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Australia’s Woodside Energy has struck a deal to acquire Tellurian for $1.2 billion as it seeks to turn into a “global LNG powerhouse”. The deal “adds a scalable US LNG development opportunity to our existing approximately 10 Mtpa of equity LNG in Australia,” Woodside chief executive Meg O’Neill said. “Having a complementary US position would allow us to better serve customers globally and capture further marketing optimization opportunities across both the Atlantic and Pacific Basins.” Tellurian has been planning to build Driftwood LNG, a production and export terminal on the Calcasieu River south of Lake Charles, Louisiana for years. Once complete, the terminal would be capable of exporting up to 27.6 million tons of liquefied natural gas annually.  After failing to secure agreements and funding for the plant, Tellurian said late last year that liquidity issues "raise substantial doubt about the Company's ability to continue as a going concern within one year after the date that the financial statements are issued." The company got a delay to its death sentence earlier this month when the Federal Energy Regulatory Agency approved a three-year extension of the deadline for the construction of the facility. The Woodside deal could be interpreted as the last move that Tellurian had to ensure its continued existence in the face of its multiple challenges. “After careful consideration of Tellurian’s opportunities and challenges, the Board and senior management weighed an immediate and significant cash return against the risks and costs associated with the timeline to FID and determined that this offer is in our shareholders’ best interest,” Tellurian’s executive chairman, Martin Houston, said in a press release. The value of the deal, Tellurian said, represented a 75% premium to the company’s closing price on July 19 and a 48% premium to its 30-day volume-weighted average price. The acquisition for Woodside, follows a failed attempt to take over domestic peer Santos earlier this year. #oilandgas Tell us what you want to hear from us. If you want to stay up-to-date with us, follow our Page.

France, the biggest net electricity exporter in Europe, plans to limit power exports to neighboring countries, which could lead to higher prices in other European power markets such as Italy, Switzerland, Belgium, and Germany. France, which derives about 70% of its electricity from nuclear energy, returned last year to the top spot of Europe’s net power exporters, as its nuclear fleet returned from maintenance and domestic demand was lower, analysts at Montel EnAppSys said early this year. The Montel EnAppSys analysis published in February showed that France exported nearly 50 TWh more than it imported in 2023, after turning into a net importer in 2022 for the first time in more than 40 years. However, French grid operator RTE has faced “unprecedented operational constraints on its network” this year, due to historically high exports towards France’s eastern neighboring bidding zones, accentuated by planned and unplanned outages. As a result, RTE limited electricity exports in the spring of 2024, which led to widening and record-high spreads between French day-ahead power prices and those in its neighboring countries. Now RTE said this week it expects “a new tense situation, from 29th of July 2024 until mid-October 2024,” in which it would limit exports to 8 gigawatts (GW). The reasons behind are comparable to the spring curbs in exports, namely the combination of low consumption, abundant and competitive generation coupled to the grid, and high transit flows over the French network. These have led “to significantly high export situations towards France’s eastern bordering bidding zones, in a situation where some planned outages are still required to ensure a well-functioning grid.” As a result of the new planned export curbs, in August and September “Price spreads between France and its eastern neighbors will likely widen again over the curtailment periods,” Florence Schmit, an energy strategist at Rabobank, told Bloomberg. The nearby markets most affected by France’s power export curtailments will be – in descending order – Italy, Switzerland, Germany, and Belgium, according to RTE’s estimates.Anang WuryantoAli Salih

Australia’s Woodside Energy has struck a deal to acquire Tellurian for $1.2 billion as it seeks to turn into a “global LNG powerhouse”. The deal “adds a scalable US LNG development opportunity to our existing approximately 10 Mtpa of equity LNG in Australia,” Woodside chief executive Meg O’Neill said. “Having a complementary US position would allow us to better serve customers globally and capture further marketing optimization opportunities across both the Atlantic and Pacific Basins.” Tellurian has been planning to build Driftwood LNG, a production and export terminal on the Calcasieu River south of Lake Charles, Louisiana for years. Once complete, the terminal would be capable of exporting up to 27.6 million tons of liquefied natural gas annually.  After failing to secure agreements and funding for the plant, Tellurian said late last year that liquidity issues "raise substantial doubt about the Company's ability to continue as a going concern within one year after the date that the financial statements are issued." The company got a delay to its death sentence earlier this month when the Federal Energy Regulatory Agency approved a three-year extension of the deadline for the construction of the facility. The Woodside deal could be interpreted as the last move that Tellurian had to ensure its continued existence in the face of its multiple challenges. “After careful consideration of Tellurian’s opportunities and challenges, the Board and senior management weighed an immediate and significant cash return against the risks and costs associated with the timeline to FID and determined that this offer is in our shareholders’ best interest,” Tellurian’s executive chairman, Martin Houston, said in a press release. The value of the deal, Tellurian said, represented a 75% premium to the company’s closing price on July 19 and a 48% premium to its 30-day volume-weighted average price. The acquisition for Woodside, follows a failed attempt to take over domestic peer Santos earlier this year. #oilandgas Tell us what you want to hear from us. If you want to stay up-to-date with us, follow our Page.

