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Norwest Energy Ltd, through wholly owned subsidiary Westranch Holding Pty Ltd, is looking to further farm-out interest in exploration permit TP/15, located in the Perth Basin.  It is reported that Norwest is looking for a partner to assist in funding 3D seismic acquisition and appraisal work within the permit. Norwest has previously farmed out interest in the permit, with 3C Group IC Ltd, Triangle Energy Ltd, and Transerv Energy acquiring interest TP/15 in August 2017.  The companies funded the Xanadu 1 exploration well under the terms of the farm-ins, with the well drilled in September 2017. Norwest retained 25% interest and operatorship in the permit.  Further expenditure in the permit is being covered by the participants accordingly with their interest held, with Norwest now looking to additionally farm-down Alongside the farm-in agreement for TP/15, the companies formed a strategic relationship, with 3C providing technical, legal, risk and financial assistance to Norwest on the TP/15 permit and other Perth Basin assets.  Norwest and Transerv had already entered a “strategic alliance” for several of Norwest’s Perth Basin assets, including TP/15.   Share placements were made as part of the alliance.   Xanadu 1 was spudded on 4 September 2017, drilled to a total depth of 2,035 m suspended as an oil discovery, with additional analysis planned, in late September 2017. Testing and logging was run, with initial analysis indicating 34.7º API oil within the discovery, with no H2S encountered and very low levels (around 0.02%) of CO2, similar to that being produced from the nearby Cliff Head field.  Norwest reported that a 3D survey over the discovery was being planned, with also the potential for drilling a sidetrack appraisal well from the discovery well main hole. The sidetrack would appraise up-dip potential and possibly penetrate deeper, higher quality sands above the inferred oil-water contact.  If development is feasible, it is expected to be low cost and schedule efficient due to the quality of the oil from initial analysis. Post-drilling, on 25 September 2017, Norwest reported that Xanadu 1 had recovered oil from the Irwin River Coal Measures at a depth of around 871.8 m. A total net pay of 4.6 m across reservoir unit “A” was encountered with oil retrieved to the surface using a Schlumberger Saturn Probe wireline tool. Two additional sands (“B” and “C”) were also encountered, which show oil saturations ranging from 41 to 46%. Oil saturation in the “A” sand is 66% with porosity at 15%. The well’s primarily target of the Permian Dongara Sandstone was not encountered at this location. Norwest renewed TP/15 on 7 December 2018 for a period of five years, effective from 22 November 2018. Under the renewal conditions, 40 sq km of new 3D seismic data is required within the first term, followed by geophysical studies and an appraisal well to the Xanadu discovery in the third term. This three-year programme is estimated to cost AUD 6.3 million. Norwest plans to acquire the seismic in Q1 2019 over the Xanadu discovery. TP/15, which covers an area of 485 sq km, was awarded on 22 November 1996. Participants in the permit are: Westranch Holdings Pty Ltd, a wholly owned subsidiary of Norwest Energy, (25% + Operator), Triangle Xanadu Pty Ltd (30%), 3C Energy, through subsidiaries 3C Capital Pty Ltd (15%) and 3C Energy IC Ltd (15%), and Kubla Oil Pty Ltd, a Whitebark subsidiary company, (15%). In a deal reported on 15 October 2018, Whitebark shall exit the permit, transferring its 15% interest to Triangle. Companies interested in pursuing this opportunity should contact: Moyes and Co: Ian Cross, Managing Director Tel: +65 9776 0753 Email: icross@moyesco.com

Norwest Energy Ltd, through wholly owned subsidiary Westranch Holding Pty Ltd, is looking to further farm-out interest in exploration permit TP/15, located in the Perth Basin.

I3 Energy spudded its pilot well 13/23c-9 (also known as 13/23c-LPt-2) for its Phase I producer well on the Liberator development in licence P2358 on 21 August 2019. The “Borgland Dolphin” (S/S) rig was used for operations. On 10 September 2019 it was reported that the well had reached a TD of 5,818 ft (1,773 m) in the Valhall Formation. Results from the well indicate that it did not encounter the targeted Upper Captain sands and the company believes the sand pinches out at this location. The Lower Captain sands were encountered but were located below the oil-water contact as expected. I3 Energy state that from initial tie in to the seismic data the well appears to be proximal to the main Upper Captain channel fairway and further well data is required to understand the Upper Captain sands channel edge. On 20 September 2019 i3 Energy announced that the well has been plugged and abandoned following the completion of the Vertical Seismic Profile and shear wave sonic logging. I3 Energy submitted its Environmental Statement (ES) for the development of the 13/23d-8 (Liberator) discovery in October 2017. The ES is sat with the Department for Business, Environment and Industrial Strategy (BEIS) for review and public consultation. In addition the company has also submitted its Field Development Plan (FDP) to the OGA for approval. The plan is to develop the field via two single wells (L1 and L2 to be drilled in 2018), one close to an existing manifold (part of Blake) and one located two kilometres from the same manifold. Produced hydrocarbons will be combined with fluids from wells drilled on the Blake field before being processed by the Repsol Sinopec “Bleo Holm” FPSO. This is Phase I of the project. In addition, i3 Energy has signed a Memorandum of Understanding for the provision of a standalone FPSO. Liberator is an oil discovery located immediately west of the Blake field. It was discovered in 2013 and has a Lower Cretaceous Captain Sand reservoir, similar to Blake. The discovery well proved 1.5 to 2.5 Darcy reservoir with a 28% porosity containing 30.3 degrees API oil with a 1.9 cP viscosity and an established water contact that mapped a potential oil column ranging from 7 m to 24 m within an elongated four way structure at approximately 1,600 m. The discovery is located in licence P1987, covering an area of 14.5 sq km and was awarded in the 27th Offshore Licensing Round and consists of just the one block (13/23d). The licence is located immediately west of the Blake field. Interest in licence P2358 is held solely by I3 Energy Ltd.

013/23c-09 (LPt-02) (Liberator West) appr. (I3 Energy 100%) in P2358 block, P&A dry. Pilot hole , MWD suggests target U. Captain sand not intersected (pinch-out likely), although L. Captain present.WD 40m, TD=1773m (Valhall fm).

Committed well in block 05-3/11, Nam Con Son Basin, P&A results n/a 29 Jun ’18, PV Drilling VI JU. Target U. Miocene Mang Cau fm.

Vietnam, Block 05-3/11

Stabroek block, NW of the Liza field in WD ca. 1,500m, Guyana Basin, contrary to last week’s rumours this well is unsuccessful, presumably to P&A, Noble Bob Douglas DS. Exxon (op), partners Hess + COOC-Nexen.

Guyana (Guyana B.) Liza

Add. DEA 13 May '20: Dráva 2 block, NE Croatia, Somogy-Dráva sub-basin, drilled 14-30 Nov '19, TMD 1,635m (1,598m TVD, Mesozoic), shows encountered in L. Pannonian sst + M. Miocene lmst, testing planned early 3Q '20.

Jancovac-1 nfw Dráva 2 block, NE Croatia, Somogy-Dráva sub-basin, drilled 14-30 Nov '19, TMD 1,635m (1,598m TVD, Mesozoic), shows encountered in L. Pannonian sst + M. Miocene lmst, testing planned early 3Q '20.

South Disouq block, onshore Nile Delta Basin, 2nd in 4-well campaign at South Disouq, TD 2,461m,  185m of high quality reservoir in the Abu Madi target, low gas saturation and deemed non-commercial, P&A’ing, rig to SD-4X appr. SDX (op), partner IPR. www.sdxenergy.com.

Kelvin 1X (SDX op. 55%, IPR Egy 45%) in South Disouq block, encountering 185m of high quality reservoir interval in the Abu‐Madi fm, the sands had low gas saturation and were not deemed to be commercial.

PEMEX completed as an oil and gas discovery the Quesqui 1EXP new-field wildcat (NFW) in the AE-0053-3M-Mezcalapa-03 entitlement block during mid-May 2019.  The well reportedly tested approximately 800 bo/d and large volumes of natural gas from the HPHT reservoir. The NFW was spudded on 22 July 2018 and reached a final total depth (TD) of 7,047 m in May 2019. The well had a proposed total depth (PTD) of 7,526 m and the primary targets were the Cretaceous and Jurassic formations. The NFW will attempt to extend the successful deeper Jurassic plays in the area like Bricol, Chinchorro, Palangre, Pareto, and the most recent discovery Chocol in March 2017.   The drilling cost estimate was reported to be USD 24.81 million at an exchange rate of 1USD = 18.5 MXN and the completion cost is USD 5.24 million.    The NFW has prospective resources of 63 MMboe.  The prospect is located in the north-western area of the block, approximately 7.8 km northwest of the A-0168-M-Campo Jujo-Tecominoacan. The operator was granted a permit to drill the well by the CNH on 22 June 2018. SENER awarded the AE-0053-3M-Mezcalapa-03 entitlement block to Pemex 100% through Ronda 0 on 27 August 2014. The entitlement has been modified three times, the latest was 13 September 2018 whereby the area of the block was reduced from 849 to 830 sq km.

Quesqui 1EXP (Pemex 100%) in NW part of AE-0053-2M-Mezcalapa-03 block, onshore in Tabasco, compl o&g at TD=7 047m mid-May ’19 after testing ab. 800 bo/d + gas from an HPHT reservoir. Targets Cret. (npw) + Jurassic (dpw).

Bight Petroleum Corp is seeking a strategic partner to join exploration activities in the exploration permits EPP 41 and EPP 42, located in the Eastern Bight Basin. Bight Petroleum is offering significant equity and strategic entry into these permits, which have planned 3D seismic acquisition and future drilling, in return for a carry of the future activity.  The potential partner would assist with funding the 3D seismic, planned for Q4 2019. Bight Petroleum plans for PGS to acquire the seismic to de-risk the prospectivity and mature drill ready prospects. Bight opened a dataroom for the farm-out in Q2 2019, with hopes to finalise an agreement in 2H 2019.  The farminee would carry Bight Petroleum on the planned seismic with a follow up well option. The Duntroon seismic is planned to be carried out across both permits, with 2,820 sq km to be acquired.  It would be designed to acquire more data over the Price Prospect as well as define drillable targets.  Mapping and derisking of the prospects is then planned for late 2020. The Price Main Prospect is the largest prospect within EPP 41 and is estimated to contain potential in-place resources of 8 Bb, with significant multi-million barrel recoverable resource potential, across a 74 sq km closure.  It is a three-way closed trap against a bounding fault with potentially five sandstone units within the intra-Waigunda section.  The Upper Tiger and Hammerhead deltaic sequences have been outlined as primary targets, which are reported to be similar to those at Stromlo, a well being drilled to the west, within the Bight Basin. There is also the potential for stratigraphic trapping. The prospect is located in water depths of 1,900 m. Remapping conducted by Bight Petroleum, using depth conversion, 3D seismic interpretation and reprocessing has resulted in 14 explorations targets being identified on 2D seismic data, with Price the largest. It is estimated that there are around 43 Bb in place, with an estimated potential recovery of around 9 Bb of oil. Bight has reported that the 3D seismic would be aimed to de-risk the play and define drillable targets within the permits. Bight reports that the current 2D seismic data available provides poor resolution for mapping the reservoir sequences but they do appear thickly developed with minimal faulting. The permits cover a total area of around 8,500 sq km, located around 50 km south of the Eyre Peninsula in around 1,100 to 2,200 m water depth. Both permits were awarded in July 2011, for an initial period of six years. After work suspensions relating to the first terms, the permits will now expire on, or be eligible for renewal by, 7 July 2020 (EPP 41) and 7 July 2021 (EPP 42). Bight Petroleum has contracted RISC as its executive advisor in the farm-out. Companies interested in pursuing this opportunity should contact: Jens Biertumpel, CEO Tel: +41 78 810 4323 Email: jens@bightpetroleum.com  Lawrence Bernstein, Exploration VP, COO Tel: +1 403 354 2492 Email: lbernstein@bightpetroleum.com Bight Petroleum has also contracted RISC Advisory to assist in the farm-out process, so additional contact can be made via: Robbie Harrison, Director A&D Email: Robert.harrison@riscadvisory.com         Tel: +61 8 9420 6648 Dan Calder, Director A&D Email: dan.calder@riscadvisory.com                Tel: +61 8 9420 666

Bight Petroleum Corp EPP 41 and EPP 42, Bight Basin - seeking farm-in partner

An auction is planned 28 Aug ’18 for 25-yr rights to the 20.5-sq km Manasozen block, Terek-Caspian Basin in the Dagestan Republic, N. Caucasus, applications by 9 August. Starting price USD 1,400. Contact Kavkaznedra, kavkaz@rosnedra.gov.ru.

An auction is planned 28 Aug ’18 for 25-yr rights to the 20.5-sq km Manasozen block, Terek-Caspian Basin in the Dagestan Republic, N. Caucasus, applications by 9 August. Starting price USD 1,400. Contact Kavkaznedra, kavkaz@rosnedra.gov.ru.

On 27 March 2018, the CNH concluded the successful CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) for 35 shelf blocks granting preliminary awards for 16 blocks out of 35 on offer covering a total provisionally awarded area of 11,158 sq km.  Companies made a total of 36 bids, dominated by bidding for all of the Sureste Basin blocks.  Companies also bid a total of nine additional wells as commitments, again all in the Sureste Basin.  Total estimated work commitments value for the round was USD 425.42 million, and there were three tie-break bonus bids made by companies that garnered the government USD 124.05 million. PEMEX dominated Ronda 3.1 winning four blocks as operator and three blocks as a partner in various consortia.  It also placed the largest number of bids individually or in consortia with 11.  Other companies who bid aggressively and won two or more blocks were CEPSA, DEA, Pan American, Premier, Repsol, and Total.  Sapura made its entry into Mexico winning the highly contested Block 30 in the consortium with DEA and Premier.  There were four companies that placed bids but failed to win a block including ECP, Galem, Inpex, and PC Carigali. In the Burgos Basin there were four of 14 blocks in the Burgos Basin bid on and granted preliminary awards, two to Premier Oil and two to Repsol all with 100% working interest and no additional work units bid.  There was only one second bid for the Area 5 block by PEMEX but it lost its bid to Repsol who bid 56.27% state take and no additional work factor compared to the PEMEX bid of 23.89% state take and no additional work units. In the Tampico-Misantla-Veracruz Basin there were also four of 13 blocks bid on and granted preliminary awards, one to the consortium of Capricorn and Citla, two to the consortium of PEMEX, DEA, and CEPSA, and one to the consortium of PEMEX and CEPSA.  There were no additional work units bid nor second bids for any of the blocks. In the Sureste Basin eight blocks on offer were bid on and granted preliminary awards.  There were second bids for all of the blocks.  The most contested block in the round was the Area 30 block with a total of seven bids, five of the bids offering the maximum state take of 65% and tie-break bonuses.  The consortium of DEA, Premier, and Sapura won the block with a tie-break bonus of USD 51.15 million versus the second place bid by ENI and Lukoil of USD 46.87 million.  The highest tie-break bonus in the round was made by PEMEX who won the Area 28 block with a tie-break bonus of USD 59.82 million. CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) - Preliminary Results – 27 March 2018     Area Basin CNH-Block Name Area sq km Number of Bids State Participation Bid % Add Work Factor Bid - 0, 1 = 1 well, 1.5 = 2 wells Total Est Work Unit Value USD Tie-Break Bonus USD Winning Consortium or Company 2nd Bid Consortium or Company 2nd State Part % 2nd Bid  Additional Work Factor 2nd Bid Tie-Break Bonus USD 5 Burgos G-BG-05 814                           2                                      56.27                                    -                                      2,227,896    Repsol PEMEX                   23.89                          -     11 Burgos AS-B-57 391                            1                                      29.47                                    -                                        1,125,432    Premier         12 Burgos G-BG-07 811                            1                                       48.17                                    -                                       2,221,632    Repsol         13 Burgos AS-B-60 392                            1                                      34.73                                    -                                        1,127,520    Premier         15 Tampico-Misantla-Veracruz G-TMV-01 962                            1                                      27.88                                        2,614,176   Capricorn, Citla         16 Tampico-Misantla-Veracruz G-TMV-02 785                            1                                      24.23                                    -                                       2,152,728   PEMEX, DEA, CEPSA         17 Tampico-Misantla-Veracruz G-TMV-03 842                            1                                       35.51                                    -                                      2,303,064   PEMEX, DEA, CEPSA         18 Tampico-Misantla-Veracruz G-TMV-04 813                            1                                       40.51                                    -                                      2,226,852   PEMEX, CEPSA         28 Sureste G-CS-01 808                           5                                      65.00                                     2                                  89,908,236                    59,823,145  ENI, Lukoil DEA, Premier                   65.00                      1.00                  14,170,000.50 29 Sureste AS-CS-13 471                           4                                      65.00                                     2                                   89,028,144                    13,075,075  PEMEX DEA, Premier, Sapura                   65.00                      1.00                                         -   30 Sureste AS-CS-14 528                           7                                      65.00                                     2                                   89,178,480                     51,147,000 DEA, Premier, Sapura ENI, Lukoil                   65.00                      1.50                46,869,235.00 31 Sureste AS-CS-15 401                           3                                      65.00                                      1                                  44,999,532   Pan American ENI, Lukoil                   42.35                      1.00                                         -   32 Sureste G-CS-02 1,027                           2                                      40.49                                    -                                      2,785,392    Total, PEMEX Sapura, Galem                    30.16                      1.00   33 Sureste AS-CS-06 581                           2                                      50.49                                      1                                  45,468,288    Total, PEMEX ENI, Lukoil                   40.35                          -     34 Sureste G-CS-03 734                           2                                      50.49                                      1                                   45,868,140   Total, BP, Pan American Shell, PEMEX                   40.36                          -     35 Sureste G-CS-04 798                           2                                      34.86                                    -                                        2,187,180   Shell, PEMEX Total, BP, Pan American                   30.49                          -       Totals                       11,158                         36                                       9                               425,422,692                  124,045,220               Source: IHS Markit     © 2018 IHS Markit                   CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) – Preliminary, Estimated Company Results Summary until Working Interest Breakdown Officially Reported – 27 March 2018 Company NAWI Est NWI Work Units + Tie-Break Bonus USD Blocks Operator Blocks Partner Number of Bids Individually or in Consortia  PEMEX       2,633.68                                    129,952,044.28                                             4                                             3 11  ENI          404.00                                     74,865,690.50                                              1   4  Lukoil          404.00                                     74,865,690.50                                                1 4  Pan American          643.22                                       60,136,018.20                                              1                                              1 4  DEA           716.43                                       49,181,074.65                                              1                                             2 5  Premier          957.24                                     48,560,360.48                                             2                                              1 5  Sapura           174.24                                     46,307,408.48                                                1 3  Total        1,053.56                                     39,722,007.60                                             3   6  BP          242.22                                       15,136,486.20                                                1 2  Repsol        1,625.00                                        4,449,528.00                                             2   5  CEPSA           943.41                                        2,583,837.36                                               3 3  Capricorn           481.00                                         1,307,088.00                                              1   2  Citla           481.00                                         1,307,088.00                                                1 2  Shell          399.00                                         1,093,590.00                                              1   2  Grand Total       11,158.00                                    549,467,912.25                                            16                                            14   Source: IHS Markit   © 2018 IHS Markit          CNH-RO3-LO1/2017 Bid Round (Ronda 3.1) - Preliminary Results Map – 27 March 2018  

