Vista Oil & Gas in a webcast on 28 July 2021 discussed its Q2 2021 results for assets in the Neuquen Basin. The company highlighted what it calls a turning point in the company’s performance during this period. Production reached 39.9 Mboe/d, a 67% increase compared to the same period of 2020, and exceeding for the first time its pre-pandemic production rate of 35 Mboe/d. Crude production rose 101% to 31.5 Mbo/d, mostly due to the great performance of the Bajada del Palo Oeste shale project, where a strong increase was shown after the tie-in of pad #7 in this field in March. Natural gas production improved by 5% compared to Q2 2020 with 1.26 MMcm/d and 10% against Q1 2021 (1.14 MMcm/d) but was still lower than Q1 2020 production (1.41 MMcm/d). Gas production progress was related to the Plan Gas.Ar company commitments. Revenue increased by 223% also year to year. The significant 107% increase of crude prices since Q2 2020 and and a 59% in average natural gas prices also helped earnings thanks to the Plan Gas.Ar winter prices. 17% of crude oil sales were exports. The company lowered lifting costs per boe by 15% from US$ 8.6 per boe in Q2 2020 to US$ 7.3 in Q2 2021 and also showed a 3% improvement compared to Q1 2021 at US$ 7.5/boe. Adjusted EBITDA increased 904% year to year driven by the boost in revenues with help from stable lifting costs. In the Bajada del Palo Oeste Block the cost per well dropped 42% from US$ 16.6 million in 2019 to the current US$ 9.6 million. In June 2021 pad #8 was connected as the third pad of 2021, with a total of 20 wells spud, all ahead of the original plans for the year with four planned pads and 16 wells. Two wells targeted the La Cocina and two wells targeted the Organico subplays of Vaca Muerta. The average lateral length drilled was 2,611m and an average of 54 frack stages were completed per well. Vista is currently drilling the last well of pad #9, with completion and connection expected by the end of Q3 2021. Drilling and completion speed were also ahead of plan with the possible tie-in of a fifth pad in Q4 2021. The current 39 Mboe/d production was also superior of the original guidance of 37 Mbo/d. Vista signed during this period a joint venture agreement with service company Trafigura in Bajada del Palo Oeste for the development of five pads of four wells each. Vista remains 100% operator with 80% of capex and production while Trafigura has a 20% share in those activities. The company divested 10% WI of the Coiron Amargo Sur Oeste concession to Shell for US$ 21.5 million. The implied valuation of the field was about US$ 13,000 per acre as one of the highest rates for Vaca Muerta. After the news Vista’s stock jumped 8% due to strong production, lower costs and accelerated growth. The company also targets a 30% reduction in green house gas (GHG) emissions year to year to approximately 29 kg of CO2 per boe in 2021. During the webcast Vista executives were planning to drill a number of new wells in the Aguila Mora Field and depending of their performance could search for a partner to provide funds for facility expansions there. In face of the Q2-2021 results Vista will invest 13% more than originally planned for 2021, reaching US$ 310 million.
Petrobras on 28 July 2021 filed a gas show report with the ANP for the 1BRSA1379DESS new field wildcat on the Espirito Santo Basin ES-M-669 Block. The well was spud on 6 April with the Constellation Brava Star drillship in a water depth of 2,366m. The high impact well targets the Monai Prospect in the pre-salt portion the basin. Petrobras is operator of the block with 40% while partners Equinor 35% and Total 25% hold the remainder. The pre-salt layer in the Espirito Santo Basin has never been penetrated. The well also has an unusually deep planned total depth of 8,150m. Previously ExxonMobil drilled a dry hole on this block in 2002 with a total depth of 5,109m. This well targeting the Monai prospect will be key for the partners in evaluating the other exploration concessions in the offshore Espirito Santo Basin which thus far have not generated much exploration interest. Seismic data quality has been insufficient to assess the existence of plays in the pre-salt section in the areas adjacent to ES-M-669 so further research is needed to determine their potential. Previously in February 2019, Petrobras planned to drill the Monai prospect that year. The Round 11 Block was awarded on 30 August 2013. An ANP decision in 2018 allowed the deepest commitment well for the Monai prospect to be drilled as an exception and to account for 3,000 UTEs to comply with the minimum exploration program (PEM). The PEM agreed with the ANP foresees the drilling of a well with a total of 3,300 UTEs. Previously in March 2018 the ANP board of directors denied a Petrobras request to extend the exploration periods for the ES-M-596 and ES-M-669 blocks. Petrobras claimed the extensions were needed due to the geological complexity of the blocks. In December 2014 a multi-client 3D seismic survey in the offshore Espirito Santo Basin called Espirito Santo Phase III completed shooting. The survey was shot by the French company CGG for a planned data acquisition of 9,605 sq km. The data was acquired by the Oceanic Champion M/V.
