The Daenerys discovery is a game changer for Talos in the Gulf of America (GoA). That’s what Wood Mackenzie said in a note sent to Rigzone by the Wood Mackenzie team this week, adding that the find could add more than 50 million barrels of oil equivalent to Talos’ net proved reserves. “For Talos, the discovery is a game changer,” Miles Sasser, Wood Mackenzie Upstream Senior Research Analyst, said in the note. “The company’s GoA portfolio was ageing, but Daenerys could add more than 50 million… barrels of oil equivalent [to] net proved reserves. That would increase its YE2024 proved reserves of 194 million barrels of oil equivalent more than 25 percent,” he added. “This is the company’s largest discovery to date in the GoA. While Talos has not released volumes, a 200 million barrel of oil equivalent discovery would make Daenerys GoA’s biggest find since Shell’s Whale in 2017,” he continued. In the note, Wood Mackenzie highlighted that the discovery well was drilled to a total vertical depth of 33,228 feet and pointed out that it was finished 12 days early and $16 million under budget, “demonstrating strong operational execution by the Talos-led consortium”. Wood Mackenzie stated in the note that its preliminary prospect valuation suggests peak production could reach 65,000 barrels per day. The company added in the note that the discovery “marks a strategic shift for Talos, which has traditionally focused on lower-risk infrastructure-led exploration (ILX) projects”. “Beyond Daenerys, the company has two additional large exploration projects in its pipeline – Enterprise and Hershey – both with pre-drill estimates exceeding 100 million barrels of oil equivalent each, signaling Talos’ embrace of a more aggressive high-impact exploration strategy,” Wood Mackenzie said in the note. Combined with BP’s Far South discovery in April, 2025 is the best year for

The Alberta Utilities Commission has certified the need for Canadian Utilities Ltd.’s multi-billion-dollar Yellowhead natural gas pipeline project. The project is proposed to carry over 1,200 terajoules, or 1.1 billion cubic feet, per day through over 230 kilometers (142.92 miles) of pipeline from the Peers area to Fort Saskatchewan. “The Need Assessment Application is the first of two key regulatory filings that require approval from the Alberta Utilities Commission to advance the project”, parent company ATCO Ltd. said in a statement online. “Canadian Utilities’ operating entity ATCO Energy Systems will file a separate facilities application later this year to seek AUC approval for construction and operation of the physical infrastructure and expects construction to commence in 2026”. Nancy Southern, chair and chief executive of ATCO, said, “This Alberta Utilities Commission decision affirms the strategic importance of the Yellowhead Pipeline in supporting Alberta’s long-term energy resilience with infrastructure that will empower communities, enable industrial growth and reinforce our commitment to responsible development across the province”. Southern said consultation had been conducted with communities along the proposed route and that the proposed project “reflects both local priorities and broader energy needs”. ATCO’s initial investment estimate for Yellowhead is CAD 2.8 billion ($2.04 billion). “The project is expected to create 2,000 direct jobs and support an average of 12,000 jobs annually through related downstream investments”, ATCO added. “Once operational, the downstream investments are estimated to contribute CAD 3.9 billion annually to Alberta’s GDP”, it said, citing an internal study by Oxford Economics. In its quarterly report last month Canadian Utilities said it continued to pursue engagements with prospective Indigenous partners for equity arrangements. Yellowhead “continues to advance on-going stakeholder consultation, land acquisition, long-lead pipeline materials procurement and design work”, the report said. Canadian Utilities is progressing another project, the Central East Transfer-Out power transmission line (CETO), which started construction in the third

Secondary sanctions and measures aimed at Russia’s energy sector would be most effective in curbing Moscow’s ability to wage war against Ukraine, according to the European Union’s foreign policy chief, Kaja Kallas. Russia’s attack this week on Kyiv, which also damaged the EU’s representative offices in the capital, is yet another reason to increase pressure on Russia, Kallas told reporters in Copenhagen Friday ahead of an informal meeting of defense ministers. Bloomberg previously reported that the EU is mulling the use of secondary sanctions to prevent third countries from helping the Kremlin circumvent the bloc’s existing penalties, as well as further measures on the country’s oil and gas and financial sectors.  “We are working on the next package, there are several options on the table,” Kallas said. “Of course, what will hurt them the most is any sanctions on energy and secondary sanctions that Americans have put for example, but also financial services.” Foreign ministers on Saturday are expected to discuss the use of the so-called anti-circumvention tool that was adopted in 2023 but that hasn’t been used yet. This tool can prohibit the export, supply or transfer of certain goods to third countries that are considered aiding sanctions circumvention. They’ll also discuss the bloc’s 19th package of sanctions that’s for now mainly expected to focus on Russia’s alleged abductions of Ukrainian children. The challenge in the coming days is to agree on new sanctions, security guarantees and funding for Ukraine, according to a European official who spoke on condition of anonymity.  The important thing is to keep up the pressure on the Kremlin, and that would require the US to take decisions, particularly about sanctions, the person said. On Tuesday, Trump warned of “an economic war” if Russia and Ukraine did not end their conflict, saying he had “very serious” consequences in mind

