drilling campaign may result into further drilling of up to four wells over 2018 and 2019, subject to the approval of joint venture partners. The Thalin 1A discovery is estimated to contain 2C resources of 1.5 Tcf of dry gas. Development options under consideration include a tie-back to the existing infrastructure at POSCO Daewoo’s Shwe field complex, or a new hub for broader gas aggregation and export. The development concept is expected to be finalized in early 2018, pending approvals from partners and the government. Block AD-7 is jointly operated by POSCO Daewoo with 60% interest (PSC operator) and Woodside Energy Myanmar with 40% (deepwater drilling operator). During the first half of 2016, 3D seismic survey and drilling of the Thalin 1 gas discovery was conducted in block AD-7.

Khayang Swal 1 op. by Posco Daewoo (blk op. 60%), Woodside (well op. 40%) in AD-7 block, P&A, dry after encountering water-wet sandstones in the Pliocene turbidite target.

13 February 2020, Turkmengeologiya reported obtaining a "commercial" flow of gas from a depth of 7,000 m in well Uzynada 8 drilled on the Uzynada gas condensate discovery close to the Caspian coast. No further details of the test have been disclosed. Uzynada 8 was spudded in December 2018 and is a follow-up (outpost) well on Uzynada 7, the discovery well (see Background below). Earlier this month the Turkmen authorities announced positive test results in well Uzynada 1 (2020), and in December 2019 they revealed plans to drill a new well on the Uzynada Gunorta (Uzynada South) structure. Background Information The Uzynada discovery is located some 30 km south of the Barsagelmes field (South Caspian Basin). It was discovered by well no. 7 in May 2017. The well flowed gas with condensate at rates of 17.1 MMscf/d and 1,200 b/d, respectively, from the interval of 6,689-6,695 m in the Lower Red Bed Series (Pliocene). The well has been drilled to 7,150 m and is the first super-deep well in Turkmenistan. It was drilled by Turkmennebit with a Chinese-made “ZJ70” heavy drilling rig. In January 2020, well Uzynada 1 (2020) tested 106,000 cu m of gas/day (3.63 MMscf/d) and 143 tonnes/d (ca. 1,150 b/d) of condensate. The hydrocarbons have been tested from the Lower Red Bed Series, in the interval of 6,746-6,752 m. The discovery is important for understanding prospectivity of the Block 21’s which lies immediately offshore. Four prospective intervals were identified in well 7 prior to drilling, including the Apsheronian Formation at -3,100 m subsea, the Upper Red Beds (Pliocene) at -4,000 m, and two intervals in the Lower Red Beds at -5,600 m and -6,125 m. Initial seismic surveys were carried out over the Uzynada structure in 1973 and 1980. At least four exploration wells were drilled in the Uzynada structure in the 1970s, to TDs between 4,200 m and 4,400 m. None of those wells had been successful.

Uzynada-8 appr Uzynada-7 gas-cond discovery area, Caspian coastal area (S. Caspian Basin), reportedly tested a commercial gas flow from some 7,000m depth, no further details.

On 3 July 2020, the Ministry of Energy and Mines (MINEM) has given approval for Perupetro to proceed with the award of an exploration and exploitation of hydrocarbons contract in Block Z-68 to Tullow Oil plc. The 6,005 sq km block is locate offshore overlapping the Salaverry and Lima basins off the coast of Santa, Casma and Huarmey (Ancash) provinces. The block is situated to the west of technical evaluations areas (TEA) Area LXXXIV and LXXXIII both operated by BP Exploration Operating Co. Ltd. Water depths across the block ranges from According to the decree Block Z-68 consist of a preliminary clause, 23 clauses and 10 annexes, in addition to the intervention of the Central Reserve Bank (BCR) to guarantee the contractor company. There have been no wells drilled in the block to date, the block is however sparsely populated with 2D seismic and has a 324 sq mi (879 sq km) seismic program in the northern tip of the block shot by Savia Peru in 2011. The award comes after an original award of five blocks in 2018 to Tullow was declared unconstitutional based on a lack of consultation with the local fishing community which requires all communities be consulted prior to the award of a contract. Now that Blocks Z-64, Z-67 and Z-68 have been awarded, Tullow continues to negotiate with Perupetro on the remaining two blocks of the five which include Z-65 and Z-66. These remaining two blocks are located in a highly perspective fishing area and are likely going to take longer in the negotiations process with local fishing communities.