Mexico, Area 28

On 30 November 2017, Neuquen province governor, Omar Gutierrez, presided over the award of two blocks from the Neuquen Province V Ronda (New Horizons Plan) by provincial company Gas y Petroleo del Neuquen. Norwegian operator, Statoil, was awarded the 133 sq km Bajo del Toro Este Block. US Retamco subsidiary, Retama, was granted rights to the 143 sq km Parva Negra Oeste license. The Statoil offer for Bajo del Toro Este was US$ 14.89 million. It is the first presence of Statoil in the Neuquen Basin which also offered a US$ 2 million entry fee. Retama offered US$ 76.25 million for Parva Negra Oeste and a US$ 10 million entry fee. Last week Petrolera Pampa, was awarded the 120 sq km Las Tacanas Norte Block based on the round.

Argentina, Bajo del Toro

In November 2019, Genel Energy appointed Stellar Energy Advisor to run a farm-out process for the SL10B, SL13 licence. Depending on the result farm-out, the company plans to drill a well in the licence in 2020/2021. Still in November 2019, the company completed the acquisition of East Africa Resource 25% stake in the licence. The interpretation of the 2018 2D seismic data together with continued basin analysis has led to the maturation of a prospects and leads inventory for the SL10B, SL13 licence. A number of potentially high impact exploration targets have been identified within play types directly analogous to the prolific Yemeni rift basins. The SL10B, SL13 licence contains the Bur Dab 1 well, which found oil shows in 1958. Genel acquired a total of 3,150 km of speculative 2D data over the SL-10B, SL13 and neighbouring Odewayne licences. The portion over the SL-10B, SL13 was completed in January 2018, while the portion over the Odewayne block was completed in October 2017. The acquisition started in March 2017 and was conducted by the contractor BGP Inc. The survey was part of a Somaliland-owned speculative 2D seismic project. Genel purchased the seismic data covering its onshore acreage, which fulfilled its minimum work obligations. A surface oil seep study completed in 2015 supposedly confirmed the presence of a working hydrocarbon system with Late Jurassic source rocks and several potential reservoir/seal pairs. Genel believes that all its acreage in Somaliland could host over 2 Bbbl of oil. Interest in the SL10B, SL13 licence is held solely by Genel Energy plc. The Republic of Somaliland is bordered by Ethiopia in the south and west and it is located in northern Somalia. Somaliland remains internationally unrecognized but is considered economically stable and democratic. Somaliland declared independence from Somalia in 1991. For further information, please contact: Stellar Energy Advisors Dave Fassom Tom Perkins +44 20 7493 1977 Genel Energy Andrew Benbow, Head of Communications +44 20 7659 5100

Genel Energy appointed Stellar Energy Advisor to run a farm-out process for the SL10B, SL13 licence. Depending on the result farm-out, the company plans to drill a well in the licence in 2020/2021.

On 6 February 2018, Aminex plc reported a resources upgrade for the Ntorya gas field, in the Ruvuma PSA following the completion of a competent Person’s Report (CPR). Pmean GIIP increased from 1.3 Tcf (reported in September 2017) to 1.87 Tcf. Ntorya 2C gross contingent resources increased to 762.8 Bcf. In April 2017, after the successful drilling of Ntorya 2 in March 2017, the company increased the Pmean GIIP from 153 Bcf to 466 Bcf. P90 GIIP was increased from 31 Bcf to 62 Bcf while the P10 GIIP was increased from 332 Bcf to 1.13 Tcf. Aminex operates the Ruvuma PSA, located onshore and offshore in the Ruvuma Basin, southern Tanzania. It comprises three main blocks, Lindi License (Ruvuma Exploration Area), Mtwara Exploration Licence and the Ntorya Appraisal License, which total 3,447 sq km. The current interests in the Ruvuma PSA are shared between Aminex plc (through its subsidiary Ndovu Resources Ltd), operator with 75% interests, and Solo Oil with 25%. Aminex applied for a development lease for the Ntorya Appraisal License and was working with io oil and gas consultancy to prepare a gas commercialisation plan. According to io, a gas development project with three wells for Ntorya could be viable.

Tanzania (Ruvuma B.) ? op. by AMINEX (75.0%, SOLO OIL 25.0%) in Mtwara block

ConocoPhillips is looking to sell-out of WL4-00, 2,530 sq km in shallow waters off Sarawak, in which it holds 50% + operatorship. The balance is held by Petronas. Commitments fulfilled.

ConocoPhillips is looking to sell-out of WL4-00, 2,530 sq km in shallow waters off Sarawak, in which it holds 50% + operatorship. The balance is held by Petronas. Commitments fulfilled.

According to reports in early-December 2018, Formosa Province government has assigned operatorship and 100% holding interest of the Palmar Largo block in the Noroeste Basin to Madalena Energy. Investment commitment was reported to be USD 2 million for workovers in two wells within the next two years, with the possibility of a one year extension. The Palmar Largo block covers 217 sq km of land in the Pirity Sub-basin part of the Noroeste Basin, on the border between the provinces of Formosa and Salta. The company is already the operator in two adjacent blocks, El Chivil and Surubi, on the Formosa Province side. Madalena previously held 14% non-operating equity in the block, joining partners Cia General de Combustibles (CGC) with 17.85%, state company YPF with 30%, and High Luck Group (subsidiary of Hong Kong firm New Times Energy) as the operator with 38.15% stake. The area was transferred to the provincial oil and gas company of Formosa, REFSA, in November 2018, following the expiration of the concession in December 2017.    Background Information Fields in Palmar Largo block have produced over 48.3 MMbo and 44.4 Bscfg as of October 2018, primarily from Yacoraite (Maastrichtian-Palecene) limestone and calcareous sands, and Palmar Largo fractured Volcanics (Campanian) reservoirs.

Formosa Province government has assigned operatorship and 100% holding interest of the Palmar Largo (217km²) block to Madalena Energy.

ATP 1189-P, Cooper-Eromanga, drilled + suspended gas at TD 2,422m between 3-12 Jan '20. Santos (op), partner Beach.

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

Tando Allah Yar EL, Lower Indus onshore, suspended at TD 3,809m mid-Dec '19, tested, co. N-2 rig. Target assumed Lower Goru.

Dhamach 1 nfw. (OGDCL 95% op. GHPL 5%) in Tando Allah Yar 2568-8 EL onshore block, suspended at TD=3809m, tested, Target assumed Lower Goru. Results unreported yet.

Santos Ltd suspended the Brompton 1 gas exploration well in PPL 116, located in the Cooper-Eromanga Basin, on 11 August 2020 after reaching a total depth of 3,006 m. The well was spudded on 25 July 2020 and was drilled by the Ensign "967" land rig, fresh from making a gas discovery at Inglewood 1, also in PPL 116. The result of Brompton 1 is yet to be reported. The well is located 4.3 km northeast of Inglewood 1 which was suspended as a gas discovery on 23 July 2020. Proximal fields include the producing Beckler, Bow, Crowsnest and Dullingari fields and the abandoned Nappacoongee East field, all of which are operated by Santos and have produced from the Permian stratigraphy. The Dullingari and Nappacoongee East fields have also produced from the younger stratigraphy, principally the Cretaceous Murta Formation. Should Brompton 1 be a discovery, a potential commercialisation avenue would include a buried gas pipeline connection to the Crowsnest - Beckler pipeline to the southeast. PPL 116, which covers an area of 182 sq km, was awarded on 1 November 1997. Participants in the permit are, through various subsidiaries, Santos Ltd (66.6% plus operatorship) and Beach Energy Ltd (33.4%).

(Eromanga B.) Brompton 1 in PPL 116 op. by SANTOS (67%), BEACH (33%) suspended at 3,006 m. Results n/a.

Alamein-Yidma devt lease, N. Egypt Basin, drilled and P&A 30 Jun – late Jul ’18, TD 2,135m (Khoman fm), IPR rig 1. El Hamra = EGPC, IPR-Transoil + Sojitz JV.

Alamein-Yidma devt lease, N. Egypt Basin, drilled and P&A 30 Jun – late Jul ’18, TD 2,135m (Khoman fm), IPR rig 1. El Hamra = EGPC, IPR-Transoil + Sojitz JV.

Aker BP and Shell have completed a swap deal whereby Aker BP has acquired a 10% interest in PL 1056 and Shell has acquired 20% in PL 1005. PL 1056 covers an area of 4,549 sq km over blocks 6302/1 to 6302/12 in the deepwater More Basin to the west of Ormen Lange. It contains the 2005 Tulipan gas discovery. PL 1005 covers 1,775 sq km over blocks 6404/9, 6404/12, 6405/4, 6405/7 and 6405/10 and contains the 2003 Ellida oil discovery. It is located north of Ormen Lange in the deepwater Voring Basin. The deal was confirmed by the NPD on 10 July 2020 and is effective from 30 June 2020. Statoil (now Equinor) drilled Tulipan well 6302/6-1 and confirmed gas in the Paleocene Rogaland Group at around 3,900 m below a very thick Quarternary (Naust Formation) North Sea Fan. The find was small and the well was not tested. Ellida well 6405/7-1, also operated by Statoil, proved oil in the Upper Cretaceous Nise Formation between 2,760 m and 2,823 m, with good oil shows below this depth. However, reservoir quality was generally poor and on test the well flowed only 252 b/d of 31°API oil. Following completion of the deal, interest in PL 1005 is divided between Aker BP ASA (40% + operator), Var Energi AS (40%) and A/S Norske Shell (20%) and interest in PL 1056 is held by A/S Norske Shell (30% + operator), Petoro AS (20%), DNO Norge AS (20%), Wintershall Dea Norge AS (20%) and Aker BP ASA (10%).

Norway (More B.), PL 1056, Aker BP has acquired a 10% stake in PL 1056, 4,549 sq km in the More Basin (blocks 6302/1 + 12, Tulipan discovery), in exchange for Shell getting 20% in PL 1005, 1,775 sq km over blocks 6404/9 + 12, 6405/4, 7 + 10 (Ellida discovery) in the deepwater Voring Basin. The deal is effective 30 Jun '20. PL 1005 partners now Aker BP (op), VÃ¥r + Shell and PL 1056 Shell (op), Petoro, DNO, Wintershall Dea + Aker BP.

During a visit to China in mid-September 2018 Venezuela’s President Nicolas Maduro signed with China a total of twenty-eight agreements, including a memorandum for the sale of 9.9% of the Sinovensa Joint Venture - Sinovensa Block. More details have not been released. The Venezuelan National Assembly approved on 18 January 2008, the constitution of the mixed company Sinovensa in the Sinovensa Orimulsion plant area including an extension of MPE 3 Block in the Orinoco Oil Belt, comprised of CVP with 60% working interest and partner CNPC the remaining 40%. PDVSA announced on 25 September 2017 that will work with CNPC to reactivate 300 wells in the Faja Petrolifera del Orinoco and rehabilitate 500 wells in the Distrito San Tome. It is expected that the project will add 200,000 bo/d to Venezuela’s production. PDVSA announced in late August 2017 China’s interest in participating in the reactivation of 800 wells in the Faja Petrolifera del Orinoco and increase the production by 42 Mbo/d. More details as to when the program will start have not been released. Back in June 2017 the governments of Venezuela and China signed an agreement to increase production and improve infrastructure in Venezuela- with USD 4.25 billion investment. A total of USD 2.8 billion would go to JV’s Petrozumano and Sinovensa, to increase production by 325 Mbo/d, and the remaining USD 1.45 billion would go to Araya Deep Water Port in the Sucre State. Venezuela’s President Nicolas Maduro met with China National Petroleum Corporation (CNPC) Chairman Wang Yilin in Caracas on 17 November 2016. Witnessed by President Maduro, Chairman Yilin and PDVSA’s President and Oil Minister Eulogio Del Pino Venezuela signed a Memorandum of Understanding (MOU) deepening oil and gas cooperation between CNCP and PDVSA.  Under the MOU, the companies plan to increase production in the mixed companies:  Petrozumano, S.A. to 15 Mbd with an investment of USD 225 million, PetroUrica JV to 30 Mbd, utilizing recovery technology with an estimated investment of USD 500 million, develop a pilot project in the Sinovensa mixed company to increase production from 160 Mbd to 230 Mbd of extra-heavy crude by expanding storage, transport and processing capacity in the Complejo Jose Antonio Anzoategui. The companies also plans to rehabilitate 500 light crude wells and will develop the joint venture (JV) for the Jie Yang Refinery, located in China, in which PDVSA has 40% interest and CNPC holds 60%.

Venezuela Government of Venezuela Signed a memorandum with China for the sale of 9.9% Sinovensa JV - East Venezuela Basin

On 1 December 2017, Chevron USA was formally awarded Green Canyon Block GC 508 (lease G36160), located in the East Texas Coastal Basin. GC 508 was originally offered as part of Western Gulf of Mexico Lease Sale 249, which was held on 16 August 2017. The lease is expected to expire on 30 September 2024. Following official award, Chevron USA is now the operator and sole interest-holder (100% WI + Op) in GC 508.

