A spokesperson has acknowledged that the sanctioned country’s energy is still flowing into the bloc
Russian energy continues to flow to the EU despite the bloc’s commitment to eliminating its dependence on it, a European Commission spokesperson has said.
The EU’s imports of liquefied natural gas (LNG) from Russia surged in the first two weeks of 2025, rising by more than 10% in annual terms.
“Russian energy – particularly gas – is still present in the EU,” the EC spokesperson for climate action and energy, Anna-Kaisa Itkonen, told a press briefing on Monday.
She noted that the Commission plans to issue a roadmap in late February or mid-March aimed at completely ending Russian energy imports.
Last week, Politico reported, citing data tracked by commodities data provider Kpler, that imports by EU member states of Russian LNG have surged to an all-time high after they purchased 837,300 metric tons of the super-chilled gas in the first 15 days of this year.
Itkonen had also previously admitted that the EU’s Russian gas imports, particularly of LNG, increased in 2024.
Imports surged again shortly after Ukraine refused to extend a five-year transit contract with Russian energy giant Gazprom at the end of 2024, cutting off Romania, Poland, Hungary, Slovakia, Austria, Italy, and Moldova from piped natural gas from Russia.
Following the escalation of the Ukraine conflict in 2022 and the sabotage of the Nord Stream pipelines, the EU prioritized reducing its reliance on Russian energy. Some members voluntarily stopped importing Russian gas, while others kept doing so. Some countries also continued importing Russian LNG since the chilled fuel was only partially targeted by sanctions.
In June, the EU targeted Russian LNG for the first time, banning re-loading operations, ship-to-ship transfers, and ship-to-shore transfers with the purpose of re-exporting to third countries via the EU. The sanctions have a nine-month transition period.
According to data compiled by the Institute of Energy Economics and Financial Analysis, in the first half of 2024 Russia was the second-biggest supplier of LNG to the European continent after the US.
The loss of Russian gas could cost the EU over €1 trillion, according to Kirill Dmitriev, chief executive of the Russian Direct Investment Fund.
Revisiting FP interviews with administration officials, from Jake Sullivan to Katherine Tai.
In the past four years, top officials from Jake Sullivan to Katherine Tai have sat down with FP to offer insight into U.S. President Joe Biden’s foreign policy. Together, they painted a picture of the “Biden doctrine” on foreign aid, relations with Europe, U.S.-China competition, and more.
On Biden’s final weekend in office, we’re revisiting some of the most illuminating conversations to provide an insider’s look at the outgoing president’s foreign-policy legacy.
White House National Security Advisor Jake Sullivan gives a press briefing.
White House National Security Advisor Jake Sullivan calls on reporters at the White House in Washington on Dec. 7, 2021.Chip Somodevilla/Getty Images
U.S. National Security Advisor Jake Sullivan sat down with Foreign Policy to talk about Russia, China, relations with Europe, and year one of the Biden presidency.
U.S. Trade Representative Katherine Tai in her office in Washington
U.S. Trade Representative Katherine Tai in her office in Washington on March 15, 2023. Jesse Dittmar photos for Foreign Policy
Gina Raimondo has reshaped the Commerce Department for technological competition with China.
Colin Kahl, the U.S. undersecretary of defense for policy, testifies during a Senate Armed Services Committee hearing in Washington.
Colin Kahl, the U.S. undersecretary of defense for policy, testifies during a Senate Armed Services Committee hearing in Washington on Oct. 26, 2021.Tom Williams/CQ-Roll Call, Inc via Getty Images
The Pentagon’s top policymaker on Russia’s war in Ukraine, the impact of recent leaks, and the long-term challenge of China.
U.S. Agency for International Development administrator Samantha Power testifies.
U.S. Agency for International Development administrator Samantha Power testifies before the House Foreign Affairs Committee in Washington on May 17, 2022.Jose Luis Magana/AFP via Getty Images
LNG imports in 2024 were lower than 78.93 million tonnes in 2021, which marked a new record high due to rising demand from the power generation and industrial sectors.
In December 2024, China’s LNG imports decreased by 13.9 percent year-on-year to 7.14 million tonnes.
GECF said in its monthly report that China’s LNG imports in December declined primarily due to rising spot LNG prices, which dampened demand, combined with mild winter weather and high LNG inventory levels.
Natural gas imports, including pipeline gas, reached about 11.55 million tonnes last month, down 8.6 percent compared to 12.64 million tonnes in December 2023, the data shows.
China’s pipeline imports rose 3.9 percent year-on-year in December to 4.41 million tonnes.