Peru (Lima B.) Block Z-68 op. by TULLOW (100%), On 3 July 2020, the Ministry of Energy and Mines (MINEM) has given approval for Perupetro to proceed with the award of an exploration and exploitation of hydrocarbons contract in Block Z-68 to Tullow Oil plc. The 6,005 sq km block is locate offshore overlapping the Salaverry and Lima basins off the coast of Santa, Casma and Huarmey (Ancash) provinces.

Hirapur area, Sundulbari-Agartala Dome PML, Tripura-Cachar, ops terminated 3Q at TD ca. 3,000m, tested (no results), E-1400-14 rig. PTD was 3,350m.

BAAA explIndia (Cambay B.) Hirapur, Sundulbari-Agartala Dome PML, ops terminated

15 May 2019, Tatneft (Russia) has signed two agreements with the Uzbekneftegaz national oil company (UNG). The first contract concerns the XLVII Tashkent Block. Tatneft will invest its own funds into gathering seismic data and drilling exploration wells in the block. In the case of a commercial discovery, Tatneft will have the priority right to sign a production sharing contract for the block or negotiate a joint venture agreement with UNG to continue with the project. The second contract covers three mature oil fields in the Fergana Basin: Andizhan, Palvantash and Palvantash Garbiy (Palvantash West). Tatneft will utilise proprietary technologies to initiate enhanced oil recovery at these fields. No further details of the new contracts have been publicised. Around two thirds of the XLVII Tashkent Block fall within the Syr-Darya Basin, while the other third is in a non-prospective territory separating this basin from the prolific Amu-Darya and Afghan-Tajik basins to the south. Currently there are no discoveries in this block, nor in the Syr-Darya Basin as a whole. Very few exploration wells have so far been drilled in the block. The Andizhan (discovered in 1937), Palvantash (1942) and Palvantash Garbiy (1955) fields are small and very mature fields. Tatneft specialises in mature field development as well as in production of heavy oil/bitumen in its home country of Tatarstan in central Russia.

Uzbekistan, not found

In early October 2018, Pluspetrol tested oil on the Jaguel Casa de Piedra Sur a-1008 appraisal well, on the Gobernador Ayala Block, Neuquen Basin. 197 bo/d was tested from the Centenario Formation over the 549-567m interval. The well was spud on 22 August 2018 and ended drilling on 27 August 2018. The main target to extend the field is the Centenario Formation. The PTD of the well was 720m. Pluspetrol operates the Gobernador Ayala Block with 47.4%, Petrolera Pampa 22.5% and YPF holds a 30.1% interest in the block.

Argentina, Gobernador Ayala (CNQ-7)

The latest news on the operations in new-field wildcat Schwegenheim 1 in the Römerberg permit in western Germany states that Neptune Energy Deutschland GmbH (operator) has commenced long-term capacity testing. The well, drilled by Neptune Energy with the equal partner Palatina GeoCon GmbH & Co.KG., reached the final depth of 2,415 m and encountered oil in the targeted Lower Triassic (Buntsandstein) reservoir succession. The results of the well are expected in the first quarter of 2020. Schwegenheim 1 was started on 12 September 2019. The well is located approximately 5 km southwest of the city of Speyer, between the localities Schwegenheim and Harthausen. The well is falling within the Upper Rhine Graben. Schwegenheim 1 was targeting the Lower Triassic (Buntsandstein) reservoir succession – the same reservoir as is known in the Römerberg field – at a planned final depth of 2,600 m (TVD). The news on the planned well were officially disclosed on 21 February 2019. News from August 2019 indicated that the drilling pad was constructed, and the spud of the well was expected during September 2019. By the end of September, the well reached a depth of 1,579 m. The final depth was reached on 24 October 2019, after 818 m had been drilled during the month. As announced on 12 December 2019, the operator is planning to test the well for several weeks to validate the commerciality of the pool. Background Information The well Speyer GTB1, drilled for geothermal purposes in 2003, turned out an incidental oil discovery and is being developed/produced. The discovery well, Speyer GTB1, was renamed to Römerberg 0 and converted into a producer. The field is developed with eight subsequent wells, since. The well Schwegenheim 1 is targeting a separate compartment of the Römerberg field.