Natural gas production in Egypt, which has seen a massive new gas field come on stream in the Mediterranean in recent years, has plunged to the lowest level in about six years, as the North African country is now importing LNG to meet growing demand. Egypt’s natural gas production fell in May to the levels last seen in February 2018, according to data from the Joint Organizations Data Initiative (JODI) cited by Bloomberg. Egypt has been exporting LNG to Europe, but it usually halts these exports during the summer months, to meet soaring electricity demand in scorching temperatures as most of its electricity output comes from gas-fired power plants. This year, early summer heat waves have made the situation in the country more difficult, and rolling power cuts have been enacted to conserve energy until contracted LNG cargoes arrive to save the day. At the beginning of the summer in June, Egypt was looking to import in the coming months the highest number of LNG cargoes in years, to help it ease the strain on its grid and industry amid energy shortages that have led to rolling blackouts. In June, Egyptian Natural Gas Holding Co, the state gas company, was seeking to purchase at least 17 LNG cargoes for delivery over the next three months. Egypt, which aims to become a regional gas hub, has been exporting LNG to Europe from its terminals on the Mediterranean with gas from domestic production and from fields offshore Israel. However, Egypt rarely exports LNG in the summer months, due to high domestic power demand in the heat waves. Earlier this year, Egyptian Natural Gas Holding sought to lease a liquefied natural gas import terminal from providers of FLNG units to get ahead of the scorching summer season that routinely triggers power blackouts due to the heavier load. As some LNG cargoes have already arrived, Egypt will halt the power cuts as of July 21, Prime Minister Mostafa Madbouly said earlier this week.

WTI crude oil prices could surge to $100 per barrel in the coming year as there are diminished incentives for producers to boost production, according to a note from JP Morgan cited by Forex live. The investment bank estimates that the equilibrium price of WTI oil, the U.S. benchmark, is currently at around $70 per barrel.  A $60 per barrel price for WTI Crude is too low to incentivize production, and this could potentially lead to a spike to $100 per barrel, according to the note carried by Forex live. Early on Thursday, WTI Crude prices were up by 0.7% at $83.45 per barrel, pushed up by a larger-than-expected U.S. crude inventory draw and increasing odds that the Fed would announce the first cut in interest rates in September. After staying depressed at the beginning of this week due to concerns about China’s oil demand, oil prices rose on Wednesday morning following the EIA’s weekly inventory report, which showed an inventory draw of 4.9 million barrels of commercial crude stocks for the week to July 12. This was largely in line with the estimates provided by the American Petroleum Institute, which reported on Tuesday an inventory draw of 4.44 million barrels for the week to July 12 in the throes of the high-demand season. Crude oil inventories in the United States are now roughly 5% below the five-year average for this time of year. Banks and analysts expect oil prices to be well supported in the $80s range in the third quarter amid the peak demand season in the northern hemisphere.  ING, for example, forecasts Brent crude at $88 per barrel for the third quarter of 2024, dropping to $80 a barrel for the full year 2025. The key risk to this outlook is if the OPEC+ group decides to maintain the full extent of its cuts, which could prolong the market deficit into 2025. #eveyone #oilandgas Angelo Machombe FISHGATE OIL AND GAS SERVICES LLC

