US oil supplies at new 18 year low, SPR at a 37 year low; DUC wells at an all time low, DUC backlog at 4.4 months

US oil supplies at new 18 year low, Strategic Petroleum Reserve at a 37 year low, DUC wells at an all time low, DUC backlog at 4.4 months, lowest since March 2015

oil prices fell for the fourth time in 5 weeks after the EIA report​ confirmed weak summertime demand for fuel ...after falling 6.9% to $97.59 a barrel last week as a new Covid outbreak in China threatened demand while rising inflation in the US & Europe bolstered the case for economy-crushing interest rate hikes, the contract price for the benchmark US light sweet crude for August delivery moved higher in early trading on Monday after Saudi officials indicated no additional production would come online following Biden's visit, and settled $5.01, or 5.1% higher, at $102.60 a barrel, boosted by dollar weakness and ​by ​indications that the Fed wouldn't raise interest rates by a full percentage point at their coming meeting....however, oil prices fell sharply in early trading on Tuesday as new Covid-19 cases in China jumped and new data showed the euro zone's inflation accelerated to a fresh record high, increasing worries about a possible recession, but reversed higher in afternoon trade Tuesday on a sharp drop in the U.S. dollar index and ​on ​a rallying stock market, and finished $1.62 higher at $104.22 a ​barrel,​​​​​​ after a disruption of the Keystone pipeline cut shipments of Canadian oil to US refiners...oil prices slipped lower in overnight trading after the American Petroleum Institute reported increases of crude and gasoline inventories, and then declined on that news in early NYMEX trading on Wednesday, as renewed strength in the U.S. Dollar Index put further pressure on prices, and then extended those losses after the EIA report confirmed those larger-than-expected builds in U.S. crude and gasoline stockpiles and settled $1.96 lower at $102.26 a barrel, as EIA data showed lackluster gasoline demand during the peak summer driving season and as interest rate hikes by central banks fed fears the economy ​would slow...with trading in the August contract expired on Wednesday and US oil prices quotes referencing the contract for the benchmark US light sweet crude for September delivery on Thursday, prices continued lower in early trading on demand concerns in both the US and China, and tumbled $3.53 to settle at $96.35 a barrel after a European Central Bank rate hike stoked demand worries, while returning oil supply from Libya and the resumption of Russia’s gas flows to Europe eased supply restraints...oil prices eroded further in early morning trading on Friday, with all petroleum contracts on course for hefty losses for the week, after overnight data out of Europe showed manufacturing activity unexpectedly contracted in July, while the return of Libya's oil exports to the global market further weighed on the complex, and settled $1.65 lower at $94.70 a barrel after the European Union said it would allow Russian state-owned companies to ship oil to third countries under an adjustment of sanctions agreed to by member states...oil prices thus finished 3.0% lower on the week, while the September oil contract, which had finished last week priced at $94.57 a barrel, actually finished fractionally higher...

natural gas prices, on the other hand, finished higher for a third consecutive week on record power demand and forecasts for ​further records...after rising 16.3% to $7.016 per mmBTU last week as record heat across the South led to record natural gas deliveries to the electricity generation sector, the contract price of natural gas for August delivery opened 3% higher and jumped to an intraday high of $7.554 by midday Monday as soaring temperatures baked much of the Lower 48 and forecasts called for heat waves to fester through July and into next month, before settling with a 46.3 cent or 7% gain at $7.479 per mmBTU...but natural gas prices gave up 21.5 cents of that gain on Tuesday to settle at $7.264 per mmBTU, after mid-range heat forecasts eased slightly and a new outlook called for record production on the horizon....however, natural gas prices soared more than 10% to a five-week high on Wednesday, as a brutal heat wave boosted power demand to a record high amid forecasts that next week was expected to be the hottest of the season, as the August gas contract settled 74.3 cents higher at $8.007 per mmBTU....natural gas prices initially surged 35 cents following an anemic storage report on Thursday, but see-sawed to close 7.5 cents or 1% lower at $7.932 per mmBTU on forecasts for less hot weather over the next two weeks than was previously expected​,​ and ​on ​the return to partial service of the Russia to Germany Nord Stream gas pipeline...but prices jumped 5% to another 5 week high on Friday on the heels of a solidly bullish storage report and a shift hotter in an already sizzling late-summer weather outlook and settled 36.7 cents higher at $8.299 per mmBTU, and thus finished with a 15.5%, $1.283 gain on the week...