Germany (Upper Rhine Graben) Graben

On 1 August 2020, BP Exploration & Production was awarded Atwater Valley blocks AT 30 (G36915) and AT 31 (G36916), located in the Gulf of Mexico Basin. The blocks have yet to be drilled. AT 30 and AT 31 were originally offered as part of recent GOM-wide OCS Lease Sale 254, which was held on 18 March 2020. Following formal award, BP Exploration & Production is now the operator and sole interest-holder (100% WI + Op) in AT 30 and AT 31.

(GOM B.) BP was awarded Atwater Valley blocks AT 30 (G36915) and AT 31 (G36916) as now the operator and sole interest-holder (100%).

Cairn announced on 27 November 2019 that it has agreed to sell its wholly-owned subsidiary Capricorn Norge AS to Solveig Gas Norway AS for the sum of USD 100 million. Capricorn holds interests in 17 licences in Norway and operates five of these. The licences include three small discoveries (Agat, Jette, Skaugumsasen) and the Nova field which is under development and due onstream in Q3 2021. Capricorn drilled its first two operated wells on the NCS in 2019 – both were dry holes. It is planning two further wells in 2020. The company was pre-qualified as an operator in Norway in late 2015 and in February 2016 it was awarded its first licence. The sale is subject to various regulatory approvals and is expected to complete in early 2020. Cairn will use the proceeds of the sale to support its ongoing business (which includes assets in the UK). Solveig Gas Norway, established in 2011, was acquired in 2019 by HitecVision. It is a significant owner in Gassled and has recently been involved in deals to acquire interests in Polarled and Duva. Its strategy is to become an integrated, infrastructure-based E&P operating company. Capricorn's first NCS operated well was 6508/1-3 which targeted the Lynghaug prospect in PL 758. A 170 m section of Are Formation (the primary objective) was encountered with around 50 m of net sandstone interbedded with claystones and coals. Failure was put down to migration. If it had been successful it would have been a play opener for the Nordland Ridge and could have been developed as a tie-back to the Norne FPSO. Pre-drill reserves estimates were 70 MMboe. Its second well, 6608/11-9, was drilled on the Godalen prospect in PL 842. Godalen had an Upper Jurassic Rogn Formation objective with potential to contain 90 MMboe and could also have been tied-back to Norne in the event of a discovery. The Rogn Formation was absent, although there were some sands (total 40 m) in the Upper Jurassic Melke Formation (118 m total section). Nova was previously called Skarfjell and was discovered in 2012 by 35/9-7. Its reservoir is the Upper Jurassic Heather Formation. The discovery was appraised over the following year and the PDO was submitted in May 2018 (and received approval four months later). Operator Wintershall Dea intends to recover 77 MMboe from the field over an eight-year period using two 4-slot subsea templates (installed in May 2019) sited one kilometre apart (the northerly template will host three water injectors and the southerly one will have three producers). The templates will be tied back to Gjoa which lies approximately 16 km to the northeast. There is also provision for a third template with four more wells if needed. Gjoa will supply Nova with power (from shore), gas lift and water injection. Drilling of six wells will commence in H1 2020 and the installation of the other facilities will take place in 2019 / 2020. A new topsides module will be installed at Gjoa in May 2020 where processing will take place prior to export via the Troll oil pipeline to Mongstad. Maximum production is expected to be 50,000 boe/d and investment is estimated at NOK 9.9 billion (USD 1.23 billion). The field consists of three segments and the initial development relates solely to Nova Main, with the Southeast and East segments representing future upside potential.

Ecopetrol (->100%) will take over Chevron’s 43% stake in the Chuchupa & Ballena field in the Caribbean Sea.