In 2024, China’s natural gas imports, including pipeline gas and LNG, rose 9.9 percent to 131.69 million tonnes.
China remained the world’s largest LNG importer in 2024.
Official data for Japan’s LNG imports in December is not yet available.
However, Japan imported some 10 million tonnes of LNG less than China during the January-November period last year.
This compares to 81.1 Mtpa in 2023, and the previous record of 81.3 Mt shipped during 2022, EnergyQuest said in a new report.
The US, Australia, and Qatar are the world’s top three largest LNG exporters.
The consultancy said that the 2024 LNG revenue of $67.7 billion was less than the record $90.3 billion in 2022, and $74.3 billion during 2023.
This is primarily due to lower LNG prices, which was countered somewhat by a falling Australian dollar compared to the US dollar, EnergyQuest said.
Australia’s December 2024 shipments were 85.7 Mtpa on an annualized basis, compared to 80.9 Mtpa for November 2024, the consultancy said.
December 2024 shipments represented 97.3 percent of nameplate capacity.
EnergyQuest estimates that Australian LNG export revenue in December was $2.38 billion, higher than the $5.76 billion in November, and reflecting only a 0.6 percent decrease compared to December 2023, when revenue was $6.42 billion.
Western Australia projects earned export revenue of $3.60 billion, Queensland projects brought in $2.06 billion, and NT projects earned $0.72 billion.
Moreover, WA shipments were higher at 4.11 Mt in December, up from 3.83 Mt in November, while there were 58 cargoes in December, compared to 55 in November, the consultancy said.
Northern Territory (Inpex Ichthys LNG) had 11 shipments in December for 0.82 Mt, compared to November’s 8 cargoes for 0.60 Mt, EnergyQuest said.
EnergyQuest said Queensland LNG shipments set a new monthly record with December shipments being 34 cargoes for a combined 2.35 Mt.
This compares to 32 cargoes for 2.20 Mt in November, and slightly eclipsing the monthly record set in October 2024 which saw 34 cargoes for 2.33 Mt, it said.
Samsung Heavy said on Monday that it will build the LNG carrier for an unidentified owner in Oceania.
The shipbuilder will deliver the LNG carrier by June 2027.
The order has a price tag of 379.6 billion won or about $261 million.
Samsung Heavy did not provide any additional information regarding the contract.
Including this deal, the shipbuilder now has 84 LNG carriers worth about $19.1 billion in its order book.
Samsung Heavy won orders for 22 LNG carriers worth $5.3 billion in 2024.
In October 2024, Samsung Heavy won an order for one LNG carrier tied to K Line, while the shipbuilder also won an order from Malaysia’s MISC for two 174,000-cbm LNG carriers.
Samsung Heavy also secured a contract from Adnoc L&S to build four LNG carriers.
In October 2024, Woodside acquired all issued and outstanding Tellurian common stock for about $900 million cash, or $1.00 per share. The implied enterprise value is about $1.2 billion.
Woodside also renamed Tellurian’s Driftwood LNG project Woodside Louisiana LNG.
Last month, Woodside signed a revised engineering, procurement, and construction (EPC) contract with US engineering and construction firm Bechtel for the Louisiana LNG export project.
The lump sum turnkey deal is for the three-train 16.5 million tonnes per annum foundation development of Louisiana LNG.
Woodside said total Louisiana LNG expenditure from December 2024 to the end of the first quarter of 2025 is forecast to be up to $1.3 billion, which is included in the overall estimated cost for the foundation development.
Piling works in plant 2 (Image: Woodside)
According to the December 2024 construction report filed with the US FERC, the Louisiana LNG project continued construction activities including site preparation, excavation and backfill, storm water management, mud mat installation, dry excavation, pile driving, vegetation burning activities, rebar/formwork in plant 1 and tanks, and wick drain installation.
Lousiana LNG also continued activities for water wells as a non-jurisdictional activity under
the early works program.
During December, the project continued maintenance of site roads and drainage efforts, completed piling in plant 2, while plant 1 sump sheet piling started.
Moreover, Louisiana LNG started excavation for tower cranes foundations at LNG tanks.
On January 17, FERC granted Louisiana LNG’s request for Louisiana LNG to start construction of the concrete foundations for the LNG tank 1 and 2 stair towers.
During January, Louisiana LNG will continue construction activities including maintenance and installation of site roads and drainage efforts, storm water management activities, and mud mat installation.
Louisiana LNG will also continue with dry excavation, burning of vegetation, wick drain installation, complete batch plant earth works, continue rebar installation, start earth work activities for south berm, and continue pile driving for the project.