The EIA's natural gas storage report for the week ending July 15th indicated that the amount of working natural gas held in underground storage in the US rose by 32 billion cubic feet to 2,401 billion cubic feet by the end of the week, which left our gas supplies 270 billion cubic feet, or 10.1% below the 2,671 billion cubic feet that were in storage on July 15th of last year, and 328 billion cubic feet, or 12.0% below the five-year average of 2,729 billion cubic feet of natural gas that have been in storage as of the 15th of July over the most recent five years....the 32 billion cubic foot injection into US natural gas working storage for the cited week was well below the average forecast for a 41 billion cubic foot injection from an S&P Global Platts survey of analysts, and much less than the 50 billion cubic feet that were added to natural gas storage during the corresponding week of 2021, and also lower than the average injection of 41 billion cubic feet of natural gas that has typically been added to our natural gas storage during the same week over the past 5 years....  

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending July 15th indicated that despite another large oil withdrawal from the SPR and a sizable increase in oil supplies that could not be accounted for​, ​we needed to withdraw oil from our stored commercial crude supplies for the 3rd time in 7 weeks, and for the 20th time over the past 34 weeks, ​mostly because of a big increase in our oil exports…our imports of crude oil fell by an average of 156,000 barrels per day to an average of 6,519,000 barrels per day, after falling by an average of 164,000 barrels per day during the prior week, while our exports of crude oil rose by 735,000 barrels per day to 3,759,000 barrels per day, which meant that our trade in oil worked out to a net import average of 2,760,000 barrels of oil per day during the week ending July 15th, 891,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, production of crude from US wells was reportedly 100,000 barrels per day lower at 11,900,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to have totaled an average of 14,660,000 barrels per day during the July 15th reporting week…

Meanwhile, US oil refineries reported they were processing an average of 16,319,000 barrels of crude per day during the week ending July 15th, an average of 321,000 fewer barrels per day than the amount of oil than our refineries processed during the prior week, while over the same period the EIA’s surveys indicated that a net average of 778,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US....so based on that reported & estimated data, the crude oil figures from the EIA for the week ending July 15th appear to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 881,000 barrels per day less than what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+881,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet in order to make the reported data for the daily supply of oil and for the consumption of it balance out, a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been an omission or error of that magnitude in this week’s oil supply & demand figures that we have just transcribed... however, since most everyone treats these weekly EIA reports as gospel, and since these figures often drive   oil pricing, and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it's published, and just as it's watched & believed to be reasonably accurate by most everyone in the industry...(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….

This week's 778,000 barrel per day decrease in our overall crude oil inventories left our oil supplies at 906,758,000 barrels at the end of the week, our lowest total oil inventory level since February 27th, 2004, and therefore at a new 18 year low….our oil inventory decreased this week as 64,000 barrels per day were being pulled out of our commercially available stocks of crude oil and 714,000 barrels per day of oil were being pulled out of our Strategic Petroleum Reserve....the draw on the SPR was part of the emergency withdrawal under Biden's "Plan to Respond to Putin’s Price Hike at the Pump"​ (sic)​, that was expected to supply 1,000,000 barrels of oil per day to commercial interests over a six month period up to the midterm elections in November, in the hope of keeping gasoline and diesel fuel prices from rising further at least up until that time...the administration's previous 30,000,000 million barrel release from the SPR to address Russian supply related shortfalls wrapped up in June, and his earlier release of 50 million barrels from the SPR to incentivize US gasoline consumption was completed in May....including those, and other withdrawals from the Strategic Petroleum Reserve under recent release programs, a total of 175,998,000 barrels of oil have now been removed from the Strategic Petroleum Reserve over the past 24 months, and as a result the 480,149,000 barrels of oil still remaining in our Strategic Petroleum Reserve is now the lowest since July 12th, 1985, or at a 37 year low, as repeated tapping of our emergency supplies for non-emergencies or to pay for other programs had already drained those supplies considerably over the past dozen years, even before the Biden administration's SPR releases....now the total 180,000,000 barrel drawdown expected over the current six month release program to November will remove almost a third of what remained in the SPR when the program started, and leave us with what would be less than a 20 day supply of oil at today's consumption rate... 

Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,508,000 barrels per day last week, which was 3.8% more than the 6,400,000 barrel per day average that we were importing over the same four-week period last year….this week’s crude oil production was reported to be 100,000 barrels per day lower at 11,900,000 barrels per day because the EIA's rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day lower at 11,500,000 barrels per day, while Alaska’s oil production was 3,000 barrels per day higher at 435,000 barrels per day but had no impact on the final rounded national total....US crude oil production had reached a pre-pandemic high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 9.2% below that of our pre-pandemic production peak, but was 22.7% above the pandemic low of 9,700,000 barrels per day that US oil production had fallen to during the third week of February of 2021...

US oil refineries were operating at 93.7% of their capacity while using those 16,319,000 barrels of crude per day during the week ending July 15th, down from their 94.9% utilization rate during the prior week, but in line with the historical refinery utilization rates of mid summer…the 16,319,000 barrels per day of oil that were refined this week were 1.9% more than the 16,007,000 barrels of crude that were being processed daily during week ending July 16th of 2021, but 4.2% less than the 17,034,000 barrels that were being refined during the prepandemic week ending July 19th, 2019, when our refinery utilization was at 93.1%, a rate slightly below normal for mid-July...

Even with the decrease in the amount of oil being refined this week, gasoline output from our refineries was still much higher, increasing by 447,000 barrels per day to 9,368,000 barrels per day during the week ending July 15th, after our gasoline output had decreased by 1,425,000 barrels per day during the prior week…this week’s gasoline production was ​also 2.6% more than the 9,130,000 barrels of gasoline that were being produced daily over the same week of last year, but 7.4% less than our gasoline production of 10,089,000 barrels per day during the week ending July 19th, 2019, ie, during the year before the pandemic impacted US gasoline output....​meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 102,000 barrels per day to 9,855,000 barrels per day, after our distillates output had decreased by 246,000 barrels per day during the prior week…even with that decrease, our distillates output was 2.6% more than the 4,902,000 barrels of distillates that were being produced daily during the week ending July 16th of 2021, but 3.6% less than the 5,219,000 barrels of distillates that were being produced daily during the week ending July 19th, 2019...

With the increase in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the fourth time in five weeks.; but for just the fifth time out of the past twenty-four weeks, increasing by 3,489,000 barrels to 228,435,000 barrels during the week ending July 15th, after our gasoline inventories had increased by 5,825,000 barrels during the prior week...our gasoline supplies increased by less this week because the amount of gasoline supplied to US users increased by 459,000 barrels per day to 8,521,000 barrels per day, after domestic gasoline supplied had decreased by a near record 1,351,000 barrels per day during the prior week, and even as our imports of gasoline rose by 150,000 barrels per day to 865,000 barrels per day while our exports of gasoline fell by 34,000 barrels per day to 806,000 barrels per day..​.​.but after 19 inventory drawdowns over the past 24 weeks, our gasoline supplies were 3.4% lower than last July 16th's gasoline inventories of 236,414,000 barrels, and about 3% below the five year average of our gasoline supplies for this time of the year…