MPLX LP has signed a definitive agreement to divest its Rockies natural gas gathering and processing network to Harvest Midstream Co. for $1 billion in cash, the companies said. The assets serve the Uinta and Green River basins across Wyoming, Utah and Colorado. The Uinta Basin assets include around 700 miles of gathering pipelines and about 345 million cubic feet a day (MMcfd) of processing capacity at the Ironhorse and Stagecoach facilities, which are being expanded. The Green River Basin assets include approximately 800 miles of gathering and transport pipelines and about 500 MMcfd of processing capacity from the Blacks Fork and Vermilion facilities, and 10,000 barrels per day (bpd) of fractionator capacity. “These assets significantly expand Harvest’s geographic reach, enhance connectivity across major production basins, and create meaningful platforms for future organic and acquisition-driven growth”, Houston, Texas-based Harvest said in a statement online. Harvest chief executive Jason C. Rebrook said, “This acquisition is the beginning of the next chapter of Harvest’s ambitious and disciplined growth story. We are executing on a long-term vision to build a scaled, resilient midstream network capable of supporting America’s energy needs for decades to come – and these premier MPLX assets fit squarely into that strategy”. Harvest agreed to deliver about 12,000 bpd of natural gas liquids from the assets to MPLX for seven years starting 2028 after the expiration of a pre-existing commitment. Service for the existing customers of the assets under the transaction will not be affected. The parties expect to complete the transaction in the fourth quarter subject to closing conditions including the receipt of anti-trust clearance. For Findlay, Ohio-based oil and gas infrastructure company MPLX, “The divestiture of these assets better positions our portfolio for growth, anchored in the Marcellus and Permian basins”, said MPLX president and chief executive Maryann

Block Energy plc said it has completed the initial injection of carbon dioxide (CO2) of its carbon capture and storage (CCS) project in the Eastern European region of Georgia. No CO2 leakage on the surface was detected after the injection, Block Energy said in a news release. Previous work has confirmed connectivity between the injector well (PAT-49) and the four monitoring wells, the company said. Liquid CO2 was delivered to the wellsite by Block Energy’s partner in the pilot study, Indorama Corporation subsidiary Rustavi Azot, and injected in solution with water, according to the release. Block Energy said it has implemented a monitoring and verification program, in which the company will collect subsurface samples and analyze data to determine if the injected CO2 has mineralized into solid calcium carbonate and is able to be permanently stored. The company said it expects to take four to six months to determine if the CO2 has successfully mineralized in the reservoir and therefore proceed with the next steps in the project. The company noted that this is the first successful pilot test of its kind in the broader Eastern European region. Assuming that mineralization is proven in the pilot, the project will provide a credible and tangible pathway to commercialization opportunities through third-party verification and a solution to carbon emissions reduction within Georgia and potentially in the wider region, Block Energy said. According to the release, commercial efforts are currently focused on direct air capture technologies as well as engagement with industrial emitters seeking carbon reduction solutions, including in response to the European Union’s (EU) upcoming Carbon Border Adjustment Mechanism. Georgia and the EU have a zero-tariff free-trade agreement in place, offering additional opportunities in the space, the company said. Block Energy said it is working on commercialization options, including discussions with materials

Karoon Energy Ltd reported an increase of 13.7 million barrels (MMbbl) of 2P reserves in the Bauna project in the southern post-salt region of the Santos Basin, Brazil. The increase in 2P reserves, which are 35 percent higher as of June 30 from six months ago, reflect the acquisition of the Baúna floating production, storage and offloading vessel (FPSO), facility operating life extension, and “better reservoir performance than anticipated,” Karoon said in a news release. The project’s economic field life has also been extended by seven years to 2039, limited by the current production concession expiry, the company said. The Bauna Project comprises the Bauna, Piracaba and Patola fields in Concession BM-S-40 offshore Brazil The asset’s 2C contingent resources have been reduced from 11.2 MMbbl to 3.0 MMbbl over the same period, reflecting an upwards revision of 5.5 MMbbl, less the transfer of 13.7 MMbbl to the 2P reserves category. The reassessment of contingent resources was based on the potential to produce until the assessed end of the facility’s operating life of 2040, according to the release. Karoon said it expects to invest $55 million to $65 million in an FPSO revitalization campaign in 2026, and approximately $80 million to $90 million in life extension activities between 2030 and 2034. Life extension capital expenditures are expected to include two flotel campaigns and associated equipment upgrades. The reassessment included an updated reservoir performance, modelling and activities outlook, as well as the removal of Altera & Ocyan FPSO charter costs, leading to a reduction in minimum economic production rates. It also included an updated assessment of long-term operating costs and field abandonment costs, with the production concession expiry date of February 2039 factored in, Karoon said. “One of the key drivers underpinning the [first-half] Baúna FPSO acquisition was the potential to reduce