On 7 February 2018 Lundin spudded Luno II appraisal well 16/4-11 in PL 359 with the “COSL Innovator” S/S. 16/4-11 is located in the southerly part of the field in the central section (segment B), approximately 2 km southeast of the discovery well. The well was terminated in Triassic or Permian rocks at 2,450 m TVDSS and encountered a 20 m oil column in Triassic sandstones. Reservoir quality is good to very good and the OWC was encountered at approximately 1,947 m subsea. The reservoir (including the water zone) has a total thickness of around 400 m comprising mainly sandstone with some layers of conglomeratic sandstone. Estimated recoverable reserves are between 31 – 82 MMbo and 35 – 106 Bcfg. On 26 March 2018 the well was being abandoned. The licensees will now begin development planning for the discovery with PDO submission likely at the end of 2018. If development of Luno II goes ahead it would be a phased tie-back to Edvard Grieg. Phase I would focus on segment B and would include four wells and then future phases would cover segments A (southeast) and C (northwest) plus any additional prospectivity (segment D and Fignon to the northwest and Back Basin to the north) that is proved to be successful. Luno II discovery well 16/4-6 S was drilled in 2013. A 280 m Jurassic / Triassic sandstone with high net to gross was encountered containing a 45 m gross oil column. The oil is light, the OWC is at 1,950 m and there is a thin gas cap. The well flowed at a rate of over 2,000 bo/d through a 48/64” choke. Later in 2013 Lundin drilled appraisal well 16/5-5 to test the potential southeasterly extension of Luno II. A 150 m thick fine-grained Triassic sandstone came in high to prognosis but was of poor quality. It was concluded that there is a pressure barrier between this well and the discovery well and that 16/5-5 lies in a separate sub-basin. A further appraisal well, 16/4-8 S, was drilled in 2014 and proved a 500 m thick sandstone in the Jurassic / Triassic with a 30 m oil column lying below a very thin gas zone. The well flowed at a rate of 450 bo/d through a 28/64” choke. Estimated recoverable reserves for Luno II are 27-71 MMboe (79% oil). In 2015 Lundin made a small light oil discovery with exploration well 16/4-9 S drilled on the Luno II North prospect. A gross oil column of 23 m was proven in conglomeratic sandstones of the Jurassic / Triassic in a separate sub-basin to the northwest of Luno II. The pressure regimes are different in Luno II and Luno II North and the OWC for Luno II North is deeper at 1,954 m subsea. The well was tested and flowed at a rate of 1,000 bo/d through a 32/64” choke. Estimated recoverable reserves are 12-26 MMboe and it is likely that Luno II and Luno II North will be developed together as a subsea tieback to Edvard Grieg. Interest in PL 359 is divided between Lundin Norway AS (50% + operator), OMV (Norge) AS (20%), Statoil Petroleum AS (15%) and Wintershall Norge AS (15%).    

Norway (Utsira High (Horda Platform)) Edvard Grieg

Add. DEA 18 Feb ’19: North of PL 19-3 field in Bohai Gulf Basin, WD 25m, oil discovery in mid-Feb ‘19, HYSY 923 JU. Target was Tertiary.

LK 19-1N-1d nfw North of PL 19-3 field in Bohai Gulf Basin, WD 25m, oil discovery in mid-Feb ‘19, Target was Tertiary.