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Serica Energy plc announced that it has agreed a further deal for the Bruce and Keith fields in the North Sea with Total. Under the deal, Serica will acquire a further 42.25% interest in the Bruce field and a further 25% interest in the Keith field. Initial consideration for the interests is USD 5 million payable on deal completion then a deferred consideration of USD 15 million to be paid in three USD 5 million instalments, payable every 8 months following completion of the acquisition and subject to continued production from the nearby Rhum field. Total will retain a 1% interest in the assets. This deal follows the announcement from BP in November 2017 in which it agreed to sell 36% interest in the Bruce field, 34.84% interest in the Keith field and 50% interest in the Rhum field to Serica. Under the terms of that deal Serica will pay an initial consideration of GBP 12.8 million along with a share of cash flows over the next four years, a consideration equivalent to 30% of BP’s post-tax decommissioning costs and several contingent payments of future asset performance and product prices. BP expects to receive an overall payment in the region of GBP 300 million. In addition to the interest approximately 110 staff working for BP on the Bruce assets are also expected to make the transition to Serica. BP is to retain a 1% interest in Bruce to oversee its future operational and financial performance. In an update on 22 May 2018 Serica confirmed that amidst the decision by the US Government to withdraw from the Joint Comprehensive Plan of Action (JCPOA) and reintroduce US Sanctions on Iran, the company remains committed to complete the deal with BP which is partnered by the Iranian Oil Company (U.K) Limited in the Rhum field.  On 1 October 2018 Serica announced that the deal is still pending. Further to US’ withdrawal from the JCPOA certain services are currently provided under authorisations obtained from the US Office of Foreign Assets Control (OFAC) related to the Rhum field. The current OFAC licence which was issued to BP enable the provision of goods, services and support by certain US persons expired on 30 September 2018. Serica and BP submitted applications to renew the licence. On 1 October 2018 Serica announced that the licence has been renewed until 4 November 2018. Bruce is a middle Jurassic gas, condensate, oil field discovered in 1974 by Hamilton Brothers Oil Co with well 9/8-1. It is a complex structure comprising three reservoirs - Bruce sandstone (oil and gas condensate), Statfjord sandstone (oil and gas condensate), and Turonian limestone (gas condensate). Appraisal drilling was largely unsuccessful until 1981. The field was not developed until 1990 and was developed using two bridge-linked platforms D and PUQ. It was brought onstream on 19 May 1993. During Phase II of the Bruce development a third platform was added to accommodate additional gas compression facilities. This CR platform, is bridge linked to the two original Bruce Field Platforms. Improved recovery commenced in 1997 with produced water being re-injected into the reservoir. The Keith field was discovered initially in 1983 by well 9/8a-8 which was drilled as a Bruce outpost. The field was not brought onstream until 2000. It has been developed as tie-back to Bruce. The Rhum field was discovered in 1977 with well 3/29-2 by a Joint Operating Agreement between BP and Iranian Oil. It was not initially developed due to the HP/HT nature of the reservoir. In 2002 the field development plan was submitted to the then Department of Trade and Industry. It was developed as a subsea tie-back to the Bruce field with two production wells and the completion of an appraisal well. Production commenced in 2005. Following completion of the deal, interest in Bruce (lying in licences P90, P209 and P276) will be held by Serica Energy plc (78.25% + operator), BHP Billiton Petroleum Great Britain Limited (16%), Marubeni Oil and Gas (U.K.) Limited (3.75%), Total E&P UK Ltd (1%) and BP Exploration and Operating Company (1%). Interest in Keith (P209) will be held by Serica Energy plc (58.84% + operator), BHP Billiton Petroleum Great Britain Limited (31.83%), Marubeni Oil and Gas (U.K.) Limited (8.33%) and Total E&P UK Ltd (1%). Interest in Rhum (P198, P566 and P975) will be held by Serica Energy plc (50% + operator) and Iranian Oil Company (U.K.) Limited (50%).

Serica Energy plc announced that it has agreed a further deal for the Bruce and Keith fields in the North Sea with Total. Under the deal, Serica will acquire a further 42.25% interest in the Bruce field and a further 25% interest in the Keith field.

Rumours are rife that Pemex would be keen to take over the Zama discovery from Talos, a substantial oil find made 2 years ago in the offshore Sureste Basin and the 1st by a foreign company since the oil sector was nationalised decades ago. The move is amidst President Obrador's keenness to return more control of Mexico's energy sector to Pemex, but also comes as a Talos request for a 2-year extension to its rights was approved by the CNH. Zama lies in CNH-RO1-LO1-A7/2015, in which Talos could also explore the Xlapak or Pok-A-Tok prospects in partnership with Wintershall Dea + Premier. Pemex runs adjacent AE-0005-2M-Amoca-Yaxche-03, in which Zama is thought to extend (yet to be proven). Of note, zama is the Maya word for dawn.

Rumours are rife that Pemex would be keen to take over the Zama discovery from Talos, a substantial oil find made 2 years ago in the offshore Sureste Basin and the 1st by a foreign company since the oil sector was nationalised decades ago. The move is amidst President Obrador's keenness to return more control of Mexico's energy sector to Pemex, but also comes as a Talos request for a 2-year extension to its rights was approved by the CNH. Zama lies in CNH-RO1-LO1-A7/2015, in which Talos could also explore the Xlapak or Pok-A-Tok prospects in partnership with Wintershall Dea + Premier. Pemex runs adjacent AE-0005-2M-Amoca-Yaxche-03, in which Zama is thought to extend (yet to be proven). Of note, zama is the Maya word for dawn.

In early-July 2019, local sources reported that state company YPF has reached a total depth (TD) of 1,353 m (4,439 ft) on its Cerro Guadal (2019) 4 new-field wildcat (NFW) on the Chachahuen Sur exploration block in late-May 2019. The well was spudded earlier in the same month with objective in the Lower Centenario Formation. YPF has a 70% operating interest in the block, and partners Phoenix Global Resources and Mendoza Province’s oil and gas company EMESA hold 20% and 10%, respectively. Chachahuen Sur exploration block covers 460 sq km of land in Northeast Platform area of Neuquen Basin. The block is part of a larger Chachahuen block (1,597 sq km), along with Chachahuen Norte and Chachahuen Centro. YPF recently submitted a request for validity extension for the entire Chachahuen block in late-2018, according to official reports. Background Information The Chachahuen block area has been reduced and divided into 3 blocks in late-2015. A two-and-a-half-year extension has been granted for the Chachahuen Sur exploration area with commitments to acquire of 478 sqkm of 3D seismic and drill four exploratory wells. For the Chachahuen Norte area, a three-year evaluation period has been granted with the commitments to complete one previously drilled well, drill one stratigraphic well targeting the Neuquen group, implement a two well pilot project to test productivity, and delineation of ten shallow well drilling program. While for the Chachahuen Centro area, two-year extension has been granted with the commitments to acquire 267 km of 2D seismic and drill one exploratory well.

Cerro Guadal (2019) 4 NFW, Chachahuen Sur exploration has reached a total depth (TD) of 1,353 m (4,439 ft) on its Cerro Guadal (2019) 4 new-field wildcat (NFW) on the Chachahuen Sur exploration block in late-May 2019.

On 13 December 2017, Energean Oil and Gas SA announced that it had been awarded five offshore exploration licences following Israel’s 1st Offshore Licensing Round. The licences, which comprise blocks 12, 21, 22, 23 and 31, are located close to Energean’s Karish and Tanin gas fields. The initial exploration period will be three years. The licences were awarded by the Petroleum Commissioner following a recommendation from the Petroleum Council. Israel’s 1st Offshore Licensing Round closed on 16 November 2017. Bids were received from Energean and a consortium of Indian companies including ONGC Videsh Ltd, Bharat PetroResources Ltd, Indian Oil Corporation Ltd and Oil India Ltd. The Israeli Government was offering 24 blocks in the Levantine Basin, East Mediterranean, with a maximum size of 400 sq km and in water depths of between 1,500 and 1,800 m. A further licensing round is expected to be launched in 2018.  

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

PEP 57075, offshore Taranaki Basin, WD 135m, TD'd 17 Dec '19, COSL Prospector SS. 1st in 4-well programme also involving Tawhaki-1 (committed in PEP 50119, Gt Sth Bsn), Toutouwai-1 (PEP 60093) + Cascade-1 (PEP 51906) in the Taranaki. OMV (op), partner SapuraOMV.

Gladstone 1 explo. (OMV 70% op, SapuraOMV 30%) in PEP 57075, WD=135m, TD'd 17 Dec '19, 1st in 4-well programme, results n/a yet. Gladstone prospect is a combination trap at the Middle Miocene level where a sand filled channel/turbidite complex is interpreted to be enclosed by mudstones and shales of the deep marine Manganui Fm.

BP indicated in late April 2020 that it has agreed to revise the terms of the supermajor's Alaskan asset portfolio sale to Hilcorp Energy. The total consideration of US$ 5.6 billion will remain the same, however the deal structure and payment phasing will be altered to take into consideration the present oil market downturn. Commenting on the sale revision, BP said "The revised agreement adjusts the structure and phasing of the remaining consideration to include lower completion payments in 2020, new cash flow sharing arrangements over the near term, interest-bearing vendor financing and, potentially, an increase in the proportion of the consideration subject to earn-out arrangements." In late August 2019, BP entered into an agreement to divest its Alaskan asset portfolio to Hilcorp Energy. BP’s divestment of its Alaskan assets is part of the company’s plan to raise US$ 10 billion over the next two years, following its acquisition of BHP’s US shale assets in 2018. BP’s current Alaskan portfolio encompasses some 178 ADLs, all located in the North Slope region, and includes equity stakes in Prudhoe Bay, Point Thomson, as well as the 1,300km Trans Alaska Pipeline System (TAPS). BP has been active in Alaska for more than 60 years, including at the Prudhoe Bay oilfield, which is the most prolific oil field in US history, having produced over 13 Bbo, with forecasts suggesting that it has the potential to produce more than one billion further barrels.

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Senex Energy Ltd is looking for a farm-in partner in permit PEL 639, located in the Cooper-Eromanga Basin.  Senex holds 100% interest in the exploration permit, which was awarded in April 2018. Senex reports that the Namur Formation is the primary target within the licence area, with the Patchawarra forming the source for potential hydrocarbons.  Frey 1 is the primary prospect within the permit and is thought to be analogous to the Bauer field. Senex is looking for a partner in the licence, which covers an area of 627.45 sq km.  It is one of several licences and applications in which Senex is looking for a farm-in partner. Parties interested in pursuing the opportunity should contacts Tel: +61 7 3335 9000 Email: info@senexenergy.com.au

Australia (Warburton - Cooper - Eromanga B.s) Namur

PL 486, 88 sq km of prod. rights in the Bowen-Surat Basin, was awarded to CH4 on 21 Dec ’18 for 30 years.

CH4 was awarded rights to PL 486 (88km²).

DNO announced on 15 November 2019 the issuance of a notice of discovery to the Kurdistan Regional Government (KRG) of Iraq, regarding the company's second exploration well on the Baeshiqa Block (Zagros Foldbelt). The notice was issued in accordance with the requirements of the Production Sharing Contract (PSC) after the Baeshiqa 2 NFW flowed hydrocarbons to surface from the upper part of the Triassic Kurra Chine B reservoir.<P />The Baeshiqa 2 NFW was spudded in February 2019 and reached a TD of 3,204m (2,549m TVDSS) by July 2019. It was subsequently suspended, with rigless testing understood to have commenced in late August 2019. Following acid stimulation, the upper part of Triassic Kurra Chine B reservoir flowed variable rates of light oil and sour gas. Further testing of this and other Jurassic and Triassic zones is ongoing and will determine the next steps towards appraisal and assessment of commerciality.<P />The well forms part of a three-well, exploration drilling programme on the Baeshiqa Block, which will target two large undrilled structures. The structures are expected to have multiple independent stacked reservoir systems in the Cretaceous, Jurassic and Triassic. Baeshiqa 2 follows the Baeshiqa 1 NFW, which targeted a shallower Cretaceous horizon. It is located on the same structure and targeted deeper Jurassic and Triassic formations. Baeshiqa 1 will be tested once testing on Baeshiqa 2 has been completed. The third well of the campaign, Zartik 1, will be drilled in early 2020 to evaluate a separate structure, with targets also in the Jurassic and Triassic.<P />DNO completed the farm-in to the Baeshiqa licence in April 2018, following government and partner approvals. The company announced on 8 September 2017 that it had signed an agreement with ExxonMobil by which it would join the Baeshiqa exploration licence. DNO assumed operatorship of the licence with a 32% interest, acquiring half of ExxonMobil's original stake. ExxonMobil retained a 32% interest, with the Turkish Energy Co (TEC) and the Kurdistan Regional Government (KRG) holding the remaining 16% and 20% (carried) interest respectively. <P />The Baeshiqa exploration licence (324 sq km) is located around 50 km south of DNO's existing Tawke licence, which is currently producing around 120,000 bo/d. ExxonMobil had previously conducted extensive geological and geophysical studies and constructed a drilling pad, before work was interrupted due to deteriorating security conditions.

Iraq, Baeshiqa

Ecuadors 2nd Intracampos round, now due to open June 2020, will feature 6 blocks (yet-unrevealed). 20-year concessions will apply, under participation or production-sharing contracts. Another round is planned in the Southeast, 'Ronda Suroriente', too early for details.

Ecuadors 2nd Intracampos round, now due to open June 2020, will feature 6 blocks (yet-unrevealed). 20-year concessions will apply, under participation or production-sharing contracts. Another round is planned in the Southeast, 'Ronda Suroriente', too early for details

Kina Petroleum Corp is offering an opportunity for a farm-in partner to acquire equity in its wholly owned exploration licence PPL 340, located in the onshore Papuan Basin. Kina first considered the offer in 2013, estimating approximately 35% interest would be available. Farm-in conditions and equity level were assessed post processing and interpreted of aeromagnetic and gravity survey data (acquired in 2013/14) which provided more information on the mid-Miocene reef units present within the licence. Kina has reported that an exploration well in the permit would likely first test the Port Moresby Prospect once newly acquired seismic data further defines the prospect. The Port Moresby Prospect lies in the south-west of the permit and is a platform carbonate shelf target which has been identified as an aerogravity high.  If hydrocarbons are present, it is estimated that prospective resources could be in the region of 660 Bcf gas (best estimate). However, required seismic in PPL 340 would be in the order of USD 30,000 / km, making delineation of large area closure prospects uneconomical. In 2H 2018 Kina carried out a soil gas geochemical survey over the Lizard Prospect, located in the northwest of the permit. The survey was designed to provide an economic method of better defining the prospect. Kina is now planning a second phase of sampling in August 2019 to confirm the initial results before possibly running a seismic survey to confirm structural closure. Lizard is a shallow structure at approximately 650 m depth within the Upper Miocene. Kina understands that the Plio-Pliocene uplift and tilting caused regional drainage to the east, into Lizard. In March 2017 the licence was renewed for a further five years and it will now expire, or be eligible for further renewal, on 31 March 2022.  Kina is planning to undertake further gravity/gradiometry surveying and seismic acquisition in the first four years of validity, before a possible well between March 2021 and March 2022. A standalone seismic survey has been considered too expensive by Kina in relation to the risk weighted analysis of the Lizard Prospect. In a previous farm in offer with Hunt Energy in 2013, Hunt agreed to fund a work programme, including an aeromagnetic and gravity survey and 2D seismic acquisition, based on the results of the aeromagnetic survey. On November 2013 Kina reported that the farm-out agreement had been terminated prior to seismic acquisition and the option to drill an exploration well for Hunt to acquire additional interest. Since the termination of the agreement, Kina has removed the commitment to drill an exploration well within the current licence validity period. PPL 340 covers an area of 4,320 sq km across five blocks and was awarded in 2010.  Kina Petroleum Corp currently holds 100% interest and operatorship of the licence. A five-year licence extension has been submitted which was approved in early 2017. Companies interested in pursuing this opportunity should contact: Richard Schroder – Kina MD Email: richard.schroder@kinapetroleum.com

Kina Petroleum Corp is offering an opportunity for a farm-in partner to acquire equity in its wholly owned exploration licence PPL 340, located in the onshore Papuan Basin. Kina first considered the offer in 2013, estimating approximately 35% interest would be available

KrisEnergy is looking for cash offers for all or part of its stakes in the Bulu PSC, located in offshore East Java, as of April 2018. The block includes the developing Lengo gas field. KrisEnergy holds a 42.5% operating interest in the block, partnered by HyOil Pte Ltd (42.5%, pending government approval of interest transfer from AWE), PT Satria Energindo (10%) and PT Satria Wijaya Kusuma (5%). AWE Ltd agreed to transfer its 42.5% interest in the block to Singapore-based HyOil in May 2016. The Plan of Development for Lengo was officially approved in 2014 and FEED works were carried out in 2015. As of end-December 2016, GSA negotiations with potential buyers were ongoing. An MoU for gas sales is in place with Pertagas. The field is estimated to contain 2P reserves of approximately 260 Bcfg. The field development concept involves an unmanned wellhead platform with four to five development wells, a gas export pipeline (approximately 65 km offshore plus 7.8 km onshore) and an onshore receiving facility equipped with separation, dehydration and metering systems. Plateau production rate is expected to be 70 MMcfg/g. The operator launched a pre-qualification tender for the facilities in early 2016. For further information, interested parties may contact: Mike Whibley VP Technical mike.whibley@krisenergy.com Dr. Gadjah E. Pireno Vice President Exploration and New Ventures Gadjah.pireno@krisenergy.com Background Information The Lengo 1 well was spudded on 8 March 2008 and was plugged and abandoned at a TD of 986 m on 7 April 2008. The well flowed 12.8 MMscf/d with gas (having less than 15% CO2) present over a 42 m interval in both the Upper Oligocene/Lower Miocene Kujung I carbonate unit and Middle Miocene Ngrayong sandstones. The Lengo East 1 wildcat was plugged and abandoned in mid-June 2010 with the well encountering gas. The well, located 20 km east of the Lengo 1 discovery in the adjacent Bulu PSC, was spudded on 28 May 2010 using Transocean's "Trident IX" J/U rig and was drilled to a TD of 872 m, shallower than the PTD of approximately 1,000 m. It targeted the Oligocene to Lower Miocene Kujung carbonates and the Middle Miocene Ngrayong sandstones. Partner AWE Limited elected not to participate in this drilling campaign and then-operator Pearl drilled this as a “sole risk” well. KrisEnergy announced the completion of the Lengo 2 appraisal well on 17 May 2013, with the well drilled to TD at 838 m. Two DSTs have been conducted over the main Kujung I carbonate reservoir. The first DST, between 736 m and 757m, flowed 4.8 MMscf/d of gas with a flowing wellhead pressure of 587 psig. The second DST, between 736 and 784 m, flowed 21 MMscf/d of gas with a flowing wellhead pressure of 487 psig, with the flow rate constrained by surface equipment. Approximately 42 m of core have also been collected from the reservoir interval. According to the operator, the good test results showed that the Kujung I reservoir is better developed in Lengo 2 than in discovery well Lengo 1. Following the successful drilling of appraisal well Lengo 2 in May 2013, KrisEnergy’s best estimate 2C resource estimate for the Bulu PSC increased by 58%, to 25.4 MMboe net (based on KrisEnergy’s 42.5% working interest) or 59.8 MMboe gross (on a 100% working interest basis). The Lengo POD was submitted to SKK Migas in July 2014. KrisEnergy reported in August 2014 that it had signed a memorandum of understanding with a potential buyer of gas from the field.