After the recent decreases in our distillates production, our supplies of distillate fuels decreased for the 3rd time in ten weeks and for the 28th time in forty-six weeks,falling by 1,295,000 barrels to 112,508,000 barrels during the week ending July 15th, after our distillates supplies had increased by 2,668,000 barrels during the prior week….our distillates supplies fell this week even though the amount of distillates supplied to US markets, an indicator of our domestic demand, increased by 329,000 barrels per day to 3,697,000 barrels per day, after distillates demand had fallen by 1,014,000 barrels per day to a one year low the prior week, as our exports of distillates rose by 121,000 barrels per day to 1,642,000 barrels per day while our imports of distillates fell by 15,000 barrels per day to 122,000 barrels per day....but after forty-four inventory withdrawals over the past sixty-six weeks, our distillate supplies at the end of the week were 20.2% below the 141,000,000 barrels of distillates that we had in storage on July 16th of 2021, and still about 23% below the five year average of distillates inventories for this time of the year…

Meanwhile, with this week's increase in our oil exports and decreases in our imports and production, our commercial supplies of crude oil in storage fell for the 6th time in 10 weeks and for the 31st time in the past year, decreasing by 445,000 barrels over the week, from 427,054,000 barrels on July 8th to 426,609,000 barrels on July 15th, after our commercial crude supplies had increased by 3,254,000 barrels over the prior week…after that modest decrease, our commercial crude oil inventories remained about 8% below the most recent five-year average of crude oil supplies for this time of year, but about 25% above the average of our crude oil stocks as of the third weekend of July over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels....since our commercial crude oil inventories had jumped to record highs during the Covid lockdowns of the Spring of 2020, and then jumped again after last year's winter storm Uri froze off US Gulf Coast refining, our commercial crude supplies as of this July 15th were still 3.0% less than the 439,687,000 barrels of oil we had in commercial storage on July 16th of 2021, and were 20.5% less than the 536,580,000 barrels of oil that we had in storage on July 17th of 2020, and 4.1% less than the 445,041,000 barrels of oil we had in commercial storage on July 19th of 2019…

Finally, with our inventories of crude oil and our supplies of all products made from oil ​receently near multi year lows, we are continuing to keep track of the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR....the EIA's data shows that the total of our oil and oil product inventories, including those in the Strategic Petroleum Reserve and those held by the oil industry, and thus including everything from gasoline and jet fuel to propane/propylene and residual fuel oil, fell by 3​,862,000 barrels this week, from 1,692,658,000 barrels on July 8th to 1,688,796,000 barrels on July 15th, after our total inventories had risen by 14,863,000 barrels during the prior week...that left our total liquids inventories down by 99,637,000 barrels over the first 28 weeks of this year, but still nearly 11 million barrels from a new 13 1/2 year low... 

This Week's Rig Count

The number of drilling rigs running in the US increased for the 80th time over the prior 95 weeks during the week ending July 22nd, but still remained 4.4% below the prepandemic rig count....Baker Hughes reported that the total count of rotary rigs drilling in the US increased by 2 to 758 rigs this past week, which was also 267 more rigs than the 491 rigs that were in use as of the July 23rd report of 2021, but was still 1,171 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, a week before OPEC began to flood the global market with oil in an attempt to put US shale out of business….

The number of rigs drilling for oil was unchanged at 599 oil rigs during the past week, after rigs targeting oil had risen by 2 during the prior week, and there are still 212 more oil rigs active now than were running a year ago, even as they still amount to just 37.2% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014, and as they are still down 12.3% from the prepandemic oil rig count….at the same time, the number of drilling rigs targeting natural gas bearing formations increased by 2 to 155 natural gas rigs, which was also up by 51 natural gas rigs from the 104 natural gas rigs that were drilling during the same week a year ago, even as they were still only 9.7% of the modern high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…

In addition to rigs targeting oil and natural gas, Baker Hughes continues to report four "miscellaneous" rigs active; including a horizontal rig drilling between 5,000 to 10,000 feet into the Permian basin in Dawson county Texas, and a directional rig drilling between 5,000 to 10,000 feet on the big island of Hawaii, a rig drilling vertically to between 10,000 and 15,000 feet for a well or wells intended to store CO2 emissions in Mercer county North Dakota, and another vertical rig, drilling more than 15,000 feet into a formation in Humboldt county Nevada that Baker Hughes doesn't track...a year ago, there were no such "miscellaneous" rigs running...

