Western Midstream Partners LP (WES) announced Tuesday it has amended its natural gas gathering and processing contracts in the Delaware Basin with Occidental Petroleum Corp and expanded its partnership with ConocoPhillips in the same basin. The new agreements with ConocoPhillips and Occidental advance WES’ transition to fixed-fee arrangements in the maturing basin, The Woodlands, Texas-based company said in a statement on its website. The previous agreement with Occidental already provided for a transition to a fixed-fee structure; the new agreement speeds up that transition, according to WES. Houston, Texas-based oil, gas and chemicals producer Occidental agreed to reduce its ownership in WES from about 42 percent to around 40 percent under the renegotiated gathering and processing contracts, “further positioning WES as a standalone midstream enterprise”, WES said. “Following this amendment, approximately nine percent of WES’ total revenue will remain subject to cost-of-service rates, with approximately one percent of total revenue subject to cost-of-service rates expiring in the late 2020s”, WES said. “The remaining cost-of-service rate provisions extend into the mid-to-late 2030s and include provisions to convert to fixed-fee structures at that time. “All significant fixed-fee contracts with Occidental, including the contracts being amended, are effective through the mid-to-late 2030s”. The new gas gathering contract provides “volumetric protection via substantial minimum volume commitments (MVCs) through the original cost-of-service term, and from that point forward, the existing acreage dedication and fixed-fee structure continues through the duration of the contract”, WES added. The new gas processing contract “continues to provide volumetric protection via MVCs through 2035”, WES said. As part of the renegotiated contracts, Occidental will surrender to WES 15.3 million common units currently owned by Occidental. The volume represents around $610 million of limited partnership interests, according to WES. “This transfer was structured on terms intended to represent a value-neutral exchange for the economic concessions reflected in

U.S. natural gas prices are rising today due to a combination of weather risk, production softness, and positioning, rather than any single structural shift. That’s what Ole R. Hvalbye, a commodities analyst at Skandinaviska Enskilda Banken AB (SEB), told Rigzone in an exclusive interview on Wednesday. “First, the weather premium has kicked in hard,” Hvalbye said. “Forecasts now show temperatures in the Lower-48 turning well below normal from around January 23 and extending into early February, particularly across the eastern half of the United States,” he added. “That directly lifts heating demand expectations at a time of year when the market is already sensitive(!). As a result, Henry Hub has surged from … [around] $3 per MMBtu [million British thermal units] last week to nearly $5 per MMBtu intraday today!” he noted. “Second, supply has tightened at the margin. Lower-48 dry gas production has dipped to around 110.5 Bcfpd [billion cubic feet per day], down from over 112 Bcfpd earlier this week, partly reflecting cold-weather disruptions,” Hvalbye continued. “At the same time, LNG feedgas demand remains elevated at just over 18 Bcfpd, even though flows at Sabine Pass eased slightly today, partly offset by higher intake at Elba Island,” he stated. “Third, positioning and short covering are amplifying the move,” Hvalbye highlighted. The SEB commodities analyst told Rigzone that trading volumes in Henry Hub futures hit a record high earlier this week and added that today’s rally has been pushed by hedge funds covering short positions built up during the recent sell-off. “That adds momentum once prices start moving,” he pointed out. Looking at the demand side, Hvalbye told Rigzone that U.S. gas consumption “has eased back toward ~108 Bcfpd from very high cold-weather levels earlier this week” but added that “that hasn’t been enough to offset the weather risk

The European Commission on Tuesday made the first call for buyer expressions of interest for hydrogen supply offers under a matchmaking platform launched last year. In a call to suppliers that closed earlier this month, European and international companies placed offers from over 260 projects, the Commission’s Directorate-General for Energy said in an online statement. Buyers now have until March 20, 2026 to indicate interest in the offers, according to the statement. “As part of the EU Energy and Raw Materials Platform, the Hydrogen Mechanism connects potential off-takers in Europe with suppliers of renewable and low-carbon hydrogen or derivatives, including ammonia, methanol, eMethane and electro-sustainable aviation fuel”, the Directorate-General said. “Hydrogen plays an important role in decarbonizing industrial processes and industries for which reducing carbon emissions is both urgent and hard to achieve”, it added. “At the same time, it can strengthen the competitiveness of Europe’s industry and leverage the EU market towards more security of supply, diversification and decarbonization”. European Energy and Housing Commissioner Dan Jørgensen said, “The EU’s Hydrogen Mechanism is a new, innovative tool to help develop the market. With strong interest shown from suppliers across Europe and beyond, the initiative is off to a very promising start”. The broader European Union Energy and Raw Materials Platform lets buyers in the 27-member bloc offer demand for biomethane, hydrogen, natural gas and raw materials. The online platform seeks to give EU companies cost-effective and efficient access to such commodities by enabling negotiations with competing suppliers, according to the Commission. The Hydrogen Mechanism will operate until 2029 under the European Hydrogen Bank, as specified under the EU’s “Regulation on the Internal Markets for Renewable Gas, Natural Gas and Hydrogen”. The Hydrogen Bank is an EU Innovation Fund financing platform to scale up the renewable hydrogen value chain. The platform’s user