Indonesia (South Sumatra B.) Bulu

During early-October 2019, Equinor Brasil Energia Ltda concluded operations on the Guanxuma B T2 (1-STAT-010C-SPS) outpost side-track in the BM-S-008 contract and suspended the well with oil shows again. It is assumed the partners conducted testing operations with results so far unreported. The rig is leaving Brazil. In mid-August 2019, the SeaDrill “West Saturn” D/S returned to the location to conduct the operations. On 8 September 2018, Equinor Brasil Energia Ltda suspended with results unreported the Guanxuma B T2 (1-STAT-010C-SPS) as the second side-track wellbore of the Guanxuma prospect in the BM-S-008 contract evaluation area.The final total depth reported for the well was 6,484 m measured depth (MD).The operator filed no oil and gas show reports for the wellbore with the ANP through late-September 2018. Press reports indicated that the intention of the wellbore was to core the reservoir interval and that the operator may return to conduct a DST and/or drill another outpost well. The well was spudded on 10 August 2018.The operator suspended with oil shows the Guanuxma A (1-STAT-010A-SPS) and suspended with results unreported the Guanxuma B (1-STAT-010B-SPS) side-track wellbore prior to spudding the Guanxuma B T2 (1-STAT-010C-SPS) side-track wellbore at the same surface location and it is speculated the well is a directional geological side-track. The wellbore had a proposed total depth (PTD) of 6,630 m and will target the pre-salt Early Cretaceous Barra Velha and Itapema formations. The operator utilized the SeaDrill “West Saturn” D/S to drill the well. Equinor Brasil Energia Ltda concluded operations on the Guanxuma B (1-STAT-010B-SPS) side-track wellbore in the BM-S-008 contract evaluation area and is assumed to have suspended the well with results unreported on about 9 August 2018 prior to the spudding of the 2nd side-track wellbore from the same surface location. There were no show reports filed to date with the ANP. On 10 January 2018, Equinor Brasil Energia Ltda was granted a drilling permit to drill the Guanxuma and other prospects and appraisal wells in the BM-S-008 contract evaluation area by environmental authority IBAMA. The rig first conducted a cased hole formation test of the 3-SPS-104DA (3-BRSA-1216DA-SPS) outpost and prior to moving to the Guanxuma prospect. The Carcara prospect area is to be unitized with the Norte de Carcara block that Statoil and partners acquired through the 2nd PSC Pre-Salt Bid Round. The Guanxuma NFW is located approximately 31 km southwest of the Carcara discovery in the southwestern area of the block. The structure has at least two culminations and Statoil will test the northwestern area of the structure with an appraisal well. Two additional appraisal wells are planned for the structure if it is productive, one offsetting the Guanxuma 1 prospect and the other offsetting the Guanxuma NW prospect. Former operator Petrobras had plans to drill the well for several years. Equinor Brasil Energia Ltda has a blanket permit to drill a total of seven wells, two new-field wildcats (NFW), and five appraisal wells.Additionally, the permit covers conducting a formation test of the 3-SPS-104DA (3-BRSA-1216DA-SPS) outpost that is part of the discovery evaluation plan (PAD) commitments.The two NFWs include the Guanxuma prospect and a new prospect, the Urtiga prospect. The appraisal wells include the Carcara NW that is located to the northeast of the 3-SPS-104DA outpost and there will be three appraisal wells on the Guanxuma structure if found productive and one appraisal scheduled for the Urtiga structure if productive. The original provisional schedule was for the operator to commence drilling the first well in 3rd quarter 2017, the testing of the 3-SPS-104DA outpost and drilling of two wells in 2018, the drilling of two wells in 2019, and the final two wells in 2020 that may extend into 2021.The timing of the drilling changed with the operator waiting to bid on the Carcara Norte block in the 2nd Pre-Salt Bid Round, and the entry of new partner Exxon Mobil. The Urtiga prospect is located approximately 23 km west of the Carcara structure and is a new prospect developed by the operator. The operator plans for one southeastern appraisal if the structure is productive. Current working interest breakdown in the contract is Equinor Brasil operator with 40% working interest, Exxon Mobil with 40% working interest, and Petrogal Brasil Ltd (Galp Energia) with a 20% working interest pending formal approvals for the 10% Barra working interest acquisition. On 4 July 2018, Equinor issued a press release indicating it signed an agreement to acquire the 10% working interest in the BM-S-008 contract, Carcara discovery evaluation area held by Barra Energia for USD 379 million pending formal governmental approvals.Once formal approvals are granted, the operator will then sell and assign 6.5% of the 10% to partners ExxonMobil and Petrogal in order to equalize working interest in the BM-S-008 contract and contiguous PSC contract Norte de Carcara block.The Barra working interest represents the last piece of the puzzle here for Equinor to move forward with development of the unitized Carcara discovery development which it hopes to bring on-stream by 2023 to 2024. It reported that total estimated recoverable reserves are 2 Bboe. On 31 January 2018, the consortium of Statoil operator with 40% working interest, ExxonMobil with 40%, and Petrogal with 20% was granted an official award for the Norte de Carcara block from the 2nd PSC Pre-Salt Bid Round. The PSC contract has a three-year exploration-evaluation phase and the minimum work program is to drill one appraisal well. On 28 November 2017, the ANP officially approved of the 10% working interest acquisition by Statoil from Queiroz Galvao in the BM-S-008 contract Carcara discovery evaluation area.The total transaction value was USD 379 million.Statoil paid Queiroz Galvao 50% or USD 189.5 million with the formal governmental approvals and the remaining 50% when certain conditions are met such as unitization with the Norte de Carcara block that Statoil and partners won in the 2nd PSC Pre-Salt Bid Round. The conclusion of the unitization process likely a year or two in the future. The resulting working interest breakdown in the BM-S-008 contract with the formal governmental approval is Statoil operator with 76% working interest, Petrogal Brasil Ltd (Galp Energia) with a 14% working interest, and Barra Energia with a 10% working interest. Also ExxonMobil farmed-in to the contract on 27 October 2017.Once the ExxonMobil farm-in for 36.5% is approved the resulting working interest breakdown in the BM-S-008 contract will be Statoil operator with 36.5% working interest, ExxonMobil with 36.5% working interest, Petrogal Brasil Ltd (Galp Energia) with a 17% working interest and Barra Energia with a 10% working interest. On 27 October 2017, Statoil announced that it concluded a farm-out agreement with ExxonMobil for the discovery evaluation plan (PAD) PA_4BRSA971BSPS_BM-S-8 of the BM-S-008 contract, Carcara discovery.The transaction was announced after the results of the 2nd Pre-Salt Bid Round whereby the consortium of Statoil (40%), Exxon Mobil (40%), Petrogal (20%) won the Norte de Carcara block with a bid of 67.12% state take won the Norte de Carcara block plus the fixed bid of USD 910 million (1USD = 3.3 BRL).The transaction is complex with two different fiscal regimes and different working interest as well as formal approvals for the pending 10% working interest acquisition in the BM-S-008 contract by Statoil from Queiroz Galvao.In its press release Statoil indicated that its portion of the bonus is approximately USD 364 million for its 40% working interest in the Norte de Carcara block.For the BM-S-008 contract, the transaction has two phases.The first phase is that Statoil divested 33% of its 66% working interest to Exxon Mobil for a total consideration of USD 1.3 billion, USD 800 million in an upfront payment and a contingent cash payment of approximately USD 500 million.Additionally upon the formal approvals and closing of the 10% working interest from Queiroz Galvao, Statoil will divest 3.5% of the 10% to Exxon Mobil and 3% to Galp for a total consideration of USD 250 million, USD 155 million as an upfront payment and USD 95 million as a contingent cash payment.The resulting working interest breakdown in the BM-S-008 contract will be Statoil operator with 36.5% working interest, Exxon Mobil with 36.5% working interest, Petrogal Brasil Ltd (Galp Energia) with a 17% working interest and Barra Energia with a 10% working interest.All the partners have agreed that Statoil will be operator of the unitized field development subject to ANP approval.The discovery evaluation plan (PAD) PA_4BRSA971BSPS_BM-S-8 was modified in August 2017 pending results of the 2nd Pre-Salt Bid Round but now can move forward once the contract for the Norte de Carcara block is signed.Statoil has provisional plans to drill several wells in the contract including two new-field wildcats. On 23 August 2017, the ANP granted Statoil approval for an extension and modification to the discovery evaluation plan (PAD) PA_4BRSA971BSPS_BM-S-8 of the BM-S-008 contract, Carcara discovery.The ANP granted the operator an extension of six months after the contract is signed for the Norte de Carcara block on offer in the 2nd PSC Pre-Salt Bid Round for the joint block owners to file a combined discovery evaluation plan (PAD).The PAD has a current final expiry date of 1 March 2018 which will be extended once the joint PAD is filed and approved.The contracts from the bid round are scheduled to be signed in early 2018, which would give the PAD a date of approximately 29 July 2018 for the companies involved to file the joint PAD. On 14 September 2000, Petrobras, operator (50%), Shell (40%) and Petrogal (10%) were originally awarded the 4,865 sq km BM-S-008 contract through the ANP Round 2.Through various relinquishments and partnership changes during the contract phases the contract now covers 815.22 sq km as a discovery evaluation plan (PAD).The PAD has been extended and modified a number of times since the original contract expired on 9 August 2010 and now has a final expiry date of 1 March 2018.Petrobras was granted approvals by the ANP on 8 January 2014 for a modified discovery evaluation plan (PAD) for the 2,089.51 sq km Santos Basin BM-S-008 contract, PA_1BRSA532ASPS_BM-S-8, evaluation area that also included a partial relinquishment and modification of the PAD nomenclature to reflect the Carcara discovery well, the PA_4BRSA971BSPS_BM-S-8.Originally the PAD was granted based on the 1-SPS-052A (1-BRSA-532A-SPS) Bem-Te-Vi prospect but the area around the well was relinquished with the modified PAD approval.On 30 March 2016 the ANP approved a second modification to the PAD.The modification included substituting the long term cased hole production test of the 3-SPS-104DA (3-BRSA-1216DA-SPS) directional outpost with the drilling of the 3-SPS-105 (3-BRSA-1290-SPS) outpost.The operator was required to maintain the commitment to conduct a cased hole formation test of the 3-SPS-104DA (3-BRSA-1216DA-SPS) and to drill the Guanxuma prospect.

Brazil (Espirito Santo Platform (Espirito Santo B.)) Bem-Te-Vi (Espirito Santo)

Angostura block, Neuquén Basin in Río Negro, drilled + susp between Apr-May ’19, TD 1,347m, w.o. test. Target Quintuco fm.

Alto Las Hormigas-7H appr Angostura block, Neuquén Basin in Río Negro, drilled + susp between Apr-May ’19, TD 1,347m, w.o. test. Target Quintuco fm.

Dum-Duma B ML, Assam Shelf, oil find in 2 zones (Eocene Narpuh and Lakadong & Therria fm’s), tested 346 bo/d from an 18m pay in the Narpuh. PTD was around 4,500m. 

Hukanguri 2 op. by Oil India (100%) in Dumduma block, found 2 zones, one each in Narpuh & Lakadong-Therria Fm. On testing, a 18m Narpuh Sand, produced oil at rate of 346 bo/d. Presently, the well is under extended prod testing. This is the first commercial oil disc. in the Narpuh play.

Twinza is on the lookout for a partner to share in the planned costs of the probable devt of the Pasca A gas + liquids field in PPL 328, offshore Papuan Basin. Twinza is currently sole holder of the 85-sq km permit. Background from GEPS. Contact: Huw Evans, HuwEvans@twinzaoil.com.

Twinza is on the lookout for a partner to share in the planned costs of the probable devt of the Pasca A gas + liquids field in PPL 328, offshore Papuan Basin. Twinza is currently sole holder of the 85-sq km permit.

Equinor spudded exploration well 15/15-2 targeting the Pip prospect in licence P2318 on 13 February 2019. The well has an Upper Jurassic target. The company is using the ‘West Phoenix’ rig for operations. It is believed that operations on Pip were completed in late February 2019, as the rig has commenced drilling operations on the Verbier discovery. No results have been announced. Licence P2318 was awarded in the 29th Frontier Licensing Round in 2017. The licence comprises six blocks – 15/9a, 15/10, 15/14, 15/15, 16/6b and 16/11a. Interest in the licence is held by Equinor (U.K.) Ltd (50% + operator) and BP Exploration Operating Company Limited (50%).

015/15-02 (Pip), (Equinor 50% + op. BP 50%) in licence P2318, has an Upper Jurassic target, operations were completed, no results have been announced yet.

N. Huizhou Sag, PRMB, WD 100m, ops terminated results n/a early Aug ’19, Nanhai 5 SS. Target Oligo-Miocene clastics.

Huizhou 22-8-1 (HZ 22-8-1) nfw N. Huizhou Sag, PRMB, WD 100m, ops terminated results n/a early Aug ’19, Target Oligo-Miocene clastics.

Ketekazgan North field in Turgay Basin, oil in the new Toarcian-Bajocian Doshan Carbonates play at 3,070m. Previous finds in the Doshan plays were all in clastic reservoirs. Description from GEPS.

Ketekazgan 18 (SSM Oil LLP 50% op. Kolzhan LLP 50%) in 1057R Kolzhan block, oil disc. in the new Toarcian-Bajocian Doshan Carbonates play at 3070m. Previous finds in the Doshan plays were all in clastic reservoirs.

Ithaca Energy Inc announced on 18 January 2018 that it has agreed to sell its interest in the Wytch Farm field in licences PL89, PEDL 328 and P534 to Verus Petroleum SNS Limited for a cash consideration of GBP 53 million (USD 73.6 million). The effective date of the transaction is 1 July 2017. However, full completion of the transaction is expected around mid-2018. The deal is subject to regulatory and partner approval. Ithaca state that proceeds from the deal will be used to partly repay Ithaca’s existing bank debt facilities. The deal also releases the company from a GBP 11.5 million (USD 16 million) letter of credit posting in relation to future Wytch Farm decommissioning liabilities. Verus had previously tried to pick up interest in the field when it agreed a deal by Premier. However, Perenco pre-empted the deal and took the 33.8% interest which was on offer. 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. Following completion of the deal interest in Wytch Farm will be held by Perenco UK Limited (87.62% + operator), Verus Petroleum SNS Limited (7.43%) and Repsol Sinopec North Sea Limited (4.95%).  

Verus Petroleum has acquired 7,5% interest in the Wytch Farm field from Ithaca (->0, Perenco 87,5%, Verus 7,5%, Repsol Sinopec 5%) for US$53 MM. Involved are PL 089, P 534 + PEDL 328 across Poole Harbour.