A deal between ExxonMobil and Ecopetrol was finalised on 17 June 2021, whereby Ecopetrol would operate the Unconventional CEPI Platero and Kale blocks, with ExxonMobil acting as partner, according to industry sources in July 2021. The Agencia Nacional de Hidrocarburos (ANH) had launched the Integral Research Pilot Projects (PPII) in 2020, in order to award companies access to carry out unconventional oil and gas pilots. Ecopetrol had picked up the first ever hydraulic fracking project under the Special Agreements for Investigations Projects (CEPI) scheme in late December 2020, with the award of the 4.5 sq km Kale project, carved out of the Ecopetrol operated Magdalena Medio Block. Ecopetrol had been the sole company to nominate an area during CEPI I. A second round of CEPI was run in 2021, and on 4 June 2021, ExxonMobil scooped up the 4.5 sq km Platero project. ExxonMobil had submitted the only bid during CEPI II, even though Ecopetrol, Drummond Energy and Tecpetrol had all qualified. The Platero area was carved out of the ExxonMobil operated VMM-37 Block, some 12km to the southwest of the Kale area. Under the newly agreed arrangement, Ecopetrol operates the Kale Block with 62.5% WI, whilst ExxonMobil has gained the remaining 37.5% WI. In the Platero Block, Ecopetrol now operates with 37.5% WI whilst ExxonMobil has retained 62.5% WI. In late October 2019, Ecopetrol agreed a deal with US company Oxy to form a JV in the famed US onshore Permian Basin. The Colombian state company wanted to use the JV as a vehicle to increase its working knowledge in unconventional hydrocarbon fairways. Oxy subsequently sold its onshore Colombian assets to the Carlyle Group in December 2020, exiting the onshore of the South American nation. Ecopetrol will now be partnered with an experienced US onshore unconventional partner as it looks to kick start the fracking industry in Colombia.
On 22 July 2021, Iran’s outgoing President Hassan Rouhani officially opened Iran’s Jask oil terminal on the Gulf of Oman coast which will allow the country to ship crude oil without the need for tankers travelling through the world’s most strategic oil chokepoint, the Strait of Hormuz. The terminal currently has a capacity to transfer 300,000 bo/d, with this set to rise to 500,000 bo/d by December 2021, 750,000 bo/d by January 2022, and 1 MMbo/d by March 2022 when it becomes fully operational. The Managing Director of the Iranian Oil Terminals Company (IOTC) said the first shipment of 650,000 barrels of oil was loaded at the terminal on 25 July 2021. The Jask oil terminal is connected by the Goreh-Jask oil pipeline. The Goreh-Jask project, which is aimed at expanding the oil transport capacity in the south of the country to 1 MMbo/d, was inaugurated in late June 2020 by President Hassan Rouhani. Addressing the inaugural ceremony of the project, President Rouhani said this project was currently the country’s most strategic project, saying: “Our oil exports will no longer be only dependent on the Strait of Hormuz. This is the first time in Iran’s history that such a thing is being done”. The 42-inch, ~1,000km pipeline is transporting oil from the Goreh oil terminal in the Bushehr Province on the Persian Gulf coast to the Jask oil export terminal in the Hormozgan Province on the coast of the Gulf of Oman, thereby by-passing the need for ships to traverse the Strait of Hormuz in the Gulf. The first phase of the pipeline reportedly has a capacity of around 300,000 bo/d. The installation of the first single point mooring (SPM) system at the terminal gives an initial capacity to transfer 7,000 cm of oil per hour. The Minister of Petroleum said previously the Persian Gulf Star Refinery will also be connected to the pipeline, giving an option to export up to 600,000 to 700,000 bo/d. According to the Minister, the estimated cost of the pipeline is US$ 850 million. The first phase of the Jask oil export terminal was completed concurrently with the first phase of the pipeline. The new-build terminal will be the country’s second largest oil export terminal after the Kharg Island terminal (in the Gulf), which currently accounts for around 90% of Iran’s oil exports. The terminal is planned to have up to 20 storage tanks, each with a half-million-barrel capacity.