Rey Resources Ltd is continuing to seek a farm-in partner for Exploration Permit EP 487 (Derby Block), located in the Fitzroy Graben, onshore Canning Basin. The opportunity was revised after a deal with Doriemus Plc was cancelled in August 2019. Rey aims to bring in a partner to assess the potential of the Wet Laurel Basin Centered Gas play which is considered regionally extensive across the Canning Basin. Ideally, Rey is seeking a partner to acquire a partner for up to 50% equity in return for contributing to the current work programme term and/or providing working capital to Rey. The terms of the farm-in are negotiable with operatorship options considered. The Laurel siltstones of the basin centred gas (BCG) play have been proven by Buru at both Valhalla and Asgard (now held by Mitsubishi). The extension of the play in the basin has been estimated by Buru to contain around 13 Tcf gas and up to 24 Tcf, inclusive of the EP 487 area. Rey has reported that a conventional play in the mid-Laurel has been interpreted from seismic data. The play is estimated to contain up to 4 Tcf of wet gas (~ 120 MMb liquids) which could flow without stimulation. Total potential recoverable resources for the entire permit area was estimated by 3D-GEO in January 2016 as 24.6 Tcf gas, plus 612 MMb condensate (P50). In the case that the first commitment well targets the conventional potential of the permit, a vertical well could be drilled plus a horizontal section (second well) to test the reservoir. In the case that the reservoir is too tight to flow conventionally at commercial rates, stimulation will be considered. If the well’s flow is good, the second well would be an appraisal and replace the horizontal component. Rey's deal with Doriemus was first entered into on 28 March 2019 for Doriemus to acquire 50% interest and operatorship in return for drilling a well within 12 months of the farm-in being completed. Doriemus was to engage an independent consultant to reassess the volumetrics of the Butler Prospect and look at drill options to test the play down to around 4,000 m, in Q3 2019. Doriemus had a 60-day due diligence period before entering into a joint operating agreement. After 12 months, and completion of agreed deal terms, Doriemus would be assigned 50% interest in EP 487. However, the deal was cancelled in August 2019 after Doriemus was unable to supply proof of funding for the ability to drill an exploration well by 31 July 2019 which was part of the deal conditions set. On 13 November 2019 approvals were received to suspend, extend and change the work programme for EP 487. The suspension relates to term-two for a period of 12-months, from 14 December 2019 to 13 December 2020 and has a knock-on effect for all subsequent terms and the permit's end date, which is now 13 December 2024. Rey is also now exempt from drilling one AUD 3 million exploration well in term-three, which was scheduled in 2020/21. Term-two commenced in 2015 and has been under suspension since 2016. After completing AUD 1 million of 2D seismic reprocessing in term-one, a zero-dollar value has been assigned to the subsequent studies. However, one exploration well is due by December 2020 which is expected to cost around AUD 12.5 million. Conducting work within the permit area has been, at times, difficult. During 2015, a planned 500 km of 2D seismic survey was delayed by nine months until after the rainy season and subsequently cancelled. The rainy season in the northern-most part of Western Australia is generally intermittent and is most prominent between November and May. The access to firm, dry pastoral lands is seen as critical during land surveys. Background The farm out was first initiated with joint venture partner Oil Basins Ltd (50%). However, the companies entered into an Asset Sale Agreement to transfer Oil Basin’s interest to Rey Resources. The deal completed on 16 June 2017. The transfer provides Rey Resources with 100% interest through its subsidiary companies Rey Derby Block Pty Ltd (50%) and Rey Lennard Shelf Pty Ltd (50%). Under the terms of the Asset Sale Agreement, Oil Basins will no longer have funding obligations which was agreed to under the joint venture agreement with Rey Resources. This includes existing cash calls made by Rey Resources on Oil Basins for approximately AUD 577,000 and legal fees of around AUD 32,000 from historical disputes. Rey Resources entered EP 487 in 2014 after Oil Basins announced that it had reached a formal agreement, with Backreef Oil Pty Ltd and Rey Resources. Under the Deed, Oil Basins resolved all previous disputes with former application partner Backreef and established terms for Rey to attain 50% interest in the block, which was subject to regulatory approvals. Once Rey formally entered EP 487, Oil Basins commenced a farm-out of combined 50% interest to fund a minimum of the first two years of the Work Programme. With the failing of Oil Basins to complete a farm-out by 31 December 2015, Rey was scheduled to take over operatorship. However, Oil Basins claimed that Rey had not met the agreed preconditions and legal requirements to perform as operator of EP 487. On 26 May 2016 Oil Basins was ordered by the Supreme Court of Western Australia to immediately resign as operator of EP 487. Parties interested in the opportunity were to contact: Stanley Fu, Project Manager Tel: +61 2951 9088 Email: [email protected]

Rey Resources Ltd is continuing to seek a farm-in partner for Exploration Permit EP 487 (Derby Block), located in the Fitzroy Graben, onshore Canning Basin.