On 1 November 2019, Walter Oil & Gas was awarded four Ewing Banks blocks: EW 702 (G36760), EW 911 (G36762), EW 953 (G36763) and EW 955 (G36764), sited in the Louisiana Coastal Basin. The blocks were originally offered as part of OCS Gulf of Mexico Lease Sale 253, held on 21 August 2019, which garnered more than US$ 159 million in high bids. Walter Oil & Gas submitted four high bids, totalling US$ 650,876. Following formal award, Walter Oil & Gas is the operator and sole interest-holder (100% WI + Op).

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The energy ministry is understood to be preparing a tender call for the Sveta Marina offshore block in 2019. Sveta Marina lies in WD max. 200m between the Galata, Han Asparuh and Han Kubrat blocks. Sveta Marina coords have yet to be released.

The energy ministry is understood to be preparing a tender call for the Sveta Marina offshore block in 2019. Sveta Marina lies in WD max. 200m between the Galata, Han Asparuh and Han Kubrat blocks. Sveta Marina coords have yet to be released.

RockRose Energy announced on 9 August 2018 that it has agreed to acquire Dana Petroleum’s 20.43% in the Arran North field which is part of the Arran development along with Arran South. The fields are located in blocks 23/11a (P1051), 23/16b (P1720) and 23/16c (359) in the Central North Sea. A Field Development Plan for Arran (fields)  is planned to be submitted to the Oil and Gas Authority (OGA) towards the end of September 2018. The field development is likely to be a tie-back to the Shell operated Shearwater Platform. Completion of the deal is subject to approval from the OGA and partner consents. The plan is to develop the fields via two drill centres (North and South) with two wells on each, tied-back to the Shearwater facilities in block 22/30 via the Scoter riser. A new 60-km pipeline will be installed between Shearwater and Arran. Work is scheduled to start on the development later in 2018 with development drilling commencing in Q3 2019. First production is targeted for late 2020 and life of the field is expected to be 12 years. The Arran fields were previously called Phyllis and Barbara. The reservoir is Paleocene Upper and Lower Forties sandstones around a salt diapir. Plans were originally in place for development in 2010, when a unitised agreement was set up and in June 2010, Serica reported that an agreement had been reached between the operators of Lomond, Columbus and Arran on a FEED for a bridge linked platform on Columbus that would connect with the Lomond platform. An ES was submitted in July 2010, which included plans for three production wells and two drill centres on the Arran development. A drill centre was to be located on both Arran North and South. Two wells were to be drilled on Arran South and one on Arran North. Arran North was to be linked to South via a 7-km pipeline, which was to be linked in turn to a new riser Bridge Linked Platform (BLP) adjacent to the Lomond platform 21-km to the south. The drill centres were to have the capacity for two additional wells each. Development was originally expected to start (with modifications to host infrastructure) in February 2011 and drilling was expected to run from July 2011 until February 2012. First gas was initially expected December 2012. In March 2013 BG informed Serica that it would not be proceeding with the construction of a BLP to the Lomond field. Following completion of the deal interest in the field is to be held by Zennor North Sea Ltd (47.36), Shell UK Ltd (23.68%), RockRose Energy (20.43%) and Dyas (UK) Ltd (8.53%).

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

On 20 January 2020, BP and the National Agency of Petroleum, Gas and Biofuels (ANPG) signed a preliminary agreement aimed at BP and the Block 18 group acquiring exploration rights for Block 18/15. The agreement defines the process and general terms for a Risk Service Contract (RSC). According to President of the Board of Directors of ANPG, Paulino Jerónimo the agreement allows for an exploration contract with BP atop an area that has significant potential and where there are existing undeveloped oil fields. President of BP Angola, Stephen Willis mentioned that BP believes the Cretaceous formations within the area present good exploration opportunities and potential developments and that the Greater Plutonium Development presents opportunities for subsea tie backs.   The 4,600 sq km block straddles the Congo Fan, Kwanza Basin and Lower Congo basin. To date all the discoveries within Block 18 are Tertiary (Miocene or Oligocene) and located within the Congo Fan. Only one well has been drilled within the Kwanza Basin portion of the Block: in 2014 Petrobras drilled the Mercurio 1 well targeting Albian aged carbonates. The well was plugged and abandoned with oil shows.   Once the RSC is signed that partnership is expected to be: BP operator with a 46% interest, Sonangol Sinopec International Ltd a 37.72% stake and Sonangol holding the remaining 16.28% stake.

A preliminary agreement was signed with ANPG for BP (op), Sonangol Sinopec Intl + Sonangol to secure rights to block 18/15. This agreement defines general terms for a risk service contract. The 4600km² block straddles the Congo Fan, Kwanza + Lower Congo basins.

Ref. DEA 8 Mar ’18, Statoil and Total have completed the acquisition of Cobalt’s 60% operated interest in the North Platte discovery in Garden Banks deepwater blocks 958 + 959 for USD 339 MM. Total now has operatorship and 60%, Statoil 40%. Effective date of the deal is 1 Jan ‘18.

Ref. DEA 8 Mar ’18, Statoil and Total have completed the acquisition of Cobalt’s 60% operated interest in the North Platte discovery in Garden Banks deepwater blocks 958 + 959 for USD 339 MM. Total now has operatorship and 60%, Statoil 40%.

On 30 June 2020 Santos Ltd, through wholly owned subsidiary Santos QNT Pty Ltd, was awarded Authority to Prospect permit ATP 2055-P, located in the Roma Shelf, Bowen-Surat Basins. The permit was awarded following the PLR2019-2 Queensland State Acreage Release, where it was offered as bid block PLR2019-2-10. Santos has been awarded the permit for a period of six years, with a four-year committed work programme, which will expire on 29 June 2024. The permit is scheduled to expire or be eligible for renewal on 29 June 2026. Under the terms of the award, any gas produced from acreage must be supplied to the Australian market, a term which is carried over should a production license be awarded over the permit. Santos Ltd applied for the bid block PLR2019-2-10 on 13 February 2020. The expiry date of the schedule work programme for the permit is on 20 May 2024, until which time no amendments to the programme will be allowed. ATP 2055-P covers an area of 330 sq km. Santos QNT Pty Ltd holds 100% interest and operatorship in the permit.

Australia (Bowen - Surat B.s), ATP 2057-P, Santos Ltd was awarded Authority to Prospect permit ATP 2055-P. Santos has been awarded the permit for a period of six years, with a four-year committed work programme, which will expire on 29 June 2024. The permit is scheduled to expire or be eligible for renewal on 29 June 2026.

On 3 February 2020, PetroRio announced that it signed a definitive agreement to acquire 80% working interest in the Tubarao Martelo production concession from Dommo Energia and would acquire the FPSO OSX-3 for USD 140 million. The goal of the transaction is for PetroRio to jointly operate the easterly adjoining Polvo field and the Tubarao Martelo field as a cluster development thus reducing OPEX costs 50% with the synergies and extending field recoverable reserves life to 2035. The announcement by PetroRio also included an update on three new pool discoveries drilled by the operator in December 2019 that are within 6-7 km of the FPSO OSX-3 in the western area of the Polvo production concession. PetroRio plans to tie-back production from its Polvo A fixed platform in the Polvo field to the FPSO OSX-3 located approximately 9.9 km to the southwest and de-commission the FPSO Polvo by mid-2021 with a Capex estimated to be between USD 50-60 million. The transaction is complex with additional financial commitments by PetroRio besides the USD 140 million for the purchase of the FPSO OSX-3. From the current transaction date to the completion of the tieback operation, PetroRio will have rights to 80% of the production from the Tubarao Martelo Field and be responsible for 100% of the FPSO's charter expenses, the Tubarao Martelo field's Opex, and Capex and abandonment costs. During this phase, through approximately mid-2021, Dommo will reimburse PetroRio a monthly fee of USD 840 thousand equivalent to 20% of Dommo's current Opex, excluding the FPSO charter costs. Once the tieback is complete, PetroRio will be responsible for 100% of all costs for the cluster and Dommo will stop paying the monthly fee with PetroRio to have rights to 95% of the produced oil from the cluster up to 30 MMbo produced after tieback, and 96% thereafter. The 1 January 2019 BAR reserves report had the Polvo field holding original oil in place (OOIP) of 404.84 MMbo and original gas in place (OGIP) of 32.55 Bcfg and with a cumulative production of 44.06 MMbo and 4.36 Bcfg represented a recovery factor to that date of 11% for oil and 13% for the gas. The 1 January 2019 BAR reserves report had the Tubarao Martelo field holding OOIP of 428.49 MMbo and OGIP of 46.96 Bcfg and with a cumulative production of 15.02 MMbo and 1.65 Bcfg represented a recovery factor to that date of 4% for oil and 4% for the gas. Both fields have a low GOR of approximately 100 cu-ft/bo and produce oil of 20° to 21° API. The Polvo field had an average daily production in 2019 of approximately 8,437 bo/d and Tubarao Martelo 5,815 bo/d. Dommo Energia held 100% working interest in the Tubarao Martelo production concession but after formal governmental approvals PetroRio will be the operator with 80% working interest and Dommo will hold 20%. On 3 February 2020, PetroRio also announced that it completed two directional special wells and one horizontal development well in the Polvo production concession and discovered three new oil pools one in the Eocene Embore Formation and two in the early-Cretaceous Quissama Formation. The three wells include the POL-N (9-POL-042D-RJS) and POL-Na (9-POL-043DP-RJS) special wells completed in December 2019 and the POL-Nb (7-POL-44HP-RJS) horizontal development well completed and initially tested in January 2020. On 3 December 2019, Dommo Energia announced that it was nearing conclusion of the revitalization project in its Tubarao Martelo field in the Campos Basin that it originally announced it would undertake in November 2018. On 26 November 2018, the company announced that the revitalization project consisted in the completion of well 7-TBMT-4HP-RJS, that needed to be connected to FPSO OSX 3, and the workover of 4 producing wells (7-TBMT-2HP-RJS, 7-TBMT-6HP-RJS, 7-TBMT-8H-RJS and 9-OGX-44HP-RJS). The company indicated that the revitalization project would increase production in the field to an estimated of 10,000 bo/d by the end of 2019. The estimated cost of the project was USD 80 million. From January to October 2019 the field has produced an average of 5,831 bo/d, 597 Mcfg/d, and 2,345 bw/d. In October 2019, only three wells were producing, the 7-TBMT-6HP-RJS, 7-TBMT-8H-RJS and 9-OGX-44HP-RJS, with the 7-TBMT-2HP-RJS not producing. The Tubarao Martelo field was discovered in December 2010 with well 1-OGX-WAIKIKI-1-RJS (1-OGX-25-RJS). The well was targeting post-salt Eocene sandstones of the Carapebus Formation and post-salt Upper Cretaceous carbonates of the Imbetiba Formation. The carbonate reservoir is the main reservoir of the field. Tubarao Martelo field was appraised between February 2011 and April 2011 by 2 wells (3-OGX-35D-RJS and 3-OGX-41D-RJS). The field was declared commercial in April 2012 by OGX. It was the first commercial declaration of an offshore oil discovery for the company. The Tubarao Martelo field started production in December 2013 through the FPSO OSX-3. As of September 2019, is has produced 17.6 MMbo and 1.8 Bcf of gas. Development drilling started in September 2012 and concluded in February 2013. No improved recovery techniques have been applied in this field. The Polvo production concession covers an area of 134.1 sq km and has been producing since 2007 when it was brought online by former operator Devon. From February 2012 to February 2013 the Polvo Field produced an average of 13,711 bo/d, 20° API, and about 20,000 bw/d. There are about 10 wells producing currently. The Polvo Field reservoirs include the Maastricthian and Turonian turbidites of the Carapebus Formation and the Early Cretaceous Quissama Formation carbonates are also productive. Rumors of BP possibly selling assets surfaced in August 2012. On 6 May 2013, HRT announced that it acquired 60% working interest and operations of the Campos Basin Polvo production concession from BP Energy do Brasil Ltda. The retroactive purchase date is 1 January 2013 for a price of USD 135 million. HRT acquired all associated equipment from a separate BP subsidiary that owns and operates the Polvo A fixed platform and other drilling and production equipment with the exception of the FPSO Polvo that is owned and operated under contract by BW Offshore. The transaction was granted formal approval by the ANP on 18 December 2014.

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

In December 2018, media reports indicated that Eni will sign an Exploration & Production Sharing Agreement (EPSA) with the Omani Ministry of Oil and Gas (MOG) for Block 47 (Jebel Hammah). Salim Nasser Al Aufi, undersecretary at the MOG, said negotiations had been finalised and that the agreement would be signed soon. The onshore block (8,524 sq km) is located in the northern part of the country, in the Governorates of Ad Dhahirah and Ad Dakhiliyah. <P />Together with three other blocks, the acreage was offered in Oman's 2017 Licensing Round, which was launched on 20 September 2017 and closed on 31 December 2017. The EPSA will be Eni's second in Oman, after it signed an agreement for Block 52 (JuzorAl Hallaniyyat) in October 2017.<P />Block 47 (Jebel Hammah) has been held by various operators in the past, including Petroleum Development Oman (PDO), Amoco, RAK Petroleum and DNO. Tight gas is the predominant play within the block and to date, gas has been discovered in the Cretaceous Natih and Shuaiba Formations and gas and condensate in the Cambrian Amin Formation.<P />Within the tight gas play is an unconventional sub-play for the Natih E. This unit is a source interval and also a reservoir. Development of unconventional gas is only beginning in the Sultanate and the Natih E has been recognized as a prime target.

Media reports indicated Eni will sign an EPSA with the Omani Ministry of Oil and Gas (MOG) for Block 47 (Jebel Hammah).

Total E&P USA Inc. and Statoil Gulf of Mexico LLC have completed the acquisition of the deepwater Gulf of Mexico assets they successfully bid for at Cobalt International Energy’s bankruptcy sale that was held on 6 March 2018. The two companies tendered a joint bid of USD 339 million to capture the crown jewel of the Cobalt auction, the North Platte discovery located primarily on Garden Banks block 958 and 959. Discovered in 2012, this subsalt Wilcox oil accumulation lies in some 4,500 ft (1,372 m) of water approximately 175 miles (280 km) offshore Louisiana. Cobalt successfully appraised its discovery before the bankruptcy, drilling 11 boreholes from three surface locations. Owing to the results of these delineation wells, the former operator estimates the gross recoverable resource range for North Platte at 500 to 650 MMbbl of oil equivalent. With the completion of the deal, Statoil owns a 40% working interest in the four-block North Platte unit that consists of Garden Banks blocks 915 (G30869), 916 (G30870), 958 (G32460), and 959 (G30876). Three of the four blocks in the unit have expired and are now held by unit operations. A suspension of production has been submitted for the unit and is awaiting government approval. Already a partner in the North Platte project, the acquisition increases Total’s working interest from 40% to 60%. Total takes over as operator as part of the North Platte transaction, which has an effective date of 1 January 2018. Total also successfully bid on several other Cobalt assets at the bankruptcy auction. Along with North Platte, Total picked up Cobalt’s 20% working interest in Chevron U.S.A. Inc.’s Anchor project, which is another Paleogene-aged, subsalt Wilcox discovery made in 2014 in the Green Canyon area. Total paid USD 181 million for the asset. This new working interest augments Total’s equity position in Anchor to 32.5%, after having obtained the 12.5% stake previously held by Samson Offshore last December. Anchor lies in some 5,200 feet (1,585 m) of water in the southwest quadrant of the Green Canyon (GC) protraction area, roughly 150 miles (240 km) southwest of the coastal support base at Port Fourchon, Louisiana. The appraisal phase is completed at Anchor. In Chevron's Q3 2017 earnings call of 27 October 2017, Chairman and CEO John Watson said that Anchor remains in the concept development stage and is not yet in front end engineering and design. Cobalt estimates the gross recoverable resource range for Anchor at 330 to 600 MMbbl of oil equivalent. The Anchor project is covered by a six-block unit consisting of GC blocks 762 (G25198), 763 W/2 (G25199), 806 (G31751), 807 (G31752), 850 (G31757), and 851 (G31758). Like North Platte, the Anchor leases have passed their expected expiration date and are held by unit operations. Chevron filed for a suspension of production in January 2018 intended to hold the leases while a development plan matures. Chevron (55%), Total (32.5%) and Venari Offshore LLC (12.5%) comprise the Anchor ownership group. Total rounded out its participation in the asset sale taking 13 of Cobalt’s deepwater exploration blocks for USD 25 million. The US Bankruptcy Court for the Southern District of Texas approved the results of Cobalt’s asset sale on 5 April 2018.