Venture Global’s 174,000-cbm newbuild carrier, Venture Gator, was on Monday anchored in the North Sea, offshore Wilhelmshaven and Brunsbüttel, where DET’s FSRU-based facilities are located, its AIS data provided by VesselsValue shows.
The data shows that the vessel is expected to deliver the shipment to Brunsbüttel, the home of the 170,000-cbm FSRU Hoegh Gannet.
Earlier this month, Venture Gator left the Plaquemines plant after loading the second commissioning cargo.
Venture Global sent the first commissioning cargo from its Plaquemines plant on December 27, 2024, and this shipment was recently delivered to DET’s FSRU-based terminal in Wilhelmshaven.
Germany’s EnBW bought this LNG cargo from Venture Global.
Venture Global said this shipment marked over 60 LNG cargoes sent from the company into Germany since 2022.
Besides these two shipments, Venture Global recently sent the third commissioning cargo from its Plaquemines plant to Europe.
The 2021-built 174,000-cbm, Isabella, was on Monday sailing in the North Atlantic Ocean, and is expected to arrive at its destination in Europe around January 27, its AIS data shows.
In addition, Venture Global loaded and shipped the fourth commissioning cargo.
The 2018-built 174,000-cbm, Flex Rainbow, left the facility in Port Sulphur during the weekend, its AIS data shows.
Flex Rainbow’s final destination is currently not available, but it also appears to be heading to Europe.
Plaquemines LNG is the eighth US LNG export facility.
Venture Global said in its recent IPO statement it is targeting a COD (commercial operations date) for the Plaquemines project in the third quarter of 2026 for Phase 1 and the second quarter of 2027 for Phase 2.
The full project, including the second stage, will have a capacity of 20 mtpa coming from 36 modular units, configured in 18 blocks.
Concerns about more supply disruptions as Trump returns to power
Potential halt to Houthi attacks on shipping in focus after Gaza ceasefire deal
US oil rig count falls by two
HOUSTON, Jan 17 (Reuters) – Oil prices settled lower on Friday but notched their fourth straight weekly gain, as the latest U.S. sanctions on Russian energy trade added to worries about oil supply disruptions.
Brent crude futures dipped 50 cents, or 0.6%, at $80.79 per barrel, but gained 1.3% this week. U.S. West Texas Intermediate crude futures lost 80 cents, or 1%, at $77.88 a barrel, having climbed 1.7% for the week.
“Sanctions on Russia are causing tightness of supply in Europe, India and China,” said Phil Flynn, senior analyst with Price Futures Group.
The Biden administration unveiled broader sanctions last week targeting Russian oil producers and tankers.
Investors are also assessing the potential implications of President-elect Donald Trump’s return to the White House on Monday. Trump’s pick for Treasury secretary said he was ready to impose tougher sanctions on Russian oil.
Money managers raised their net long U.S. crude futures and options positions in the week up to Jan. 14, data from the U.S. Commodity Futures Trading Commission showed on Friday. Speculators raised combined futures and options positions in New York and London by 8,038 contracts to 215,193 over that period.
However, weighing on oil prices were expectations of a halt in attacks by Yemen’s Houthi militia on ships in the Red Sea following a Gaza ceasefire deal.
The Houthis’ attacks have disrupted global shipping, forcing ships to make longer and more expensive journeys around southern Africa for more than a year.
The Israeli security cabinet approved the ceasefire deal on Friday, paving the way for the return of the first hostages from Gaza as early as Sunday. The accord was still conditional on approval by the full cabinet, which was meeting on Friday afternoon.
Expectations for increased demand lent some support to the oil market earlier on Friday. Data this week showed inflation easing in the U.S., the world’s biggest economy, bolstering expectations of interest-rate cuts.
Traders are also assessing fresh data from China, the world’s top oil importer. Its economy fulfilled the government’s ambitions for 5% growth last year.
However, China’s oil refinery throughput in 2024 fell for the first time in more than two decades barring the pandemic year of 2022, government data showed on Friday, as plants tempered operations in response to stagnant fuel demand and depressed margins.
Meanwhile, the U.S. oil rig count, an indicator of future output, fell by two to 478 this week, energy services firm Baker Hughes said.
A blast of Arctic air is set to cover much of the United States with temperatures below freezing starting on Friday and into next week, and is set to drive up heating oil demand and likely impact some productionoperations.
