Russia’s oil product exports dropped in June to the lowest in eight months amid extended work at refineries supplying Baltic ports, coupled with efforts to stabilize domestic fuel supplies before the upcoming seasonal surge in agricultural and holiday consumption. Seaborne shipments of refined fuels totaled 2 million barrels a day in the first 20 days in June, according to data compiled by Bloomberg from analytics firm Vortexa Ltd. That’s the lowest monthly tally since October and an 8% decline compared to both the previous month and last year in June. Flows from Baltic ports recorded the sharpest drop of more than 15% from May levels. Russian seaborne oil flows are closely watched by the market to assess its production since official data has been classified. Crude outflows slid to the lowest since mid-April led by maintenance-related disruptions at a key Pacific port, compounded by a decline from the Baltic. Oil processing rates have ramped-up this month as refineries wrap up seasonal maintenance. However, volumes available for export may be curbed by government initiatives to boost stockpiles to meet growing fuel demand from agricultural activity and summer travel. Diesel exports were largely flat, while flows of refinery feedstocks like vacuum gasoil, used by secondary units like the fluid catalytic crackers, jumped this month. Outflows of all other major fuels slumped. Most of the decline in fuel flows were concentrated in the Baltic ports, indicating extended turnarounds at refineries that usually supply these terminals. “Drone strikes earlier this year could have extended the turnaround time for both primary and secondary units,” according to Mick Strautmann, a market analyst at Vortexa. The spike in vacuum gasoil flows out of Ust-Luga in the Baltic, a feedstock used in secondary units like the fluid catalytic cracking units, suggests more serious disruptions at downstream units in the region, he

Oil held steady as traders weighed the uncertain status of nuclear talks between the US and Iran against reports that OPEC+ may extend its run of super-sized production increases. West Texas Intermediate edged up to settle above $65 a barrel after swinging between gains and losses. Bloomberg reported that several OPEC delegates, who asked not to be identified, said their countries are ready consider another 411,000 barrel-a-day increase for August when they convene on July 6, following similarly sized hikes agreed upon in each of the previous three months. While that figure is broadly in-line with expectations, “the indications are that the group may go beyond the 411,000 barrel-a-day increase,” said John Kilduff, a partner at Again Capital. “Next, we should hear about the voluntary cuts under-shooting the goal from the group laggards. I expect the ultimate decision to be bearish for prices.” Crude had earlier advanced as much as 1.3% after US Energy Secretary Chris Wright told Bloomberg that sanctions against Iran will remain in place for now, and US President Donald Trump said he dropped plans to ease Iran sanctions. The statement comes just days after the president claimed that Iran and the US would meet for nuclear talk as soon as next week, which Iran denied. Oil still ended the week down roughly 13% — snapping three weeks of gains — after a ceasefire in the Israel-Iran conflict was reached, easing concerns about supply disruptions from a region that pumps about a third of the world’s crude. The focus has largely reverted to fundamental catalysts, including OPEC moves. Russia now also appears more receptive to a fresh output boost, in a reversal of an earlier stance, raising concerns of supply overhang in the second half of the year. Investors have also turned their attention to progress on

The cost of shipping Middle East crude to customers in Asia collapsed on Thursday, the latest sign of oil markets returning to normal after conflict eased in the world’s top petroleum-exporting region. Charter rates slumped by 17% to 55.50 industry-standard Worldscale points, according to data from the Baltic Exchange in London. It works out at roughly $1.60 a barrel. “Risk premiums have naturally faded,” said Fredrik Dybwad, an analyst at Fearnley Securities AS. “There is ample vessel availability, and considering normal seasonality, rates should naturally find a lower level.” Shipping prices soared two weeks ago amid concern Iran might disrupt maritime traffic around Hormuz Strait, a vital waterway through which 20% of the world’s oil and liquefied natural gas must pass. After almost two weeks of fighting between Iran and Israel that began on June 13, there’s since been a ceasefire, hitting oil prices and lowering the risks for ships that enter the region. The Joint Maritime Information Center, a naval liaison with commercial shipping in the region, said Thursday that no hostilities had been reported in the Strait of Hormuz over the past 48 hours and that traffic had returned to normal levels. “A sustained period of inactivity and strengthening of the ceasefire agreement will stabilize maritime tension in the Arabian Gulf,” it said in a note.  “Now that the market has become sanguine about Iran shutting the Strait of Hormuz, ships are running fluidly again, the premium gas been removed, and rates are correcting lower meaningfully,” said Jonathan Chappell, senior managing director at Evercore ISI. The Worldscale system is designed to let owners and charterers quickly calculate the latest earnings and per-barrel costs on thousands of trade routes.  Vessels on the industry’s benchmark Saudi Arabia-to-China route are earning $35,281 a day, according to the Baltic Exchange. They were