Total E&P USA Inc. and Statoil Gulf of Mexico LLC have completed the acquisition of the deepwater Gulf of Mexico assets they successfully bid for at Cobalt International Energy’s bankruptcy sale that was held on 6 March 2018.

Lime parent Rex Intl advises its withdrawal from PL338C, 338E + 815 in the NNS was complete on 29 May ’19, retro-effective 1 Jan ’19. Remaining partners Lundin (op), OMV.

Lime parent Rex Intl advises its withdrawal from PL338C, 338E + 815 in the NNS was complete on 29 May ’19, retro-effective 1 Jan ’19. Remaining partners Lundin (op), OMV.

Madagascar Oil is seeking to dilute its 100% interest in the Tsimiroro Contractual Area (block 3104), home to the Tsimiroro heavy oil field. Near-term plans include drilling a (light) oil prospect in the S. part of the licence within the known hc play, 3 wells planned as of Jun ’19, target 200m thick Lower Sakamena reservoir expected at ~700m.

Madagascar Oil is seeking to dilute its 100% interest in the Tsimiroro Contractual Area (block 3104), home to the Tsimiroro heavy oil field. Near-term plans include drilling a (light) oil prospect in the S. part of the licence within the known hc play, 3 wells planned as of Jun ’19, target 200m thick Lower Sakamena reservoir expected at ~700m.

Romgaz is looking to acquire 15-20% from ExxonMobil in the XIX Neptun East licence, and talks are said to be underway on the latter's initiative. The block encompasses the Domino and Pelican South gas fields. Neptun is divided into XIX Neptun East (7,916 sq km) and XIX Neptun West (1,727 sq km), the latter apparently not part of the talks. Exxon (op), partner OMV Petrom.

Romgaz is looking to acquire 15-20% from ExxonMobil in the XIX Neptun East licence, and talks are said to be underway on the latter's initiative. The block encompasses the Domino and Pelican South gas fields. Neptun is divided into XIX Neptun East (7,916 sq km) and XIX Neptun West (1,727 sq km), the latter apparently not part of the talks. Exxon (op), partner OMV Petrom.

Australian Impose Holdings has reportedly agreed to acquire an 80% stake in contract SG4571, 1,013 sq km in the Cabora Basin, through the acquisition of fellow Invictus Energy Resources.  The project is known as Cabora Bassa and features the large Mzarabani prospect. A farmout may be offered ahead of drilling. Impose (op-to-be), partner One-Gas Resources.

Murphy is offering up to 25.5% in SK-405B, 2,352 sq km astride the Balingan and Tatau provinces off Sarawak, WD 10-50m. Murphy currently 59.5% (op), partners MOECO + Petronas.

Theia Energy Pty Ltd, previously Finder Shale Pty Ltd before a name change/spin-off, is seeking a farm in partner to fund exploration activities in the Canning Basin permit EP 493. Theia Energy is offering a 30 – 50% equity position in return for contributions to well costs, as well as payment for historical costs on the permit. The permit covers the mature liquids rich shale play Goldwyer III – Bakken Shale analogue at shallow depths and is ideally situated close to existing infrastructure. EP 493 is situated between Buru the Mitsubishi and New Standard Energy/ConocoPhillips’ permits, south west of Key’s Cyrene-1 well. Theia Energy was initially looking for a farm in partner to assist with costs of Theia 1 exploration well when the farm-out was first announced in May 2015. Theia 1 subsequently spudded on 15 July 2015 and reached a TD of 1,645 m on 28 August 2015. During drilling Theia Energy utilised a “slim-hole” drilling technique, which reduces environmental impact and costs and also allowed the acquisition of a continuous core section. Theia Energy reported that a total 778 m of continuous core had been acquired during drilling. Upon reaching total depth wireline logs were run over the cored interval of the target Ordovician Goldwyer Formation. Theia Energy reported that high wet gas mud readings, increased wireline resistivity, fluorescence, positive well desorption indications, and a geothermal gradient validated the geological model and de-risk the Canning Goldwyer shale play. In 2015 Theia Energy suspended term one of the work programme until 28 February 2018 to facilitate the completion of a 220 km 2D seismic survey. However, on 28 February 2018 Theia Energy received approval from the Department of Mines, Industry Regulation and Safety (DMIRS) to vary the work conditions, from which, Theia Energy is now exempt from completing the seismic survey (AUD 2.6 million). The exemption also extends to the drilling of two exploration wells in term two (AUD 17.95 million). The wells have been deferred to term three. In January 2019 further suspension and extension of the work programme was granted, with the wells now to be completed by 28 February 2021 and expected to cost a total of around AUD 10.6 million. The exemption to drill an exploration well in permit term 2 was first approved after Theia Energy drilled the Theia-1 exploration well in term one, which DMIRS credited towards the term two commitments (leaving the requirement to drill two wells). A moratorium on hydraulic fracturing (“fracking”) in Western Australia has been in place since 5 September 2017 and is likely to remain in place until the completion of an independent scientific inquiry which is assessing the full impact and regulatory framework of fracking within the State. Completion of the inquiry is not expected until 2020. Under the original work programme, Theia Energy proposed to drill the Helios-1 well in 2018, including a 1,000 m lateral section within the Goldwyer III shale. The exploration programme was expected to cost around AUD 30 million and included fracking and an extended well test. The moratorium does not permit this activity. EP 493, which covers 4,628 sq km, was awarded on 1 March 2015 is now scheduled to expire, or be eligible for renewal by, 28 February 2022 after two extensions. Theia Energy Pty Ltd, which holds 100% interest in the permit, and are offering 30-50% equity and participation in the next phase of exploration. Companies interested in pursuing this opportunity should contact: Ryan Taylor-Walshe, General Manger          Tel: +61 474 979 474            Email: ryan@theiaenergy.com Jop van Hattum, COO            Tel: +31 430 739 507              Email: j.vanhuttum@theiaenergy.com

Theia Energy Pty Ltd, previously Finder Shale Pty Ltd before a name change/spin-off, is seeking a farm in partner to fund exploration activities in the Canning Basin permit EP 493. Theia Energy is offering a 30 – 50% equity position in return for contributions to well costs, as well as payment for historical costs on the permit.

Pan American Energy was fracking and tested gas from the Vaca Muerta Shale at last report on the Aguada Pichana Oeste 102(h) horizontal well on the Aguada Pichana license, Neuquen Basin. The well had a 32 stage frack performed over the 2,998 to 4972m gross interval. 3.17 MMcfg/d was tested with a high water cut. The well was spud on 11 January and finished drilling on 10 February with a 5,078m TD and 2,848m TVD. Pan American operates and holds 45%, YPF 30% and French operator Total has a 25% working interest on the Aguada Pichana Oeste Block.

Pan American Energy was fracking and tested gas from the Vaca Muerta Shale at last report on the Aguada Pichana Oeste 102(h) horizontal well on the Aguada Pichana license, Neuquen Basin. The well had a 32 stage frack performed over the 2,998 to 4972m gross interval. 3.17 MMcfg/d was tested with a high water cut. The well was spud on 11 January and finished drilling on 10 February with a 5,078m TD and 2,848m TVD. Pan American operates and holds 45%, YPF 30% and French operator Total has a 25% working interest on the Aguada Pichana Oeste Block.

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

Repsol continued offering a farm-in opportunity in the Andaman III PSC, located in offshore North Sumatra Basin, in late October 2018. The company is offering up to 49% interest to participate to a planned high-impact exploration drilling campaign in late 2019. A data room was opened in September 2018 and the process is expected to be finalized in early 2019. The planned well, Rencong 1, will likely target Upper Eocene-Lower Oligocene carbonates of the Tampur Formation. The operator commenced the search for a deepwater rig in early September 2018. It is understood that the necessary permits for the drilling campaign are in place. Rencong 1 will fulfill the exploration commitments for the PSC. In late November 2017, the company completed the seismic commitment with a 3D seismic survey covering over 3,000 sq km in the block. The survey, acquired using Elnusa’s “Elsa Regent” vessel, was reported as the largest 3D seismic survey acquired in Indonesia at the time. The block is operated by Repsol’s fully owned subsidiary Talisman (Andaman) BV, with 100% interest. Prior to the acquisition by Repsol, Talisman had offered a farm-in opportunity in the block in 2014. At the time, several companies reportedly expressed interest in the highly prospective block. The Andaman III PSC, awarded in 2009, covers approximately 8,500 sq km and lies between shelf and over 1,300 m water depth. The block was offered during Phase II 2008 Tender Round under the regular tender mechanism and was officially awarded to Talisman (100%, operator) on 30 November 2009. The company paid a signature bonus of USD 7.5 million for the block. Firm commitments include G&G studies worth USD 2 million, acquisition of 2,500 sq km 3D seismic (USD 15 million) and drilling one well (USD 30 million). The seismic acquisition commitment was initially planned in 2010 but has been pushed back to a later date. The well commitment likewise has not been fulfilled. This deep water area in the southern Andaman Sea is vastly under-explored. Three exploration wells have been previously drilled within the current block boundaries. All are situated in the southern of the block, on the North Sumatran shelf. Samalanga 1 (P&A/dry - 1986) and Glumpang Minyeuk 1 (P&A/dry, 1987) were both drilled by Inpex, under the North Aceh Offshore PSC. EAO-B-1, which lies at the edge of the block, was also a dry hole. This well was drilled by Mobil in 1982 under the NSO PSC. Background Information Multiple play types exist in the area, including carbonate build-up on a basement high or on an anticline, syn-rift clastics with combined stratigraphic-structural trap component, inverted syn-rift clastics close to the Mergui Ridge, carbonate build-ups on flanks of the Mergui Ridge and Barisan fold-belt anticlines. Potential source rocks in the area in include the shales of the Eocene Parapat (lacustrine syn-rift), Oligocene Bampo, Lower Miocene Peutu/Belumai and Middle Miocene Baong formations. Potential reservoirs which could have commercial accumulations in this deepwater area are the Belumai carbonates and Parapat syn-rift sandstones. Shales of the Bampo and Baong formations would be the likely seals. Second exploration phase commitments (Year 4 to 6) include G&G studies (USD 0.6 million), acquisition of 500 sq km 3D seismic data (USD 3 million) and drilling one exploration well (USD 30 million). Directly east of the Andaman III block are Eni's Krueng Mane block, where two out of the planned three exploration wells were drilled in 2008/2009, and Zaratex's Lhokseumawe PSC. The 1985-1997 North Aceh Offshore PSC, operated by Inpex, previously covered a portion of this new block. This contract was held under moratorium for several years while Inpex attempted to re-negotiate the terms of the PSC to take into account the deep water nature of the area. Failure to settle the terms and the subsequent unjustifiable economics of exploration led to Inpex prematurely relinquishing the block. Vintage 2D seismic does exist, after Geco Prakla shot several 100 km lines over the area (North Sumatra Basin - Mergui Ridge) in 1995.

Indonesia, Andaman III PSC

In May 2020, Ecopetrol indicated that the Olini Oeste 1 outpost well, in the northern part of the Tolima B Block in the Upper Magdalena Basin, was plug and abandoned dry. The Olini Oeste 1 spudded on 24 December 2019 and reached a total depth (TD) of 5,000 ft (1,524 m) and a total vertical depth (TVD) of 4,900 ft (1,494 m). It is assumed the outpost was targeting Miocene sandstones of the Honda Group believed to be targeted at the Olini 1 discovery, in a structural-stratigraphic trap made of an anticline truncated by an unconformity. The 75.57 sq km Tolima B Block, Tolima Contract is owned and operated by Petrotesting Colombia S.A. with 46% working interest, and non-operating partner Ecopetrol with the remaining 54% since December 2012. The block was officially awarded in June 1986 to operator Hocol with 55% working interest and Isthmus Exploration Inc with 45% working interest. Background Information The Olini 1 new-field wildcat (NFW) spudded in June 1989 and it was suspended in July of the same year as an oil discovery. The NFW reached a TD of 6,230 ft (1,899 m) and it is assumed it was targeting Miocene sandstones of the Honda Group. Besides the recently drilled Olini Oeste 1, three other outposts have been drilled to evaluate the Olini discovery: Olini 2, Olini 3 and Olini Sur 1. All those wells found oil. Olini wells Well Name Spud Date Td Feet Td Meter Olini 1 12-Jun-1989 6,230 1,899 Olini Sur 1 22-Jun-2005 4,026 1,227 Olini 2 06-Feb-2013 4,323 1,318 Olini 3 30-May-2013 4,650 1,417 Source: IHS Markit © 2020 IHS Markit

Ecopetrol indicated that the Olini Oeste 1 outpost well, in the northern part of the Tolima B Block in the Upper Magdalena Basin, was plug and abandoned dry.

On 12 March 2020, the ANP board of directors approved the assignment of 25% interest from the ONGC Campos Ltda subsidiary of India's ONGC to Petrobras on the BM-BAR-1 Block, in the frontier Barreirinhas Basin. Petrobras will now hold 100% of the license. On 1 May 2019, antitrust regulator Cade approved this requested transfer 25% to Petrobras from ONGC. Petrobras said that ONGC requested to leave the project in 2012 but the request was denied due to debt on the project which was only resolved after a lengthy international arbitration. Petrobras claimed ONGC did not make an agreed payment with them thus triggering default clause 13.1 of the Joint Operating Agreement (JOA) that did not allow ONGC to withdraw from the block before the issue was resolved. The issue gave rise to an arbitration process that was only resolved in 2018, so ONGC could legally withdraw from the project. The BM-BAR-1 Block was acquired by Petrobras in ANP Round 3 in 2001. The 1BRSA1015MAS well discovered gas on the block and in 2012 twice reported natural gas shows to the ANP. In November 2017, the ANP suspended the concession contract for the area due to the difficulty faced by Petrobras in obtaining an environmental license to drill there. With the decision of the ANP, the exploration acreage of the block and the Discovery Assessment Plan (PAD) for the 1BRSA1015MAS were suspended until Petrobras obtains an environmental license to drill a well there. The ANP also added 730 days to the contract of the PAD to be counted after Ibama issues a drilling permit for the block. The ANP in March 2013 approved an evaluation plan based on the 1BRSA1015MAS discovery well. The well has a total depth of 3,285m and was targeting the Late Cretaceous Travosas Formation turbidite sandstones with a PTD of 4,028m. It was drilled in a water depth of 1,253m. <P />

ONGC Campos Ltda subsidiary of India's ONGC has transferred 25% interest on the BM-BAR-001 Block to Petrobras (->100%).

According to PetroChina News report on 15 August 2018, PetroChina - Daqing has an oil discovery in the Songliao Basin. New field wildcat Shuang 68 was spudded in early 2018 in the Shuangcheng Depression. The well had an open flow rate of more than 630 b/d (100 cm/d) of oil possibly from the Lower Cretaceous Quantou Formation in April 2018. It was then kept at a restricted flow rate of 157 b/d (25 cm/d) of oil. The Shuangcheng Depression is in the eastern part of the South Songliao Basin, adjacent to the Xujiaweizi Depression where the Xushen gas field was found.  Shuangcheng Depression covers an area of 5,076 sq km and holds an estimated 8.6-11.5 Tcf gas resource potential. Background information In 2016, PetroChina-Daqing tested commercial oil with exploration well Shuang 66 in the Shuangcheng Depression, Songliao Basin. The well flowed 75 b/d (12 cm/d) of oil following fracking operations in the Lower Cretaceous Denglouku Formation. Shuangcheng field was discovered with the Shuang 30 new field wildcat which tested oil from the Lower Cretaceous Quantou Formation in 1995. The field was then put onstream in 2006. As of 2011, the field had 468 development wells and more than 130 exploration wells.  Around 80 sand layers have been tested for oil. By end-2016, a total of 11.5 MMbbl of oil and 600 MMcf of gas have been produced from the field.

China (Southeast Uplift (Songliao B.)) Shuangcheng

The ANH has extended the bid submission deadline for the Sinú-San Jacinto Basin round from yesterday until 3 May ’18. For the record 15 blocks are on offer, 2 blocks mature, the remainder semi-explored. SN-10, SN-14, SN-19, SN-20, SN-21, SN-22, SN-23 and SN-24 lie in the Sucre dept, SN-5, SN-6, SN-16, SN-17, SN-25, SN-26 and SN-27 in the Córdoba dept. Six companies have qualified, namely Gran Tierra, Hocol, Nexen, Noble, Parex and Repsol.

The ANH has extended the bid submission deadline for the Sinú-San Jacinto Basin round from yesterday until 3 May ’18. For the record 15 blocks are on offer, 2 blocks mature, the remainder semi-explored. SN-10, SN-14, SN-19, SN-20, SN-21, SN-22, SN-23 and SN-24 lie in the Sucre dept, SN-5, SN-6, SN-16, SN-17, SN-25, SN-26 and SN-27 in the Córdoba dept. Six companies have qualified, namely Gran Tierra, Hocol, Nexen, Noble, Parex and Repsol.