On 28 July 2021, PETRONAS awarded the 2,015 sq km Greater Sarawak Basin block SK-437 to a consortium comprising operator Sarawak Shell Bhd holding 85% and partners Petronas Carigali Sdn Bhd (PCSB) and Petroleum Sarawak Exploration and Production Sdn Bhd (PSEP), each having 7.5%.The block is located in 50m of water and contains the 1970 J 2 and the 2008 KT gas discoveries. The four-year initial commitment is understood to comprise the acquisition of new 3D seismic with a one well drilling programme. Shell is potentially consolidating its assets in Malaysia as of 2021, looking to relinquish its position in the SK-307 and the 2011 Baram Delta EOR PSCs, whilst concurrently picking up new assets in the country. In 4Q 2020, the supermajor reported that it was concentrating its upstream unit on nine core regions, which generate 80% of the company’s cash flow. These nine regions include Brunei and Malaysia. SK-437 is a portion of a larger historical block SK-305. The 9,892.7 sq km SK-305 was relinquished in 4Q 2017 by then sole stakeholder Petronas Carigali Sdn Bhd. SK-305 had been awarded to PCPP Joint Operating Co, a consortium comprising Petronas Carigali Sdn Bhd (40%), PT Pertamina Hulu Energi (30%) and PetroVietnam Exploration Production Corp (30%) in mid-June 2003 with partners Pertamina EP and PVEP surrendering their equity to Petronas Carigali as of 4Q 2016. Before the full relinquishment of the block in November 2017 (TBC), PCSB awarded an Engineering, Preparation, Removal and Disposal (EPRD) contract to Sapura Energy (now SapuraOMV) with the decommissioning contract worth US$ 10.2 million.
Pemex’s Racemosa 1 NFW, located on the onshore AE-0142-Comalcalco contract area, discovered an estimated 377.2 MMboe in Cretaceous Age reservoirs, following a recent spate of less-than-hoped for exploration results. Pemex, in Q2 2021, reached final TD of 5,719m. According to sources at the time, the well tested an estimated 2,200 bo/d. Pemex had encountered numerous issues while drilling the well. In late 2020, Pemex went up-hole to 5,574m, due to issues in the well.
In September 2020, industry sources indicated that Pemex would sidetrack the NFW, due to problems within the wellbore. The well had been drilled to 5,951m by mid-month. In mid-August 2020, Pemex experienced issues with hole stability at 5,595m, whilst drilling the 5-7/8″ section. The drillbit was pulled to the surface and Pemex continued drilling to 5,850m, after changing the tool. In early July 2020, reports stated that 5-7/8″ casing had been set to 5,261m.
In June 2020, Mexico’s Comisión Nacional de Hidrocarburos (CNH) approved a petition from Pemex to modify its current drilling programme for Racemosa 1. Pemex is understood to have experienced issues while drilling and sought approval to change the well’s trajectory. Racemosa 1 was originally planned to drill with a “J” type trajectory to a 6,290m PTD, however the NFW was changed to a “S” type directional well with a 6,451m PTD. The well targeted the Cretaceous and Jurassic sequences.