U.S. gasoline prices have edged slightly higher as oil prices have struggled to break out of the low-$80s, with sluggish U.S. demand one of the factors keeping prices range-bound. Data compiled by GasBuddy from more than 12 million individual price reports covering over 150,000 gas stations across the country has revealed that U.S. gas prices averaged 5.2 cents higher from a month ago but 5.8 cents per gallon lower than a year ago. The national average price of diesel climbed 2.3 cents in the last week to $3.83 per gallon but remained unchanged from a year ago. “Much like last summer, the nation’s average price of gasoline has remained somewhat stuck in the mid-$3 per gallon range with a mixed bag of prices: small declines in some states and modest increases in others as we wait for what could be the next major trend,” said Patrick De Haan, head of petroleum analysis at GasBuddy.  According to De Haan, Hurricane Beryl had no major impact on prices, although some drivers in Texas had trouble finding gasoline due to power outages. De Haan has predicted that we will continue to see small price fluctuations as news of any hurricane-fueled refinery disruptions comes in. Oil prices have kicked in the new week on the back foot with Brent for September delivery continuing to pull back from Friday’s intraday high of $86.10 to trade at $85.05 per barrel in Monday’s session while the WTI August contract has declined $1.39 to $81.94 per barrel. Oil prices have been facing downward pressure with growing concerns about demand in top importer China offsetting support from strong demand elsewhere, OPEC+ supply restraint and geopolitical tensions in the Middle East.  Meanwhile, the dollar has been gaining ground a day after an attempted assassination of the former U.S. President. A stronger dollar makes oil more expensive for buyers with other currencies and tends to weigh on oil and commodity prices. #everuone #oilandgas If you want to stay up-to-date with us, follow our Page.

India is set to launch its tenth bidding round for oil and gas blocks in August or September, the Directorate General of Hydrocarbons (DGH) has said. The latest round will include 25 blocks across 13 sedimentary basins, which are essential for exploration and production activities. The areas on offer range from land blocks covering 16,871 square kilometers, to shallow water blocks and even ultra-Deepwater blocks extending over 12,373 square kilometers. The move aims to attract significant investment and boost domestic oil and gas production. In the previous ninth bidding round under the Hydrocarbon Exploration and Licensing Policy (HELP), the government extended the deadline multiple times in order to provide more detailed data to help companies make informed decisions that it hoped would improve the lukewarm response the earlier rounds generated. Some of the lukewarm responses from foreign firms have been linked to concerns about indemnity and compensation issues—issues that India is working to address. The ninth bidding round, with 28 oil and gas blocks up for grabs, was originally set to close on February 29, but was extended until May 15. India then extended it to July 15. India now has extended it until August 31. The Indian government is also working on shrinking approval times to enhance domestic production and decrease reliance on imports. For India—the world’s second-largest oil importer—foreign investment in developing its oil and gas industry is critical, with the country’s crude oil demand growing this year despite higher prices. According to the IEA, India is set to become the biggest driver of oil demand growth in the world between now and 2030. It currently imports 4.6 million bpd. #oilandgas #everyone Ali Al Marhoun FISHGATE OIL AND GAS SERVICES LLC Rosemarie Rutecki, PharmD, IFMCP you want to stay up-to-date with us, follow our Page.

The Department for Energy Security and Net Zero denied reports that Ed Miliband has banned the North Sea oil regulator from issuing any outstanding drilling and exploration licenses, calling them “a complete fabrication”. Energy Secretary Ed Miliband has enacted an immediate ban on new North Sea oil drilling licenses, overriding departmental officials and setting the stage for potential legal confrontations with oil companies. This decision halts the expected approval of new drilling in up to 35 areas, a process initiated during the 33rd offshore oil and gas licensing round in late 2023. Miliband’s directive is aimed at aligning the UK’s energy policies with its climate commitments, but oil companies that had invested substantial monetary resources into preparing their bids are likely to retaliate with legal action in order to recoup the millions of pounds spent. The North Sea Transition Authority had said only a day ago that the applications for the 35 areas were still being considered despite the regime change in the government. But the Energy Secretary has now made it clear that no licenses for new fields will be approved. Miliband, a known opponent of oil and gas expansion, has argued that new licensing would not lower energy costs, enhance security, or provide a sustainable future for offshore energy communities. Instead, Miliband maintains, the UK must avoid reliance on fossil fuel markets, which are controlled by “petrostates and dictators.” This stance has been met with considerable concern from the energy sector. Industry analysts highlight that the UK, which sources 75% of its energy from oil and gas, could face increased dependency on imports, undermining energy security. Offshore Energies UK warns that domestic production is already declining at 8% annually, a rate that could accelerate to 15% without new drilling initiatives. The forthcoming policies detailed in the King’s Speech on July 17 will be crucial in shaping the future of the UK's energy landscape by detailing taxation plans for the country’s oil and gas industry. #everyone #oilandgas TotalEnergies Oil and Gas Job Search Ltd If you want to stay up-to-date with us, follow our Page.