POSCO International announced on 17 February 2020 that wildcat Mahar 1 in Block A-3, offshore Rakhine Basin, has discovered gas, testing approximately 38 MMcf/d. According to local media reports, quoting the company, the well was drilled to a TD of 2,598 m and intersected a gas column of about 18 m. Mahar 1 is located at a water depth of approximately 1,200 m. The well was spudded in late November 2019 using the "Maersk Viking" D/S. In early December 2019, Mahar 1 was suspended at a drilled depth of approximately 1,960 m while the rig moved to spud a second wildcat, Kissapanadi 1, located 17 km northeast. Kissapanadi 1 may have been completed around late December 2019, with results still under evaluation. Operations at Mahar 1 probably resumed in early January 2020. Upon completion of Mahar 1, the rig is expected to mobilize 24 km southwest to spud the third and last firm well in the campaign, Yan Aung Myin 1, around March 2020. The firm drilling programme is scheduled to last until April 2020 for a total duration of approximately 155 days. Maersk reported that the drilling contract is valued approximately USD 33 million, including mobilization fee. The proven exploration target in the area is the Pliocene turbidite play which is producing biogenic gas from the Shwe Gas Project in adjacent Block A-1. Mahar 1 and any other discovery from the current exploration campaign are planned to be appraised with two to three additional wells, starting from 2021. The new resources could be developed to extend production plateau of the Shwe Gas Project. The operator is planning to complete Shwe Phase II and Phase III developments between 2022 and 2024, in order to maintain gas sales volume of 500 MMcf/d. The Mahar structure, located about 20 km southwest of the Mya South production facilities, was initially defined by the operator as "Prospect G". The other structures were provisionally defined as "Mya Channel Fill" (Kissapanadi) and "Prospect A-South" (Yan Aung Myin). The last exploration activity in the area was a 1,900 sq km 3D seismic survey covering both blocks A-1 and A-3. The survey was likely completed around early March 2015, using PGS’s “Ramform Titan” survey vessel. The survey commenced on 27 January 2015 with the first part of acquisition in Block A-1, followed by Block A-3. Blocks A-1 and A-3 are operated by POSCO International with 51% interest alongside partners ONGC Videsh (17%), MOGE (15%), Gail (India) (8.5)% and Kogas (8.5%). Background Information The 6,779 sq km block was awarded to Daewoo (100%) in February 2004. OVL and Daewoo had applied separately for the block, both seeking a 100% equity. Block A-3 lies adjacent and south of Block A-1, where operator Daewoo made a gas discovery with the sidetrack of its first wildcat Shwe 1, marking the first discovery in Myanmar waters in the Rakhine Basin. The well, drilled from November 2003 to January 2004, flowed 32 MMcfg/d from Lower Pliocene basin floor fan sandstones upon testing. On 1 November 2004 Daewoo entered into the exploration phase of the block by paying an agreed signature bonus of US$ 2.5 million. Subsequently, during February-April 2005, the company acquired 7,797 line km of 2D seismic over the block at an estimated cost of US$ 2.2 million. Interpretation of the new seismic data has led to the identification of undisclosed number of prospects including Mya (Emerald). On 3 October 2005, Daewoo finalised a deal with ONGC Videsh Ltd (OVL), Gas Authority of India Ltd (GAIL) and Korea Gas Corporation (Kogas) to acquire stakes of 20%, 10% and 10%, respectively in Block A-3. The two Indian state firms, OVL and GAIL, paid premiums of US$ 2.88 million and US$ 1.44 million, respectively. It followed a Memorandum of Understanding (MOU) signed on 5 October 2004 to finalise the farm-in agreement, where a combined 30% equity was offered to the two Indian firms against their request for 50% equity. Daewoo drilled four exploration wildcats in the block and discovered the Mya field in 2005. In 2007, two appraisal wells were drilled, Mya 2 and Mya 3, and successfully appraised gas. Three wildcats, Mya West 1, Kyauk-Seine 1 and Thandar 1, were drilled between 2007 and 2008 but did not have favorable results. In January 2008, the operator completed a 1,006 sq km 3D seismic survey using CGGVeritas’s “CGG Harmatan” survey vessel.

Mahar 1 nfw. (Posco 51% op , ONGC Videsh 17%, MOGE 15%, Gail 8,5%, Kogas 8,5%), 1st of 3 wells planned in ex-prospect G in block A-3, ops. concluded at TD ca. 1950m, reportedly 18m gas column encountered (presumably in the target Pliocene turbidites), testing approximately 38 MMscf/d. Appraisal drilling would be planned in 2021. WD=1100m.

Appraisal to Halladale-1DW1 discovery (2015) in VIC/L1(v), Otway Basin, results in line with expectations (gas), terminated of late. Target Waare sst. Next well planned Enterprise-1 onshore to offshore explo well in 2H '20. Lattice (op), partner OGOG. 2019 map extract courtesy Beach. Meanwhile a contract for the Ocean Onyx SS, arrived in Victorian waters in mid-April for an offshore drilling campaign, has been cancelled, although the arrival date was later than had been agreed allowing Beach to exercise its right to terminate the agreement.

Black Watch 1 appr. to Halladale-1DW1 discovery (2015) (Beach 60% op, OGOG 40%) in VIC/L1(v), results in line with expectations (gas), terminated of late. Target Waare sst.