The Racemosa 1 well originally had two primary objectives, both of which were located at subsurface depths of 5,130-5,180m (Cretaceous) and 5,780-5,840m (Jurassic). While details are scant, the updated primary objectives are thought to be located below 4,709m (Cretaceous) and 5,559m (Late Jurassic Kimmeridgian, “JSK”). As a part of this modified plan, Pemex switched out rigs. The company used the “IPC-504” drilling unit instead. Pemex spudded Racemosa 1 in March 2020 using the “Pemex 1503” rig, and the well is thought to have been suspended to change rigs and retool the drilling programme. The well targeted prospective resources of 69 MMboe and had a 38% chance of geological success.
In late July 2021, state-run Pemex had returned to the drafting board to prioritise the Wakax 1 prospect on the AE-0160-Chalabil contract area under a two-year US$ 35 million Baseline programme. Two other prospects, Caan 801 and Ektal 201 will be drilled under a more ambitious US$ 102.7 million Incremental programme. The proposed Wakax well site straddles the A-0001-3M-Campo Abkatun (Abkatun Field) and the AE-0160-Chalabil tract on the Mexican shelf. Regulators are in the process of transferring part of the acreage from Abkatun over to Chalabil for future planning.
Mexico’s Comisión Nacional de Hidrocarburos (CNH), in early December 2019, approved exploration plans submitted by Pemex, as part of the company’s strategy to explore the lion’s share of the 64 blocks that it was awarded on 28 August 2019. The Mexican Energy Secretariat (Sener) granted the state-run company rights to 64 entitlements, spanning the onshore to deepwater sector. The approval came the day after Pemex was due to lose access to 52 blocks, which it obtained in Round Zero in 2014, for not meeting minimum work commitments. Those plans included the AE-0160-Chalabil area. Pemex’s original plan focused on investigating the Brecha Cretaceous and Upper Oxfordian Jurassic in the block. Investments, as of 2019, were pegged at between US$ 119.6 million and US$ 160.8 million.
On 28 July 2021, the Minister for Petroleum Resources disclosed at the 2021 Gas Sector Stakeholders’ Forum in Kano that a new price system for domestic supply obligation (DSO) was to be implemented. The Minister said: “Let me use this medium to announce to this gathering that following the successful negotiation between the Federal government and the Organised Labour Unions, and the detailed review of the gas pricing framework in Nigeria, the price of gas-to-power has been reduced from US$ 2.50/MMBtu to US$ 2.18/MMBtu (domestic supply obligation — DSO) with immediate effect. The outcome of the negotiations and review have been communicated to the relevant stakeholders”. According to the Minister, this action will increase domestic gas utilisation as the mainstay for national industrialisation, attract foreign direct investment, boost government revenue and provide more job opportunities for Nigerians.
Wellesley Petroleum will assign 40% operated interest in North Sea licences PL090 JS, PL248 I & PL925 to Equinor in exchange for 10% non-operated equity in Norwegian Sea licence PL942 and 20% in North Sea licences PL878 & PL878 B from Equinor. The Sale and Purchase Agreement was announced on 26 July 2021 and is subject to regulatory approval.