Reporting by Enes Tunagur in London, Yuka Obayashi in Tokyo and Siyi Liu in Singapore Editing by Clarence Fernandez, Jason Neely, Paul Simao, Frances Kerry, Rod Nickel and David Gregorio
HOUSTON, Jan. 15, 2025 /PRNewswire/ — Talos Energy Inc. (“Talos” or the “Company”) (NYSE: TALO) today announced that the Katmai West #2 well located in the Ewing Bank area of the U.S Gulf of Mexico successfully encountered commercial quantities of oil and natural gas.
(PRNewsfoto/Talos Energy)
Key Highlights
The Katmai West #2 well was drilled significantly under budget and ahead of schedule to a true vertical depth of approximately 27,000 feet.
Encountered the primary target sand full-to-base with over 400 feet of gross hydrocarbon pay and excellent rock properties in line with pre-drill expectations.
Expected deliverability from the well is in line with pre-drill estimates of approximately 15 – 20 thousand barrels of oil equivalent per day (“MBoe/d”) gross.
The strong performance from Katmai West #1 well, and the successful appraisal from Katmai West #2 well, have nearly doubled the Proved EUR (estimated ultimate recovery) of Katmai West field to approximately 50 million barrels of oil equivalent (“MMBoe”) gross, which further affirms the company’s expected total resource potential of approximately 100 MMBoe gross.
First production is expected in the late second quarter 2025.
The drillship West Vela began drilling the Katmai West #2 well in late October 2024. Talos plans to case and suspend the well by late January 2025 while the Company finalizes completion plans to be executed in the second quarter 2025. Production is expected to start later that same quarter. The well will be connected to the existing subsea infrastructure that flows to the Tarantula facility, which has been expanded to increase capacity to 35 MBoe/d. Talos anticipates the Katmai wells will be rate-constrained under the upgraded capacity, allowing for extended flat-to-low decline production from the facility. Talos, as operator, holds a 50% working interest, with entities managed by Ridgewood Energy Corporation holding the other 50% in Katmai West field. Talos is the 100% owner and operator of the Tarantula facility.
Talos’s Interim Co-President, Executive Vice President and Head of Operations John Spath stated, “We are proud of our team for achieving these successful drilling results. Delivering this high-impact deepwater well, approximately 35% under budget and more than a month ahead of schedule, demonstrates our ability to efficiently execute complex projects while maintaining top safety and environmental standards. We remain optimistic about the greater Katmai area, as these results align with our pre-drill expectations about its gross resource potential. We look forward to having this well on production and believe it positions us for strong value creation as we move forward into 2025.”
ABOUT TALOS ENERGY
Talos Energy (NYSE: TALO) is a technically driven, innovative, independent energy company focused on maximizing long-term value through its Upstream Exploration & Production business in the United StatesGulf of Mexico and offshore Mexico. We leverage decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility, and community impact. For more information, visit www.talosenergy.com.
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
This communication may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this communication, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this communication, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast,” “may,” “objective,” “plan” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.
We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, the successful development of and production from the prospects described herein; the uncertainty inherent in estimating reserves, resource potential and reservoir performance; the outcome of exploration and drilling efforts; environmental risks; drilling, geologic and other operating risks; the profitability and results of wells described herein; timely completion of development projects; technical or operating factors; the uncertainty inherent in projecting future rates of production and cash flows; our access to capital to finance such opportunities; implementing a successful drilling program and the other risks discussed in “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2023 and “Risk Factors” in our subsequent Quarterly Reports on Forms 10-Q filed with the U.S. Securities and Exchange Commission (the “SEC”).
Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this communication are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this communication.
PRODUCTION ESTIMATES
Estimates for our future production volumes are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation, marketing and storage of oil and gas are subject to disruption due to transportation, processing and storage availability, mechanical failure, human error, hurricanes and numerous other factors. Our estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Therefore, we can give no assurance that our future production volumes will be as estimated.
RESERVE INFORMATION
Estimates of recoverable hydrocarbon volumes and related measures, including estimates of total resource potential, as presented herein are based on internal data prepared by the Company’s management team in reliance on several assumptions. Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions upward or downward of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered. In addition, we use the term expected “total recoverable resource” in this release, which is not a measure of “reserves” prepared in accordance with SEC guidelines or permitted to be included in SEC filings. These resource estimates are inherently more uncertain than estimates of reserves prepared in accordance with SEC guidelines.
US shale producers are focused on capital discipline and shareholder returns, limiting the impact of Trump’s pro-oil policies.
Increased Permian rig activity is unlikely to significantly boost oil production due to inventory depletion and efficiency concerns.
The US is already on track to meet Bessent’s 3-3-3 hydrocarbon production target without policy changes, driven by NGLs and gas.