On 9 February 2019 Equinor used the Visund A drilling facility to spud exploration well 34/8-18 S targeting the Telesto prospect in PL 120. The well is a deviated exploratory extension of development well 34/8-A36 H, with its top hole location in the centre of Visund. TD was reached at 6,068 m (3,298 m TVDSS) in the Upper Triassic Lunde Formation and it has made a new, small oil discovery. A 115 m oil column was proven in the Upper Triassic Statfjord Group, with two sandstone reservoirs of 17m (upper) and 20 m (lower), and an OWC at 3,170 m subsea. There was also 15 m of water-wet sandstone in the Lunde Formation. Estimated recoverable reserves are 12-28 MMboe and development using the Visund facilities is likely. The well was abandoned on 22 February 2019. This is the second exploration well in PL 120 within the last 12 months. In June 2018, the company drilled 34/8-19 S from the Visund North template, targeting the Tarqeq / Aegir prospects which had Lower Jurassic Cook Formation and Upper Triassic Statfjord Formation objectives. A 90 m section of Cook Formation was present with 22 m of sandstone but no hydrocarbons. The Statfjord Formation was not reached due to technical issues. Interest in PL 120 is divided between Equinor Energy AS (59.06% + operator), Petoro AS (16.94%), ConocoPhillips Skandinavia AS (13%) and Repsol Norge AS (11%).

034/08-18S (Telesto) (Equinor op. 59,07%, Petoro 16,93%, COP 13%, Repsol 11%) Visund A platform in PL 120, minor oil disc, 115m oil column in the U&L parts of the Statfjord group, 17-20m net, OWC in the L. Statfjord group at ab. 3170m, the resources are estimated at 12-28 MMbl of recoverable oil.

On 27 April 2018, the CNH signed the official award for the CNH-RO2-LO3-VC-01/2017 contract with operator and 100% working interest owner Bloque VC 01, S.A.P.I. de C.V., subsidiary of the consortium led by Roma Exploration and Production LLC.  The consortium of Roma Exploration and Production LLC, Tubular Technology, S.A. de C.V., Suministros Marinos e Industriales de Mexico, S.A. de C.V., and Golfo Suplemento Latino, S.A. de C.V. had the second-place bid in the CNH-RO2-LO3/2016 Bid Round for the Area 6 block in the Veracruz Basin after the first-place bidder, the Shandong consortium failed to pay the government the USD 2.2 million tie-break bonus.   On 8 December 2017, the consortium of Roma Exploration and Production LLC, Tubular Technology, S.A. de C.V., Suministros Marinos e Industriales de Mexico, S.A. de C.V., and Golfo Suplemento Latino, S.A. de C.V. was granted a preliminary award.  The Roma led consortium must now pay the USD 1.5 million tie-break bonus and had 140 days to sign for the contract.  The Shandong consortium forfeited its bid guarantee bond of USD 250,000 for not signing the contract. On 12 July 2017, the consortium of Shandong, Sicoval, and Nuevas Soluciones was the high bidder in the CNH-RO2-LO3/2016 Bid Round for the Area 6 block in the Veracruz Basin and was granted a preliminary award.   For the 193.30 sq km Area 6 block the Shandong consortium offered the maximum additional royalties of 40% 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.   Shandong won the tie break with a bonus bid of USD 2.2 million beating the 2nd place consortium of Roma, Tubular, Suministros Marinos, and Suplemento who offered a bonus of USD 1.5 million.   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, Area 6

On 24 October 2019, the Federal Agency for Subsoil Use held an auction for five blocks in Orenburg Oblast (Volga-Ural Province). Lukoil-subsidiary Ritek won four blocks with combined offer of USD 96.35 million. Gazprom Neft became the winner for one block. Winners of the auction will obtain 25-year E&P licenses. Details of the offer are as follows: The Nizhneozernyy 1 block covers 329 sq km. Hydrocarbon resources (category D1) of the block are estimated at 27 MMbbl of oil and 55 Bcf of gas. The starting price amounted to RUB 7.8 million (USD 0.1 million). Ritek, competing against seven companies, offered RUB 3,243.24 million (USD 50.68 million). The Nizhneozernyy 2 block covers 579 sq km. Hydrocarbon resources (category D1) of the block are estimated at 67 MMbbl of oil and 65 Bcf of gas. The starting price amounted to RUB 16 million (USD 0.25 million). Ritek, competing against seven companies, offered RUB 1,460.8 million (USD 22.8 million). The Pervomayskiy block covers 411 sq km and encompasses the Mayevskaya prospect with hydrocarbon resources estimated at 1 MMbbl of oil, 17 Bcf of gas and 0.2 MMbbl of condensate. Hydrocarbon resources (category D1) of the block are estimated at 42 MMbbl of oil and 75 Bcf of gas. The starting price amounted to RUB 9.8 million (USD 0.15 million). Gazprom Neft offered RUB 10.78 million (USD 0.17 million). The Tsentralnyy 1 block covers 590 sq km. Hydrocarbon resources (category D1) of the block are estimated at 69 MMbbl of oil and 113 Bcf of gas. The starting price amounted to RUB 21.8 million (USD 0.34 million). Ritek, competing against five companies, offered RUB 1,007.16 million (USD 15.7 million). The Tsentralnyy 2 block covers 496 sq km. Hydrocarbon resources (category D1) of the block are estimated at 58 MMbbl of oil and 65 Bcf of gas. The starting price amounted to RUB 14.9 million (USD 0.23 million). Ritek, competing against five companies, offered RUB 458.92 million (USD 7.17 million).