Equinor is to become operator of PL090 JS, PL248 I & PL925, which covers the Grosbeak and Kallåsen discoveries. Equinor will retake operatorship of PL090 JS, which covers stratigraphies below Base Cretaceous over 4.06 sq km in part of block 35/11, and contains the SW portion of the Grosbeak discovery. Wellesley acquired its 45% operated stake in the licence from Equinor on 30 November 2018. Immediately to the E of PL090 JS is PL248 I, which was partitioned in December 2017 from Equinor-operated PL248 C, but Equinor (then Statoil) did elect to participate when P248 I was created and assigned its 30% operated share to Wellesley. This licence covers 48 sq km over part of block 35/11 and contains the central portion of the Grosbeak discovery. The remaining portion of the discovery is covered by PL925, which was awarded on 2 March 2018 as part of APA 2017 and covers 163 sq km over part of blocks 35/9 & 35/12. Wellesley has operated this licence since its award. The Grosbeak oil and gas discovery was made by 35/12-2 (2009, Wintershall, 2,541m) in Jurassic Sognefjord and Ness reservoirs. This was successfully appraised by Wellesley in 2018 with 35/11-21 S & 21 A. Preliminary resource estimates are between 50-120 MMbo and 600-1,270 Bcfg within the Middle Jurassic Ness and Etive Formations (Fms) and Middle to Late Jurassic Sognefjord and Fensfjord Fms. The plan for development and operation (PDO) is expected to be submitted by the end of 2022 with development to comprise either a subsea tie-back to an existing installation or with a floating production, storage and offloading vessel (FPSO). Wellesley will acquire a further 10% working interest in PL942 which covers 150 sq km over part of blocks 6507/1 & 6507/2. The licence covers the Ørn discovery, which contains an estimated 280-500 Bcfg contingent resources within the Middle Jurassic Fangst Group, Garn and Not Fms. It was discovered by Equinor in 2019 with 6507/2-5 S (4,147m TVD). The PDO is for Ørn is planned for 2022. Wellesley will also acquire 20% in PL878 & PL878 B. PL878 was awarded on 10 February 2017 as part of APA 2016 with the addition of auxiliary licence PL878 B in APA 2020, awarded in February 2021, equity in the two licences is harmonised. The licences cover the shut-in Huldra gas and condensate field, which produced 635 Bcfg and 25.5 MMbc from Middle Jurassic Brent Group sands between 2001 and 2014. There are a further two undeveloped discoveries on the licence: 30/3-9 (2000, Statoil, 4,015m TD) technical gas and condensate discovery in Middle Jurassic Ness Formation and 30/2-5 S Atlantis (2020, Equinor, 4,388m TVD). Atlantis has estimated contingent resources of 19-63 MMboe gas and condensate within Middle Jurassic Brent Group with potential to be developed as a subsea tie-back to the Kvitebjørn facility.
Upon completion of the asset swap, licence equity will be:
The Petroleum Ministry announced that a new bid round for oil and gas exploration is planned by the end of the year. The announcement, at end-July 2021, stated the round will target “high-potential, surrendered and under litigation blocks”. The Federal Minister of Energy Hammad Azhar stated in early July 2021, that new areas will be opening for competitive bidding to push exploration activities in the country and increase local production. There is currently no official document on the acreage available. Previous bid rounds had been released on a near biennial occurrence in the past few years. The 2020 Bid Round has awarded 6 licences, after receiving applications for 15 of the 20 blocks offered. The round launched on 9 October 2020 and closed on 15 January 2021 with applications numbering: 13 blocks from OGDCL; five from Mari Petroleum (MPCL); four each from Pakistan Petroleum Ltd (PPL), Oil & Gas Investment Ltd (OGIL) and Pakistan Oilfields Ltd (POL); two each from Jura subsidiary Spud Energy Pty Ltd, OKTA and Hashoo subsidiary Zaver Petroleum; one block interest from Ocean Pakistan Ltd (OPL).
Interest in offshore Pakistan was somewhat stymied in May 2019 when the high impact deep water NFW Kekra 1, on the Offshore Indus-G 2265-1 EL, failed to encounter hydrocarbons. Kekra had been targeting a 425 sq km Paleocene-aged carbonate play and whilst a reservoir was encountered, it was found to be water-bearing. The high-profile deep-water well had the potential to ignite interest in Pakistan’s offshore hydrocarbon industry. Kekra was drilled by operator ENI (25% interest), ExxonMobil (25% interest) and Pakistani companies Oil & Gas Development Co Ltd (25% interest) and Pakistan Petroleum Ltd (25% interest). The partners subsequently relinquished the Offshore Indus-G 2265-1 EL on 31 May 2020, after a post-drill review was carried out.
The 2018 Bid Round in Pakistan was opened on 13 September 2018 and ran until 26 November 2018. The Director General Petroleum Concessions (DGPC) received bids for all 10 onshore blocks offered. Eight were formally awarded and two were declined.