Although corporate executives in the shale industry may be encouraged by the supportive rhetoric of President-elect Donald Trump and his incoming administration, a potential crude oil oversupply and a stagnation in well productivity mean they are less likely to boost drilling budgets. Operators are likely to cut back on Lower 48 drilling if prices stay below $70 per barrel. Industry heavyweights such as Chevron and Diamondback have guided for more modest budgets and slower-to-flat production growth next year. For now, ‘Shale 4.0’ priorities, which emphasize capital discipline to prioritize shareholder payouts and inventory consolidation are expected to outweigh ‘Trump 2.0’ policy considerations in US producers’ boardrooms. Rystad Energy finds that in a scenario where Permian rigs rise by 60 more per month higher compared to current projections and reach post-Covid-19 highs, we could see a production upside of 343,000 barrels of oil per day by the second half of 2026, relative to our current forecast. However, this growth would come at the expense of a spike in capital spending of more than $11 billion, while Permian reinvestment rates are also expected to edge higher by nine percentage points.
There is some hope that an unabashedly pro-oil and gas administration could break the current investor paradigm and encourage a new era of exploration and growth. However, the overriding issue is that without the consistent productivity improvements that allowed for investors to effectively subsidize the shale boom during the 2010s, investors and lenders will be unlikely to await longer-term payback while capital efficiency degrades.
Figure 1 looks at Rystad Energy’s current annual forecast for oil, natural gas liquids (NGLs) and gas in the entire US from 2024-2028. Scott Bessent, tapped by President-elect Trump to serve as his Treasury Secretary, floated an increase of output by “3 million barrels of oil equivalent per day (boepd)” as part of a broader “3-3-3” economic plan. There has been some ambiguity around the reporting of Bessent’s plan and whether it refers to only the growth of oil or across all hydrocarbons. Rystad Energy notes that, if this is in reference to all hydrocarbon production, the US is already on track to surpass this metric in 2027 based on current market fundamentals and company strategies, barring any policy changes. In our base case outlook, total output will grow in the US by 3.3 million boepd from full-year 2024 averages to full-year 2027. However, an important caveat here is that the 6:1 volumetric-equivalent between oil and dry gas means that gas volumes, which already have a more optimistic medium-term price outlook than oil, average higher current output in oil-equivalent terms than oil and are on track to grow by 1.72 million boepd through 2027. NGLs have the highest compounded annual growth rate (CAGR) among hydrocarbons, of 3.2% between 2024-2027, bringing an additional 625,000 boepd.
To evaluate any realistic growth in just oil volumes in the medium term, Figure 2 looks at an excess rig scenario in which rig activity in the Permian increased 60 above our current outlook through 2025. While this is highly unrealistic in the current price environment and corporate strategy paradigm, it is meant as a purely theoretical exercise to see what level of growth would be possible. Moreover, we have seen that operators exhibit little upwards price sensitivity in the $70-$90 per barrel range, and any increases in activity could come at the expense of other parts of a company’s portfolio. Even so, in the scenario where upward price movement comes on the back of external demand factors such as the occurrence of macroeconomic or geopolitical shocks, or if executives were willing to ramp up activity and pursue Trump’s desire for more drilling, we explore what output would look like.
First, we limit the theoretical potential rig increase in the Permian to 60, which would surpass post-Covid-19 highs set in early 2023 if achieved. Inventory depletion, consolidation, service market high-grading and improved efficiencies make any medium-term increase beyond this extremely unlikely even in the most optimistic price scenarios. Moreover, for this analysis, we assume that any additions would come from the Permian, rather than being distributed across less commercial, second tier basins such as Bakken, DJ and Eagle Ford. One plausible scenario could see smaller private exploration and production (E&P) companies, that are left to fringier positions and with limited remaining inventories, choose to increase drilling while prices remain somewhat commercial, rather than waiting for a sale in a market where buyers are seeking scale in the core. Therefore, for this analysis, we use a 25th percentile 2023-2024 vintage Permian type curve. This is reasonable for the aforementioned reason, as well as the fact that it is extremely unlikely that any of the larger Permian players will willingly drain core, lower-cost inventory in the short term in such a situation. Next, Figure 2 projects the production from new wells (PUD) output of 60 more rigs (shown in blue) on top of our current base case outlook for the Permian. This assumes 1.75 spuds per rigmonth, a six-month spud-to-start-up cycle time and a gradual buildup of rigs over 2025.
By Matthew Bernstein Vice President, Shale Research at Rystad Energy
U.S. Trade Representative Katherine Tai in her office in Washington