2014 unconventionals well in EP 161, McArthur Basin, fracked in late 2019, now testing the Middle Velkerri Shale, 1.2 MMcf/d recorded of mainly methane.

Tanumbirini 1 (Santos 75%, Tamboran Res 25%) in EP 161 block. Production testing ongoing, gas discovery with test results confirming a gas discovery in the Middle Velkerri shale gas play. Gas flow rates of over 1,2 MMcfg/d were recorded with initial gas composition analysis indicating more than 90% methane, less than 5% total inert content and 3% ethane.

According to official reports in late-August 2018, Echo Energy has signed a Letter of Intent (LOI) with Bolivian state company YPFB for a new Technical Evaluation Agreement (TEA) for the purpose of continuing its study on the Rio Salado block. Planned future activities include geological surveys, seismic acquisitions, and the drilling of exploratory wells with objectives in the Huamampampa, Icla and Santa Rosa formations. Rio Salado block covers 522 sq km block is located in the Sub-Andean Zone of Chaco Basin on the Tarija Department. The block is situated around Pluspetrol’s Campo Huayco block where the Huayco X1 gas and condensate discovery from 1982 is located. It is also directly adjacent to Shell’s Huacareta block on the western side where the operator is currently drilling the Jaguar X6 NFW to investigate the Huamampampa Formation, and next to Repsol’s Caipipendi block on its eastern side where the mega gas field of Margarita-Huacaya is located. Background Information Echo Energy originally signed a TEA for the block with partners Pluspetrol and Shell in July 2017, although it is unclear at this point if the latter two will continue to be involved in the new agreement.

Bolivia (Maturin Sub-basin (East Venezuela B.)) Santa Rosa

Ghauri 3273-3 EL, onshore Potwar Basin, Punjab, TMD 4,770m (4,472m TVD), DST’d 372 b/d of 29 API oil from the Kherwa fm, targets Sakessar + Khewra fm’s. Next well planned Miraj-1. MPCL (op), partner PPL.

Dharian-l ST-3 expl in Ghauri 3273-3 EL, onshore Potwar Basin, Punjab, TMD 4,770m (4,472m TVD), DST’d 372 b/d of 29 API oil from the Kherwa fm, targets Sakessar + Khewra fm’s. MPCL (op), partner PPL.

PetroChina made a breakthrough in deep shale gas exploration drilling in the Sichuan Basin. Zu 201-H1, a horizontal well with a TD over 6,000 m, tested 3.7 MMcf/d of gas from the Longmaxi Formation in early November 2017, which is the deepest shale gas well so far completed in the Sichuan Basin with commercial gas flow.  PetroChina completed Zu 201-H1 well drilling in the Sichuan Basin in March 2017. Zu 201H-1, kicking off from Zu 201, reached a TD of 6,038 m. The well was started on 20 August 2016.  PetroChina completed Zu 201, a vertical shale gas exploration well, in the Sichuan Basin in October 2015. Zu 201 was located in Dazu-Rongchang block with target in the Longmaxi Formation and the well reached a TD of 4,412 m. Earlier in 2017 PetroChina achieved commercial gas flow in a shale gas well in this area. Zu 202 tested 1.7 MMcf/d of gas from the Longmaxi Formation. The well has a TD of 3,980 m. PetroChina is partnership with Sinochem and Chongqing Municipal local energy company in the Dazu-Rongchang block.

China, not found

VIM 21, Lower Magdalena, target shallow Porquero sst, spudded late Apr ’18, currently completing as a Porquero gas find, Pioneer 302 rig. Next well planned Borojo-1 nfw in June, Esperanza block, target CDO, and Canahuate East.

Breva-1 VIM 21, Lower Magdalena, target shallow Porquero sst, spudded late Apr ’18, currently completing as a Porquero gas find, Pioneer 302 rig. Next well planned Borojo-1 nfw in June, Esperanza block, target CDO, and Canahuate East.

10 years after having sold a 10% interest in the REC-T-158 block to Labrea Petróleo, Cowan Petróleo has re-acquired the interest. Cowan is now again sole holder of the 31-sq km block within the BT-REC-037 contract, Recôncavo Basin.

10 years after having sold a 10% interest in the REC-T-158 block to Labrea Petróleo, Cowan Petróleo has re-acquired the interest. Cowan is now again sole holder of the 31-sq km block within the BT-REC-037 contract, Recôncavo Basin.

Hokchi suspended as a potential new pool oil discovery the Xaxamani 2EXP new-pool wildcat (NPW) in the CNH-R03-L01-AS-CS-15/2018 contract in the offshore Sureste Basin during late-September or early-October 2019 and an unreported final total depth (TD). Partner Talos reported on 6 November 2019 that the Xaxamani 2EXP had 45 m of gross pay with 35.1 m of net pay in two shallow oil sands. The CNH reported that the well was an oil producer on 22 October 2019 without any details. Hokchi tested the well in August and September. The partners planned to conduct a drill-stem test (DST) prior to moving the rig to drill the Tolteca prospect in the block. The NPW spudded in late-July 2019 and reached an unreported total depth (TD) in early-August 2019. The NPW had a proposed total depth (PTD) of 910 m. The prospect had a primary target in the Lower Pliocene, from 751 m to 784 m and 810 m to 841 m. The well was drilled by the Borr Drilling “Odin” J/U in a water depth of 19m. The NPW is located in the south-eastern area of the block approximately 570 m south-west of the Xaxamani 1 non-commercial oil well drilled by PEMEX in 2003. The unrisked prospective resources are reported to be 43.6 MMboe. The drilling cost for the Xaxamani 2EXP NPW is USD 18.42 million and the completion cost is estimated to be USD 17.93 million. On 12 July 2019, the CNH approved the drilling permit request submitted by operator Hokchi for the Xaxamani 2EXP new-pool wildcat (NPW). Hokchi is operator of the contract with 75% working interest and lone partner Talos with 25%. On 12 July 2019, the CNH approved a modification to the exploration plan submitted by operator Hokchi on 31 May 2019 for the CNH-R03-L01-AS-CS-15/2018 contract in the offshore Sureste Basin. The approved modified exploration plan includes the confirmation of the Xaxamani 1 discovery on the block through the drilling of the Olmeca prospect, now named the Xaxamani 2EXP well with a modified location with respect to the discovery well. If successful, then there will be an evaluation plan proposed. The operator maintained two possible drilling scenarios for the block pending results of the Olmeca prospect. On 12 April 2019, the CNH officially approved of the Talos farm-in to the Hokchi operated CNH-R03-L01-AS-CS-15/2018 contract. The new working interest breakdown in the contract is Hokchi operator with 75% working interest and Talos with 25% working interest. On 27 June 2018, Hokchi Energy (Pan American) with 100% working interest was granted an official PSC contract award for the 264.24 sq km CNH-R03-L01-AS-CS-15/2018 contract from the CNH-R03-L01/2017 Bid Round. The company bid the maximum state take of 65.00% over the minimum of 22.5% for the Area 31 block and a work units factor of 1 equivalent to one well. There were two other bids for the block. The second highest bidder was the consortium of ENI and Lukoil who bid 42.35% state take and 1 additional work units factor. On 27 March 2018, Pan American Energy with 100% working interest was granted a preliminary award for the contract.

Mexico (Salina Sub-basin (Sureste B.)) Xaxamani 1

In April 2019, Lukoil-subsidiary Ritek discovered a new oil pool in the Tsentralnoye field in Khanty-Mansiysk (Yugra) Autonomous Okrug (Western Siberia). New-pool wildcat Tsentralnaya 1, drilled to 3,187 m in 2016-2017, tested oil at a rate of 31 b/d from the Bazhenov-Abalak Formations (Oxfordian-Berriasian) perforated at 2,612-2,638 m. The well has been suspended until next winter. Tsentralnoye, discovered in 1987, is located in the Ural-Frolov Province. Before the reported pool, recoverable 3P reserves of a single pool in the Tyumen Formation Unit Yu4 (Middle Jurassic) were estimated at 26 MMbbl of oil.

Russia (North Caucasus Platform) ? op. by ROSNEFT DG (100.0%) in Tsentralnoye block

In late January 2020, Red Willow Offshore acquired 5% WI from CL&F Offshore in Green Canyon blocks GC 943 (G36060) and GC 944 (G36061). The blocks are sited 16km southeast from Occidental Petroleum's oil producing Heidelberg Field, which was discovered in January 2009 and commenced production in January 2016. The transaction is effective as of 1 December 2019. Following completion of the transaction, equity in GC 943 and GC 944 is now shared between LLOG Exploration Offshore (0.35% WI + Op), Ridgewood Monarch North (35%), Houston Energy (5%), Red Willow Offshore (17.5%), LLOG Bluewater Holdings (34.65%) and CL&F Offshore LLC (7.5%).

Red Willow Offshore acquired 5% WI from CL&F Offshore in Green Canyon blocks GC 943 (G36060) and GC 944 (G36061). The blocks are sited 16km southeast from Occidental Petroleum's oil producing Heidelberg Field,

P2343 / block 10/1b, Frigg (abandoned) field area, P&A 1 Dec '19, West Phoenix released to 15/3-12 S (Sigrun Øst) (ref. DEA 4 Dec '19: spudded on 3 Dec).

United Kingdom, P2343

JKX has agreed on terms for the sale of its Hungarian subsidiary, Folyopart Energia / Riverside Energy, to Starhol Holding Ltd for USD 2.9 MM cash. Completion is pending receipt of Ukrainian anti-monopoly consent, likely in 4-8 weeks. Riverside has several mining plots* and a dormant production facility. Proceeds will be used to fund ongoing ops in Ukraine. * Emod V (100 sq km), Hajdunanas IV (28 sq km), Hajdunanas V (7 sq km), Jaszkiser II (6 sq km), Pely I (18 sq km) + Tiszavasvari IV (46 sq km) in NE Hungary.

JKX has agreed on terms for the sale of its Hungarian subsidiary, Folyopart Energia KFT / Riverside Energy KFT to Starhol Holding Ltd for USD 2,9 MM.

On 4 December 2017, ExxonMobil announced that its wholly owned subsidiary ExxonMobil Exploration and Production Mauritania Deepwater Ltd was awarded blocks C-14, C-17 and C-22 in deep waters of the M S G B C Basin. ExxonMobil operates the blocks with a 90% interest. Partner is Société Mauritanienne des Hydrocarbures et du Patrimoine Minier with 10%. ExxonMobil will start exploration work with analysis of existing data and the acquisition of seismic. Blocks C-14, C-17 and C-22 cover together around 38,000 sq km around 200 km off the Mauritanian coast in water depths of 1,000 to 3,000 m. C-14 lies outboard of Kosmos C-13, it is undrilled. C-17 lies outboard of Tullow’s C-18 and Total’s C-9, it is undrilled. C-22 lies outboard of Tullow’s C-18, it contains the Flamant 1 well which was abandoned, dry, by Dana in 2006.  

Mauritania (Senegal (M.S.G.B.C.) B.) (It's a petroleum rights. Please summarize by yourself). In IHS database: C-13 op. by BP (62.0%, KOSMOS EN 28.0%, SMHPM 10.0%) to be check.C-18 op. by TULLOW (90.0%, SMHPM 10.0%) to be check.C-9 op. by TOTAL (90.0%, SMHPM 10.0%) to be check.

Energean's acquisition of Edison is hoped to close asap in 2020. EdF-controlled Edison’s upstream division has interests at home in Italy, Croatia, Egypt, Norway + the UK offshore (the NS assets to be sold to Neptune. Algerian assets have however now been excluded from the deal.

Energean's acquisition of Edison is hoped to close asap in 2020. EdF-controlled Edison’s upstream division has interests at home in Italy, Croatia, Egypt, Norway + the UK offshore (the NS assets to be sold to Neptune. Algerian assets have however now been excluded from the deal.

UK Oil and Gas Plc announced on 7 August 2019 that it has agreed to acquire Magellan Petroleum (UK) Investment Holdings Limited 35% interest in PEDL 137 and PEDL 246 which hosts the Horse Hill field for a total consideration of GBP 12 million. Magellan is owned by Tellurian Investments LLC. Following completion of the deal UKOG Horse Hill’s net interest will increase from 50.635% to 85.635%. The deal will give UK Oil and Gas full operatorship for the forward drilling programme and production schedule. Following completion of the deal the drilling of the HH-2/2Z Portland horizontal well will follow shortly. Horse Hill is located in the Weald Basin and comprises of two fractured limestone members within the Kimmeridge section and an overlying Portland Sandstone reservoir which have all flowed oil. The field was discovered back in 2016. Extended Well Tests and production has been run on the field since 2018. In late summer 2019 it was reported that in total, from all horizons 60,186 barrels of oil had been produced. The drilling of HH-2/2Z is planned to commence in later summer 2019.

UK Oil and Gas Plc announced on 7 August 2019 that it has agreed to acquire Magellan Petroleum (UK) Investment Holdings Limited 35% interest in PEDL 137 and PEDL 246 which hosts the Horse Hill field for a total consideration of GBP 12 million.

Nim 2568-9 EL, Lower Indus onshore, P&A dry (tested) at TD 2,503m mid-Mar '20, co. N-2 rig. OGDC (op), partner GHPL.

Katiar 1 nfw. within the Nim 2568-9 EL onshore concession, P&A, after failed to encounter hydrocarbons. TD=2503 m.

Block III,  3,217 sq km in the Nord-Kivu province (E. DRC), is open for farmin ahead of explo drilling in the N. part of the block.  Semliki (op), partner SNH. * Semliki Egy = DigOil – Efora Egy JV.

Block III, 3,217 sq km in the Nord-Kivu province (E. DRC), is open for farmin ahead of explo drilling in the N. part of the block. Semliki (op), partner SNH. * Semliki Egy = DigOil – Efora Egy JV.

Tarba Energia will acquire the 100% interest held by Petroleum Oil & Gas Espana (POGESA) in the El Romeral-1, El Romeral-2 and El Romeral-3 production concessions located to the east of Sevilla in the Guadalquivir Basin. The deal, which was signed in December 2019 with an economic date starting in July 2019, will be effective upon approval of the license transfer by the authorities. The deal involved an initial consideration of EUR 750,000 (USD 837,000) plus further deferred considerations of EUR 250,00 (USD 279,000) for each of the next three wells to be drilled in the concessions. Warrego Energy, which currently holds 85% of Tarba Energia, funded the initial consideration and Prospex Oil and Gas – the other shareholder in Tarba Energia – acquired 49.9% in the project by funding Warrego Energy accordingly (through the issue of a second class of Tarba shares). The three blocks, covering a total area of 310 sq km, encompass five one-well Miocene gas fields out of which three - Ciervo 1, Santa Clara 1 and Sevilla 1- are currently in production and two - Rio Corbones 1 and Sevilla 3 - are shut-in with a low-cost workover potential. The gas is converted in electricity by an 8.1 MW power station owned the operator of the license. As per a 2019 independent reserves and resources assessment, the three producing fields hold remaining reserves of 0.3 Bcf. In addition to the five fields, the tracts cover two undeveloped discoveries with 2C contingent resources estimated at 5 Bcf and 13 nearfield prospects identified on 2D seismic and supported by AVO analysis with unrisked prospective resources (2U) estimated at 90 Bcf. The El Romeral contracts were awarded to group led by Repsol on 28 July 1994. After numerous interest change, Petroleum Oil & Gas Espana became the sole rightholder of the tract in December 2017. The contracts are valid until 2024 and can be renewed twice for a ten-year term. The ultimate expiry date is 28 July 2044. Subject to regulatory approval, Tarba Energia will hold a 100% interest in the El Romeral-1, El Romeral-2 and El Romeral-3 production concessions.

Tarba has agreed to acquire Petroleum Oil & Gas España's 100% in the El Romeral-1, -2 & -3 prod. leases totalling 310 sq km in Andalucía.

TAQA Bratani acquired a 40% interest from RockRose in licence P205 (block 16/6a). The block contains the northwest extension of the Brae West field. The deal completed on 14 September 2018. The OGA reported that West Brae operator, Marathon Oil, sanctioned a project on the field in 2018. The field was discovered in 1975 and started producing in 1997. The field is located on the eastern margin of the Fladen Ground Spur. Following completion of the deal interest in the licence is now held by TAQA Bratani Ltd (80% + operator), TAQA Bratani LNS Ltd (20%) and RockRose Energy UKCS4 Ltd (0%).

RockRose has assigned its 40% stake in licence P205 block 16/6a containing the western extent of the West Brae-Sedgwick Field to operator TAQA.