Ministry of Energy and Mines (MEM) Minister Jaime Galvez also said in his last statement before leftist Pedro Castillo assumed the presidency on 28 July that there is always room for renegotiation of gas export contracts. It is not simple or easy because companies with contracts in Peru are protected by international law and arbitration can be very costly to the state if we impose conditions that are not accepted. Peru and specifically the Castillo administration is expected to ask companies to renegotiate contracts with a greater commitment to increase production of gas especially and invest more in exploration. Investment in exploration has been very low in Peru in recent years. Renegotiation of the gas export contracts is expected to seek higher state take and more exploration investment based on promises made by Castillo during the campaign. Oscar Frias Martinelli heads the transition team for the MEM. Frias is a Mining Engineer from the Pontificia Universidad Catolica del Perú who also has an MBA and more than 30 years in the mining industry. The team is also made up of José Farfan, president of the Institute for the Promotion and Formalization of Small-Scale Mining, and Miguel Cortavitarte, a lawyer with a master’s in political science, along with 10 other representatives of the new government. In preparation for the new government taking over, a few important decrees and resolutions were also passed impacting the industry. Concerning hydrocarbon blocks and abandonment plans, Ministerial Resolution R.M. 231-2021-MINEM-DM was published in El Peruano on 17 July 2021, clarifies the responsibilities of rightholders in that phase of operations. It approves the “Terms of Reference for the preparation of the Abandonment Plan and Partial Abandonment Plan”. Supreme decree (SD) 021-2021-EM published on 25 July modified the regulation of commercialization of compressed natural gas CNG and Liquefied Natural Gas (LNG) to promote and encourage the development of the market of LNG. This decree establishes that Osinergmin, within 60 calendar days, must adapt and/or approve the procedures or supervision guides for the implementation of the provisions of this standard. The Peruvian state also implemented a decree to grant security to electrical transmission concession contracts. Supreme Decree 185-2021-EF was published on 21 July.
The State Geological Service (SGS/Geonadr) is offering five hydrocarbon blocks for tender in the 2021 Round 13 auction – South Rusanivska, Zhukivska, Kitvan, Reshetylivska and Tynivske. Bidder registration is open from 26 August until 19 October 2021 for an auction the following day. Block details are as follows:
SGS has returned to mixed bid rounds, with hydrocarbon blocks sold alongside mineral concessions. It had indicated it would auction 10 E&P concession in 2021, with four already offered in 2021 Round 5, held in Q2. Only two of these blocks received bids, with Zolochivsky (Yuliyivske Field) won by Naftogaz-owned Ukrgazvydobuvannya at the first stage (now awarded), and Shcherbakivsko-Shkurupiyivska won by Zholet Invest Group at the third stage. Under the auction system, blocks not successfully tendered at the first attempt are auctioned 30-33 days later at half the minimum bid price of the previous tender. If that is not successful, they return two weeks later for a Dutch auction starting at 20% of the original price and terminated at 10% of the original launch price. No hydrocarbon blocks were offered in the other rounds held this year. During Q1 2020, SGS cancelled the old local permitting process and allowed IOCs to participate in special permits, removing the previous requirement for a locally-registered entity. The government is also amending regulations to allow special permit holders to farm-out equity to new partners. IOCs can continue to participate directly in Production Sharing Agreements (PSAs), as before. Note that US$ conversions reported here are impacted by exchange rate fluctuations over time. Further details available at http://www.geo.gov.ua or https://prozorro.sale.