The offshore rig count in the Gulf of Mexico was up by 1 to 14 rigs this week, with all of this week's Gulf rigs drilling for oil in Louisiana's offshore waters....that's still 3 less than the 17 offshore rigs that were active in the Gulf a year ago, when 16 Gulf rigs were drilling for oil offshore from Louisiana and one was deployed for oil offshore from Texas.…in addition to rigs drilling in the Gulf, we now have two offshore directional rigs drilling for natural gas in the Cook Inlet of Alaska; one is indicated to be drilling to between 10,000 and 15,000 feet, ​while ​the new one is is indicated to be drilling to between 5,000 and 10,000 feet...a year ago, there were no offshore rigs other than those deployed in the Gulf of Mexico....

in addition to rigs running offshore, there are now 4 water based rigs drilling through inland bodies of water....one is a directional rig targeting oil at a depth of 10,000 to 15,000 feet in Cameron parish, Louisiana; others include a directional rig targeting oil at a depth greater than 15,000 feet on Grand Isle, Louisiana, and two directional inland water rigs drilling for oil in Terrebonne Parish, Louisiana, one of which is targeting a formation greater than 15,000 feet in depth, while the other is shown drilling to between 10,000 and 15,000 feet... during the same week of a year ago, there was just one such "inland waters" rig deployed...

The count of active horizontal drilling rigs was up by one to 687 horizontal rigs this week, which was also 248 more rigs than the 439 horizontal rigs that were in use in the US on July 23rd of last year, but just half of the record 1,374 horizontal rigs that were drilling on November 21st of 2014....at the same time, the vertical rig count was up by 1 to 31 vertical rigs this week, and those were also up by 12 from the 19 vertical rigs that were operating during the same week a year ago…on the other hand, the directional rig count was unchanged at 40 directional rigs this week, while those were still up by 7 from the 33 directional rigs that were in use on July 23rd of 2021…. 

The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of July 22nd, the second column shows the change in the number of working rigs between last week’s count (July 15th) and this week’s (July 22nd) count, the third column shows last week’s July 15th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 23rd of July, 2021...

the 2 rig increase in Alaska came as an offshore rig was added in the Cook Inlet, another natural gas rig was added in Tyonek of the Athabascan region, and an oil rig was added in Sagavanirktok in the North Slope Borough, while a gas rig was removed from the Kenai peninsula...the 2 rig increase in Louisiana came as an oil rig was added in the state's offshore waters and an inland waters oil rig was added in Cameron parish...

checking the Rigs by State file at Baker Hughes for the changes in Texas, we first find that a rig was added in Texas Oil District 1, which accounts for the oil rig that added in the Eagle Ford shale, and that a rig was added in Texas Oil District 10 of the Texas panhandle, which accounts for the rig added in the Granite Wash basin....at the same time, an oil rig was pulled out Texas Oil District 9, which would have been drilling in a basin that Baker Hughes doesn't track....we also find that an oil rig was pulled out Texas Oil District 8, which covers the core Permian Delaware, but that a natural gas rig was added in Texas Oil District 8A, which includes the northern counties of the Permian Midland...since th​ose indicate no ​net ​change in the Permian basin in Texas, we have to conclude that the rig removed from New Mexico had been drilling in the western Permian Delaware for the national Permian count to show a loss of one....the Permian now has two natural gas rigs, one miscellaneous rig, and 346 oil rigs running...the Texas rig count ended unchanged because the inland waters oil rig that had been drilling in Galveston Bay was pulled out at the same time...

meanwhile, the rig that was removed from Utah had been drilling in the Uintah basin, where all of Utah's drilling is taking place​,​ even as it not tracked by Baker Hughes...the two oil rigs that were pulled out of Oklahoma's Ardmore Woodford were offset by two oil rig additions in the state's Cana Woodford, leaving the Oklahoma rig count unchanged...a similar combination of oil rig removals and oil rig additions left the national oil rig count unchanged, while the natural gas rig count was up by two with the net additions in the Permian basin ​and ​in the Cook Inlet, and offshore from Alaska....