Russia, not found

Lundin announced on 28 June 2017 that it had sold a 39% interest in PL 148 to Cape Omega for NOK 774 million (USD 91.5 million). PL 148 contains the Brynhild oil field which has been producing since 2014 as a subsea tie-back to the UK sector Pierce field. Confirmation of completion of the deal was given by the NPD on 1 December 2017 (the transfer takes effect from 30 November 2017). Brynhild was discovered by Statoil in 1992 and was the first Jurassic find in the area along the eastern edge of the Central Graben. A DST flowed at 5,000 b/d of 36 API oil from the Upper Jurassic Ula Formation. Appraisal well 7/7-3, drilled the following year, was intended to confirm the new geological model but brought disappointing results (only shows). Lundin took over operatorship of the licence in 2004 and drilled appraisal well 7/4-2 in 2008. The positioning of 7/4-2, 2km north of the Brynhild discovery well, aimed to prove significant upside by evaluating the OWC (not found in the discovery well) and reservoir thickness and quality. The well was successful and proved the field's commerciality. Brynhild is tied-back to the “Haewene Brim” FPSO which is located at the Shell-operated Pierce field where the oil is processed and stored before offloading to shuttle tankers. In February 2016 Lundin reported that the reserves for Brynhild had been reduced from 23 MMboe to just 7.4 MMboe. Data acquired from the producing wells showed that the connected hydrocarbon volumes were lower than previously thought. Following completion of the deal interests in PL 148 are divided between Lundin Norway AS (51% + operator) and CapeOmega AS (49%).  

Norway (Cod Terrace (Central Graben)) Ula

L33/43, onshore Phetchabun Basin, ops terminated 18 Jun ’18: WBW-10A P&A dry at TD 1,165m on 6 June, follow-on sidetrack WBW-10ST compl oil at TD 1,144m, Sinopec 9001 rig. Eco Orient (op), partners Loyz Egy + Berlanga Grp.

L33/43, onshore Phetchabun Basin, ops terminated 18 Jun ’18: WBW-10A P&A dry at TD 1,165m on 6 June, follow-on sidetrack WBW-10ST compl oil at TD 1,144m, Sinopec 9001 rig. Eco Orient (op), partners Loyz Egy + Berlanga Grp.

Thailand’s 21st round, last expected towards 2Q ’19, has reportedly slipped into 2H ’19. When first announced in 2014 the following blocks had been earmarked: Onshore: Phitsanulok Basin: L01/57, L07/57, L08/57 Mae Sot Basin: L06/57 Phetchabun Basin: L16/57A-L16/57B Chao Phraya Basin: L23/57 Khorat Plateau Basin: L02/57, L03/57, L04/57, L05/57, L09/57, L10/57, L11/57, L12/57, L13/57, L14/57, L15/57, L17/57, L18/57, L19/57, L20/57, L21/57, L22/57 Offshore: Gulf of Thailand Basin: G01/57, G02/57A-G02/57B, G03/57, G04/57, G05/57A-G05/57B Malay Basin: G06/57.

Thailand’s 21st round, last expected towards 2Q ’19, has reportedly slipped into 2H ’19. When first announced in 2014 the following blocks had been earmarked: Onshore: Phitsanulok Basin: L01/57, L07/57, L08/57 Mae Sot Basin: L06/57 Phetchabun Basin: L16/57A-L16/57B Chao Phraya Basin: L23/57 Khorat Plateau Basin: L02/57, L03/57, L04/57, L05/57, L09/57, L10/57, L11/57, L12/57, L13/57, L14/57, L15/57, L17/57, L18/57, L19/57, L20/57, L21/57, L22/57 Offshore: Gulf of Thailand Basin: G01/57, G02/57A-G02/57B, G03/57, G04/57, G05/57A-G05/57B Malay Basin: G06/57.