Petrobras has agreed to PetroRio taking over its remaining 30% in the Frade field for USD 100 MM + a contingent USD20 MM*. Frade lies in deepwaters of the Campos Basin and is now wholly-owned by PetroRio. * an additional USD 20 MM will be due contingent to a potential new oil discovery not included in the previously disclosed Frade revitalisation plan.

Petrobras (->0%) has agreed to PetroRio (->100%) taking over its remaining 30% in the Frade field for US$120 MM.

On 1 November 2017 Oil Search Ltd. a company with holding in Papua New Guinea has signed an agreement with Armstrong Energy and GMT Exploration Company which will see the company acquire a 25.5% interest in the Pikka Unit and a 37.5% interest in the Horseshoe block both of which are located on the North Slope of Alaska. The deal marks the first entry of Oil Search into Alaska who will also assume operatorship of the acreage in June of 2018. Oil Search paid USD 400-milliion for the acquisition and has an option to purchase all the remaining interest of Armstrong and GMT in both the Pikka Unit and Horseshoe block until June 2019 for an additional USD 450-million. Oil Search will carry Armstrong and GMT’s share of cost of appraising the discoveries through 2018/2019, if it has not exercised the option to acquire the remaining interest in the properties. In addition to the acquired interest in properties with discoveries the company has also agreed to jointly explore and develop other opportunities in the area. If approved the working interest in the Pikka Unit will be Oil Search 25.5%, Armstrong Energy 19.125%, GMT 6.375%, Repsol 49%. The Horseshoe will be Oil Search 37.5%, Armstrong Energy 28.125%, GMT 9.375%, Repsol 25%. Exploration acreage interest will be Oil Search 25.5%, Armstrong Energy 37.125%, GMT 12.375%, Repsol 25%. The Hue shale play acreage will have the following interest of Oil Search 37.5%, and Armstrong Energy 62.5%. The acquisition is subject to the standard US regulatory approvals, including approval by the Committee on Foreign Investment in the US (CFIUS).

United States (Taroom Trough (Bowen - Surat B.s)) Horseshoe

In late January 2020, Khalda Petroleum Co (Khalda) abandoned Isis 18, an outpost well of the Isis field in the Khalda block, Shoushan Sub-basin (Northern Egypt Basin). The well, which was spudded on 6 January 2020 was drilled to a TD of 3,292 m. The operator was targeting objectives in the Cenomanian Bahariya Formation and in the Paleozoic units. The Isis field was discovered in 2004 after the new field wildcat Isis 01 tested oil in the lower and upper members of the Bahariya Formation. It was brought on-stream in late 2004 and further developed through the drilling of eight wells. Khalda implemented an improved recovery plan including the drilling of four water injectors between 2007 and 2008. The Khalda block, which extends over 959 sq km includes numerous exploratory dry wells and oil and gas producing fields (e.g., Hayat, Kenz, Yasser, Shrouk B, Shrouk East). It was granted Khalda, a JV between EGPC (50%), Apache (33.5%) and Sinopec (16.5%) in January 2013.

Khalda Petroleum Co abandoned Isis 18 outpost well, Isis field, Khalda block, Northern Egypt Basin

CaribX (UK) Limited announced on 28 January 2020 its plans for an exploration well during 2021-2022 in the Main Cape Block, located in the Mosquitia Basin. The last offshore well drilled in Honduras was the Castana 1 (TD 3,812m) drilled by Texaco and abandoned dry in 1980 in the Tela Basin (Caribbean Sea). Earlier, Union Oil's 1973 offshore wildcat Main Cape 1, located in the Mosquitia Basin, had oil shows in the interval 2,711 - 2,817m in Eocene Mosquitia Formation carbonates. The well was not appraised. The interest holders are the operator AziLat Petroleum Ltd with 45% and CaribX with the remaining 55%. CaribX increased its interest in the Main Cape Block, from 15% to 55% - subject to governmental approval. During 2019, 50% of the 33,950 sq km offshore block was relinquished. As of July 2017, AziLat acquired 80% interest in the Main Cape Block (former Patuca and Mosquitia) from Shell. The block was secured by BG Group in 2013, with the Production Sharing Contract (PSC) approved by the Honduras Congress in May.

CaribX (UK) has increased its interest in the Main Cape Block, from 15% to 55% (AziLat Petroleum Ltd ->45%).

Khalda Offset concession (Khalda Ext III), Northern Egypt Basin, drilled mid-Apr – late Jun '20, susp w.o. test. PTD was 5,090m, targets Alam El Bueib, Safa + Ras Qattara fm's.

Egypt (Northern Egypt B.), Goose-1 nfw, Khalda op. by APACHE (67%), SIPC (33%), EGPC (0%), suspended w.o. test. PTD was 5,090m, targets Alam El Bueib, Safa + Ras Qattara fm's.

Dec ’18, Lion had agreed to acquire Gulf’s 16.5% stake in the Seram (Non-Bula) PSC, 1,305 sq km mainly onshore Seram island. This was cancelled as a result of administrative restrictions from the authorities, details of which can be found from Lion. Partners otherwise Citic (op), Petro Indo Mandiri  + GHJ:

Lion had agreed to acquire Gulf’s 16.5% stake in the Seram (Non-Bula) PSC, 1,305 sq km mainly onshore Seram island. This was cancelled as a result of administrative restrictions from the authorities, details of which can be found from Lion.

Further to DEA 6 Jul ’18, officials confirmed today that Pertamina will operate the 6,264-sq km Rokan block in Central Sumatra under a gross split PSC, for 20 years starting from the expiry of Chevron’s contract in Sep ’21 until ’41.

Further to DEA 6 Jul ’18, officials confirmed today that Pertamina will operate the 6,264-sq km Rokan block in Central Sumatra under a gross split PSC, for 20 years starting from the expiry of Chevron’s contract in Sep ’21 until ’41.

Nyarmeyskiy licence, Kara Sea, W. Siberian Basin, 2018 well to PTD 2,300m,  4.137 Tcfg 3P booked, ops terminated Oct ’18, Arkticheskaya SS.

Nyarmeyskoye discovery Nyarmeyskiy licence, Kara Sea, W. Siberian Basin, 2018 well to PTD 2,300m, 4.137 Tcfg 3P booked, ops terminated Oct ’18

Romgaz disclosed on 14 August 2020 that it had plugged and abandoned the Podeni 1 exploration well in the RG 1 Transilvania Nord block during the second quarter of 2020. The well, which was drilled about 50 km to the east of the city of Cluj-Napoca had a planned total depth of 1,750 m. The Transilvania Nord block contains more than 30 gas fields or gas discoveries. The nearest field to the Podeni well is Delureni, located about 5 km to the southeast. The field was discovered in 1976 and put onstream the following year. It has six reservoirs in the Badenian Spirialis Marl Member at depths between 1,550 m and 2,100 m. The RG Transilvania permit was awarded to Romgaz (100%) on 8 October 1997. It is divided into three blocks, RG 1 Transilvania Nord, RG 2 Transilvania Centru and RG 3 Transilvania Sud. The RG 1 Transilvania Nord encompasses 2,008 sq km.

(Transylvanian B.) Podeni 1 op. by ROMGAZ (100%) in RG 01 Transilvania Nord block, P&A results n/a, The well, was drilled about 50 km to the east of the city of Cluj-Napoca had a planned total depth of 1,750 m.

Khaskeli ML (Badin I), Lower Indus onshore, TD 1,753m, oil discovery + tested, results yet n/a, target Lower Goru. TCPDC-2001 rig.

Sukhi 1 op. by UEPL (100%) in Khaskeli ML (Badin I), oil disc. + tested, results yet n/a, target Lower Goru.

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

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

Ledong block in Yinggehai Basin SW of Hainan, WD 80m, TD 4,000m+, HPHT well completed end-Jan ’18, results not reported, Haiyangshiyou 944 JU.

Ledong 10-2-1 (LD 10-2-1) nfw Ledong block in Yinggehai Basin SW of Hainan, WD 80m, TD 4,000m+, HPHT well completed end-Jan ’18, results not reported,

In mid-March 2020, Navitas Petroleum, via its local subsidiary ShenHai, farmed-out a 30.95% working interest share in Walker Ridge blocks WR 51, WR 52 and the northern half of WR 53 (8.852% in the southern half), site of the Shenandoah project, to LLOG Deepwater Development. The Shenandoah project is situated ~322km south of New Orleans, and is presently in the FEED phase, with LLOG targeting an FID in H1 2020 and first production in 2023. Shenandoah leases are currently held under a Suspension of Production ('SOP') and will be developed using a new FPS. The forward play for Shenandoah is to drill multiple wells to develop the estimated 100-400 MMbbls, targeting previously discovered oil-bearing Upper and Lower Wilcox-reservoirs. The oil and rock qualities for the Shenandoah development are both best-in-class for the emerging Wilcox production trend. The original Shenandoah discovery well, G25232 1 BP2, was drilled in late 2008/early 2009 on Block WR 52 and encountered more than 91m (300 feet) net of Inboard Early Tertiary oil pay. Following completion of the April 2020 transaction, equity in WR 51, WR 52 and the northern half of WR 53 is now shared between Beacon Offshore Energy Development (15.95% WI), ShenHai (53.1%) and LLOG Deepwater Development Company III (30.95%). Equity in the southern half of WR 53 is split between Beacon Offshore Energy Development (4.556%), ShenHai (86.592%) and LLOG Deepwater Development Company III (8.852%). LLOG Exploration Offshore is the operator of all three leases.

Not Found

YPF' suspended and results unreported for its Barreal Grande 1H New-Field Wildcat (NFW) horizontal well in the Loma La Lata-Sierra Barrosa Block – Neuquén Basin. During early-March 2020 after conducting fracking operations and starting its initial flow-back and extended testing it conducts on its horizontal, unconventional wells – operations were suspended. The well is in the south-eastern corner of the block in an area that hasn't been tested for Vaca Muerta potential. YPF SA is operator of the Loma La Lata-Sierra Barrosa contract with 100% working interest. The operator perforated the horizontal section from 2,920 m to 4,892 m and fract it with 25 stages. The well was spudded on 24 June 2019 with a planned total depth (PTD) of 4,297 m and the primary objective was the unconventional Vaca Muerta Formation shale. The NFW reached a total depth (TD) of 4,940 m measured depth (MD) in mid-August 2019. The Loma La Lata-Sierra Barrosa Block covers 1,643.53 sq km in the Neuquen Embayment and Huincul Uplift portions of the Neuquen Basin. The Loma la Lata-Sierra Barrosa Block covers an area of 1,989 sq km and was awarded 100% to YPF SA as a Production Concession-YPF Area on 14 November 1992. The Argentine Government approved the 10-year extension of the Loma la Lata-Sierra Barrosa Contract in advance through Decree 1,239/2000, with an effective date of 3 January 2001. The extension period of ten years gives the contract a final expiry date of 14 November 2027 from the original 14 November 2017. A complex agreement was reached between the Argentine Federal Government, the Provincial Authorities of Neuquen and Repsol-YPF whereby the operator will pay approximately USD 300 million to the Federal Government and invest USD 8 billion in the Loma la Lata-Sierra Barrosa Production Concession through 2017 in exchange for being granted the 10 year extension.

Argentina (Neuquen B.) Barreal Grande 1H New-Field Wildcat (NFW) op. by YPF (100%) in Loma la Lata-Sierra Barrosa block, suspended and results unreported.

Further to DEA 23 Jan '20, it is now reported that ONGC has bagged 24 bids for 14 contract blocks comprising 50 marginal fields under its Marginal Nomination Fields (MNF) round 2019. The offer comprised 64 marginal fields within 17 onshore contract blocks, 3 of which (14 fields) failed to attract a bid. Please refer to GEPS for latest list of bids. The January info suggested ONGC netted 28 bids from 12 (other reports suggest 13) private companies to participate in 50 marginal producing fields making up 14 clusters upon the deadline on 17 Jan '20.

ONGC has bagged 24 bids for 14 contract blocks comprising 50 marginal fields under its Marginal Nomination Fields (MNF) round 2019. The offer comprised 64 marginal fields within 17 onshore contract blocks, 3 of which (14 fields) failed to attract a bid. Please refer to GEPS for latest list of bids.

According to official reports on 29 July 2019, Qatar Petroleum (QP) has taken 40% of Total's stake in both Orinduik and Kanuku blocks in Guyana in which equates to 10% in each block. Specifically, Orinduik block will have along with QP’s 10%, Eco (Atlantic) (15%), Total (15%) and operator Tullow at 60%. Kanuku block will be partnered with operator, Repsol (37.5%), Tullow (37.5%), Total (15%) and now QP at 10%. No financial details were revealed. The transaction is expected to be closed after additional pending approvals. Orinduik block (1835 sq km) is located offshore in the Guyana Basin, adjacent to south central area to ExxonMobil’s operated Stabroek block and adjacent northwest of Repsol-operated Kanuku block. On 4 July 2019 Tullow Oil spudded the Jethro-Lobe 1 new-field wildcat (NFW) well on the Orinduik Block in the offshore Guyana Basin. Kanuku block (6530 sq km) is located offshore Guyana Basin, adjacent southeast area of Stabroek and adjacent south of Orinduik block. Background Information On 4 July 2019 Tullow Oil spudded the Jethro-Lobe 1 new-field wildcat (NFW) well on the Orinduik Block in the offshore Guyana Basin. Jethro is being drilled with the “Stena Forth” drillship (DS) in water depths of some 1,350 m (4,429 ft). The well is targeting Lower Tertiary stratigraphically trapped canyon turbidite and will be drilled down to the Cretaceous section. While the neighboring Stabroek Block’s Hammerhead 1, located some 7 km east of Orinduik, discovered Cretaceous reservoirs, it also proved that the Tertiary section reveals commercial hydrocarbon accumulations in stratigraphic sand traps. Jethro-Lobe 1 has an estimated 40 days’ drilling time, then next up is the Joe prospect slated for Q3 2019 on the acreage. On 14 February 2019 partner Tullow reported Q3 2019 plans for the Repsol-operated Kanuku Block located offshore Guyana Basin. The Carapa prospect will be drilled in approximately 70 m of water with a jack-up rig soon to be contracted. Carapa targets Cretaceous objectives with resource potential estimates of some 200 MMbo.

Qatar Petroleum (QP) has taken a 10% stake in each of the Orinduik and Kanuku blocks, from 40% of Total's stake in each.

It was reported in December 2017 that EnQuest has acquired Dana’s 50% interest in block 21/19a Eagle Area (licence P238) giving EnQuest 100% ownership in the block. The deal completed on 28 September 2017. The Eagle oil discovery was made in 2016. EnQuest encountered a 20 m Fulmar oil bearing section with excellent reservoir properties. The discovery was thought to be similar in size to the Gadwall field (6 MMb). Eagle is located in the Greater Kittiwake Area which comprises the Kittiwake (P351), Gadwall, Grouse, Mallard (P238) and Goosander (P073) fields. The Kittiwake field was discovered in 1981 before coming onstream in 1990. Grouse was also discovered in 1981 but didn’t come onstream until 2008. Mallard was the next field to be discovered in 1990 and was brought onstream in 1998. Gadwall was discovered in 1996 and began producing in 2005 and finally Goosander was discovered in 1998 and started producing in 2006. The fields (apart from Kittiwake) are tied-back to the facilities located at Kittiwake. The Kittiwake platform has oil capacity for 29,000 Bo/d and a water injection capacity of 57,000 Bo/d in a water depth of 85 m to 90 m. Oil is exported via a 10” 33 km pipeline to the Forties platform before being transported to shore at Cruden Bay via the Forties Pipeline System. Following completion of the deal interest in 21/19a Eagle Area (licence P238) is held solely by EnQuest Heather Limited.

EnQuest (->100%) has acquired Dana’s 50% interest in licence P238 (block 21/19a Eagle Area).

Guhlen concession within the Lübben block in Brandenburg, E. Germany, 2018-2019 well to TD 3,150m, sidetrack of Guhlen-1/1a (which encountered o/g/c), tested, now reported to be P&A'ing as 'unsuccessful'.

Guhlen-1b appr Guhlen concession within the Lübben block in Brandenburg, E. Germany, 2018-2019 well to TD 3,150m, sidetrack of Guhlen-1/1a (which encountered o/g/c), tested, now reported to be P&A'ing as 'unsuccessful'.

Lalla Mimouna Nord block, Rharb in E. Morocco, final in 9-well programme in Morocco, gas discovery, TD 1,158m, 16.4m net pay in Miocene H-9 sequence, under completion as a conventional gas producer, testing yet planned. SDX (op), partner Onhym. www.sdxenergy.com.

Morocco, Lalla Mimouna Nord