OMV Petrom SA and NewMed Energy LP have signed a deal to sell 10 percent in the Han Asparuh exploration block on Bulgaria’s side of the Black Sea to state-owned Bulgarian Energy Holding EAD (BEH) following a government order. The Bulgarian parliament had directed the Energy Ministry to have up to 20 percent of the license transferred to a government-owned corporation, NewMed Energy said in a stock filing. Operator OMV Petrom, an integrated energy company with investments from Austria’s state-backed OMV AG and the Romanian government, and equal co-owner NewMed Energy, an Israeli natural gas-focused explorer and producer, have now agreed to sell five percent each to BEH, according to the regulatory disclosure. The Bulgarian government still needs to approve the sale agreement and the companies need to amend the “joint operating agreement” for Han Asparuh before the sale could be completed, NewMed Energy said. Under the sale agreement, “the parties agreed to work jointly vis-à-vis the Bulgarian government and the Bulgarian Ministry of Energy in connection with amendments to the ordinance for determining the concession royalty payments for the production of underground resources and extension of the period of the appraisal drillings in the project to two years in lieu of one year”, NewMed Energy said. “It is noted in this context that on 8 December 2025, the Bulgarian Ministry of Energy released a draft of new regulations for determining royalty payments to the Bulgarian government, which are determined by multiplying the economic value of annual production by the royalty rate payable to the government”. “It is further proposed to establish in the draft regulations a minimum annual royalty payment obligation”, NewMed Energy added. BEH has agreed to pay NewMed Energy and OMV Petrom its proportionate share of the cost of drilling preparations, NewMed Energy said. A two-well campaign

In a research note sent to Rigzone by the HSBC team this week, HSBC analysts, including Kim Fustier, HSBC’s Senior Global Oil and Gas Analyst, said they think BP “could accentuate its shift back to oil and gas and away from low carbon energy” under its new CEO. “BP’s 4Q25 results in February will take place during yet another period of transition for the company,” the analysts said in the note. “Incoming CEO Meg O’Neill will assume the role on April 1, following the unexpected departure of Murray Auchincloss in late December and interim leadership of Carol Howle,” they added. “We do not expect major strategic announcements at BP’s 4Q results yet, almost a year since its ‘fundamental reset’. Under its new CEO, we think BP could accentuate its shift back to oil and gas and away from low carbon energy,” they continued. The HSBC analysts stated in the research note that they would also expect a greater emphasis on cost savings and capital efficiency. “On our estimates, there is no immediate financial pressure on BP’s $3 billion annual buyback in a $60-65 per barrel Brent environment as it is dwarfed by the scale of yet to be announced disposals of c$9 billion,” the analysts noted. “That said, BP could choose to cut buybacks out of prudence as deleveraging remains a priority, or if it sees the current interim period as an opportune time to reset shareholder distributions,” they added. Rigzone has contacted BP for comment on HSBC’s research note. At the time of writing, BP has not responded to Rigzone. In a statement posted on its website on December 17, BP announced that its board had appointed O’Neill as BP’s next CEO, effective April 1, noting that Murray Auchincloss had decided to step down from his position as CEO

Norway’s natural gas output averaged 367.6 million cubic meters (12.98 billion cubic feet) a day (MMcmd) in December, increasing for the third consecutive month sequentially and marking last year’s highest monthly production, according to preliminary monthly production figures released Tuesday by the country’s upstream regulator. Last month’s gas production exceeded the Norwegian Offshore Directorate’s (NOD) forecast by 2.9 percent and rose 1.5 percent from November, the NOD reported on its website. Year-on-year the December figure climbed 1.6 percent. The Nordic country sold 11.4 billion cubic meters (Bcm) of gas in December, up 600 MMcm from November. In the third quarter of 2025, the Nordic country accounted for 51.8 percent of pipeline gas imported into the European Union, according to EU statistics agency Eurostat. “Norwegian gas accounts for about 30 percent of EU gas consumption, and Norway is Europe’s largest supplier after cutting off Russian gas”, the NOD said earlier in “The Shelf 2025” report published January 8, 2026. The Equinor ASA-operated Troll field in the North Sea accounts for about one-third of Norway’s gas production. The NOD said in that report it expects Troll to hold onto the position “over the next few years”, noting most new developments “are relatively small discoveries that are being developed with subsea templates or wells from existing subsea templates, and tied back to existing infrastructure”. Meanwhile Norway’s oil production in December averaged two million barrels per day (MMbpd), up 4.6 percent from November 2025 and 9.7 percent from December 2024, the NOD said Tuesday. The figure beat the NOD projection by 5.1 percent. Total liquids production in December was 2.2 MMbpd, up 4.9 percent month-over-month and 8.1 percent year-on-year. “Preliminary production figures for December 2025 show an average daily production of 2,190,000 barrels of oil, NGL [natural gas liquids] and condensate”, the NOD said. “The total