Naftogaz-owned Ukrgazvydobuvannya (UGV) has been formally awarded the special permit for Zolochivsky Block (Yuliyivske Field), valid for 20 years commencing 31 May 2021. It covers 13.75 sq km in Khar’kov region (Dnieper-Donets Basin), overlying the previous Zolochivsky concession relinquished by Nadra Geocenter in January 2020, and contains the eastern extension of the Yuliyivske Field (UGV Op). Estimated resources of 17-40 Bcfg and 1-2 MMbc are assigned to the Zolochivsky Block section of the field, which has access to a nearby UGV-operated gas processing plant. UGV bid UAH 120,670,612 (US$ 4.31 million) on 21 April to beat out Auction Consulting Center LLC which only offered the opening price, UAH 58,743,190 (US$ 2.08 million). It was one of four blocks offered by the State Geological Service (SGS/Geonadr) in the 2021 Round 5, and the only one to sell at the original auction; Zholet Invest Group later bid UAH 1,527,112 (US$ 56,700) for Shcherbakivsko-Shkurupiyivska block at the third attempt on 15 June, whilst East Kosmatska and Luchkivsko-Berezivska attracted no bids.
Centrica is pursuing alternative options for the proposed divestment of it majority stake in Spirit Energy, in order to simplify the sale structure. Spirit Energy joint venture structure has been limiting the number of parties that are interested in acquiring the equity. Spirit Energy’s primary owners are Centrica (69%) and former Bayerngas Norge’s shareholders which comprise Munich’s municipal utilities group Stadtwerke München (SWM; 28%), with the remaining 3% held by a number of other German and Austrian municipal utilities; SWM and the other minority stakeholders had also been known to be considering divestment of their share. Centrica announced the ongoing strategy revision on 22 July 2021, in its H1 2021 Interim results, but has not provided detail of the divestment alternative(s). One clear solution would be to consolidate the minority stakeholding prior to ongoing sale, although this would require the partners to co-operate on asset valuation during consolidation, and possibly agree consideration contingencies related to the onward sale.
Goldman Sachs and Lambert Energy are reportedly advising Centrica on the sale, which was paused the sale in April 2020, due to unsettled market conditions. Centrica announced its planned disposal on 30 July 2019 and news of the divestment by SWM and other minority stakeholders first emerged in August 2019. Spirit Energy holds equity in two Dutch Licences (one operated), 53 Norwegian licences (10 operated) and 64 UK licences (35 operated). The principal fields which the company hold interest in are Kvitebjørn, Statfjord, Nova, Ivar Aasen in Norway and Chiswick, Cygnus and Morecambe in the United Kingdom. Net 2P reserves were 264 MMboe at the end of 2020, down from 284 MMboe at the end of 2019. Spirit Energy was formed when Centrica merged its E&P division with Bayerngas Norge in December 2017, with Centrica to pay GB£ 340 million (US$ 445 million) for a 69% interest, in staggered payments between 2017 and 2022, whilst Bayerngas Norge’s shareholders retained 31% share.
In late July 2021, Shell Offshore revealed that it has taken the final investment decision (FID) for its deepwater Whale development, to be sited on Alaminos Canyon Block AC 773 in the US Gulf of Mexico. The supermajor had previously delayed the decision from H1 2020 to 2021, citing both issues surrounding their supply chain, as well as the general uncertainty created by the 2020 COVID-tainted economic environment. The Whale development, owned by Shell Offshore (60% WI + Op) and Chevron USA (40%), is expected to reach peak production of ~100,000 boe/d and currently has an estimated, recoverable resource volume of 490 MMboe.
“Whale is the latest demonstration of our focus on simplification, replication and capital projects with shorter cycle times to drive greater value from our advantaged positions,” said Wael Sawan, Shell Upstream Director. “We are building on more than 40 years of deep-water expertise to deliver competitive projects that yield high-margin barrels so that we are able to meet the energy demands of today while generating the cash required to help fund the development of the energy of the future.”
Shell’s original Whale discovery NFW, G35153 1 BP1, was drilled on Alaminos Canyon Block AC 772 in June 2017 to a final TD of 6,995m, encountering 427m net of oil-bearing pay in the process. The Whale discovery lies up-dip of the Tobago and Silvertip fields and is located approximately 16km from Shell’s massive Perdido platform. Since those assets are close to the Mexican border, Shell has also leased several offshore blocks from Mexico that could include the extension of the Whale play. Whale will be Shell’s 12th deep-water host in the Gulf of Mexico and is currently scheduled to begin production in 2024.
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