Shell PLC and Equinor ASA have named their United Kingdom North Sea joint venture Adura, which they announced December as the biggest independent producer on the UK’s side of the sea. “Work continues towards securing regulatory approvals, with launch of the IJV [incorporated JV] expected by the end of this year”, Norway’s majority state-owned Equinor said in an online statement. Adura, which will be equally owned, combines the two companies’ offshore assets in the UK, where Shell currently produces over 100,000 barrels of oil equivalent a day (boed) and Equinor about 38,000 boed. “Adura is expected to produce over 140,000 barrels of oil equivalent per day in 2025”, Equinor said. The name Adura is “rooted in their [the companies] respective heritage and focused on shaping the future of the basin in the years ahead”, Equinor explained. “Adura has been created to bring together the A of Aberdeen and the dura of durability. It’s a company built on firm foundations, much like the strong granite synonymous with the city”. “Adura will sustain domestic oil and gas production and security of energy supply in the UK and beyond”, Equinor added. Adura will include Equinor’s 29.89 percent stake in the CNOOC Ltd.-operated Buzzard field, which started production 2007; an operating stake of 65.11percent in Mariner, online since 2019; and an 80 percent operating stake in Rosebank, expected to come onstream 2026. Shell will contribute its 27.97 percent ownership in BP PLC-operated Clair, which began production 2005; a 50 percent operating stake in Gannet, started up 1992; a 100 percent stake in Jackdaw, for which Shell plans to seek a new consent following a court nullification; a 21.23 percent operating stake in Nelson, which started production 1994; a 50 percent operating stake in Penguins, which started production 2003; a 92.52 percent operating stake in Pierce,

Dive Brief: New York state is offering up to $750,000 in state cost-sharing funding for building and campus decarbonization efforts that use ground-source heat pumps, waste heat recovery, thermal energy storage and other low-emissions technologies. Applications are due July 31. The New York State Energy Research and Development Authority’s Large-Scale Thermal program encourages property owners to pursue high-efficiency, “grid-friendly” electrification projects, NYSERDA Program Manager Sue Dougherty said in a presentation at the International District Energy Association annual conference earlier this month. The $10 million program is open to systems that provide heating, cooling and hot water to single buildings with at least 100,000 square feet of conditioned space or multibuilding campuses with at least 250,000 conditioned square feet, NYSERDA says.  Dive Insight: State funding opportunities like the Large-Scale Thermal program are key to New York’s efforts to significantly reduce the environmental impact of its roughly 6 million buildings in the coming decades, Dougherty said. The state wants 85% of its buildings to use clean heating technologies like heat pumps and thermal energy networks by 2050, the same year its statutory net-zero statewide GHG emissions target kicks in. “We’re not going to do all 6 million buildings, and we really don’t have to,” Dougherty said. “But we will need to do a significant number, and our solutions will need to address existing, older buildings and newer buildings getting built [today].”  The Large-Scale Thermal program is accepting applications for its third funding round through July. Successful applicants will receive state funding equal to 50% of total project design costs, with maximum funding up to $300,000 for new construction and $750,000 for existing buildings. The project economics tend to work best for existing facilities with aging heating and cooling infrastructure, new construction and larger buildings or campuses that can achieve “economies of scale,”

The National Electrical Manufacturers Association on Wednesday announced the publication of three standards aimed at helping utilities and equipment manufacturers develop the “digital substations” they say will underpin a modern, reliable and self-healing grid. More standards will be published in the future, with the initial set covering fault isolation and restoration issues in distributed energy resources, and on a looped single line feeder, potentially in instances of communications loss. The standards can assist utilities that want to install grid sensors, switches and automated reclosers, NEMA officials said. “You can think of them as basically blueprints for utilities to use when they are going to implement one of these systems,” NEMA Senior Vice President of Strategy, Technical and Industry Affairs Patrick Hughes said. “We’ve seen and heard from utilities that there are interoperability questions and there’s a need for technical guidance for utilities interested in installing these … self-healing grid technologies,” Hughes said. “These give utilities a very clear blueprint for how to implement these systems.” Modernized substations and automated restoration equipment will be key to managing the increasing demand for electricity across a strained grid, experts say. NEMA anticipates electricity demand in the U.S. will increase 2% annually and 50% by 2050, as more data centers are built, buildings are electrified and transportation shifts away from fossil fuels. “When you’re dealing with modern grid technologies, and it includes communication systems and smart technologies, you have a number of different vendors that are offering these technologies and the service,” Hughes said. “And it can be a little overwhelming with different manufacturers and different communication protocols and all the different specifications that go into implementing one of these systems.” Add to that, utilities must convince regulators who are concerned about how the investments are made, and whether the systems will have long-term support