DUC well report for June

Monday of this week saw the release of the EIA's Drilling Productivity Report for July, which included the EIA's June data on drilled but uncompleted (DUC) oil and gas wells in the 7 most productive shale regions (shown under the report's tab 3)....that data showed a decrease in uncompleted wells nationally for the 24th consecutive month, as both completions of drilled wells and drilling of new wells increased in June, but remained well below average pre-pandemic levels...for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 26 wells, falling from 4,271 DUC wells in May to 4,245 DUC wells in June, which was the lowest number of US wells left uncompleted on record, and also 31.1% fewer DUCs than the 6,159 wells that had been drilled but remained uncompleted as of the end of June of a year ago...this month's DUC decrease occurred as 938 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during June, up from the 909 wells that were drilled in May, while 964 wells were completed and brought into production by fracking them, up by just 3 from the 961 well completions seen in May, but up by 245 from the 716 completions seen in June of last year....at the June completion rate, the 4,245 drilled but uncompleted wells remaining at the end of the month represents a 4.4 month backlog of wells that have been drilled but are not yet fracked, unchanged from the DUC well backlog of a month ago, which ​is the lowest DUC backlog since March 2015, despite a completion rate that is still more than 15% below 2019's pre-pandemic average...

only the oil producing regions saw a net DUC well decrease during June, since both ​of ​the natural gas producing Appalachian and Haynesville shales saw modest DUC well increases....the number of uncompleted wells remaining in the Permian basin of west Texas and New Mexico decreased by 30, from 1,244 DUC wells at the end of May to 1,214 DUCs at the end of June, as 408 new wells were drilled into the Permian basin during June, while 438 already drilled wells in the region were being fracked....in addition, the number of uncompleted wells remaining in Oklahoma's Anadarko basin decreased by 8, falling from 727 at the end of May to 719 DUC wells at the end of June, as 62 wells were drilled into the Anadarko basin during June, while 70 Anadarko wells were completed....meanwhile, there was a decrease of 1 DUC well in the Bakken of North Dakota, where DUC wells fell from 425 at the end of May to a record low of 424 DUCs at the end of June, as 76 wells were drilled into the Bakken during June, while 77 of the drilled wells in the Bakken were being fracked...at the same time, DUCs in the Eagle Ford shale of south Texas also decreased by 1, from 598 DUC wells at the end of May to a record low of 597 DUCs at the end of June, as 110 wells were drilled in the Eagle Ford during June, while 111 already drilled Eagle Ford wells were fracked....on the other hand, DUC wells in the Niobrara chalk of the Rockies' front range increased by 1, riising from 310 at the end of May to 311 DUC wells at the end of June, as 109 wells were drilled into the Niobrara chalk during June, while 108 Niobrara wells were completed....

among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, rose by one well, from 526 DUCs at the end of May to 527​ ​DUCs at the end of June, as 98 wells were drilled into the Marcellus and Utica shales during the month, while 97 of the already drilled wells in the region were fracked....at the same time, the uncompleted well inventory in the natural gas producing Haynesville shale of the northern Louisiana-Texas border region rose by 13, from 419 DUCs in May to 432 DUCs by the end of June, as 75 wells were drilled into the Haynesville during June, while 63 of the already drilled Haynesville wells were fracked during the same period....thus, for the month of June, DUCs in the five major oil-producing basins tracked by this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a net total of 39 wells to 3,265 DUC wells, while the uncompleted well count in the major natural gas basins (the Marcellus, the Utica, and the Haynesville) increased by net of 13 wells to 980 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas...

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Fracking Co. Tells Ohio Justices Its Equipment Is Exempt – Law360 - A hydraulic fracturing company asked the Ohio Supreme Court to find that its equipment purchases used in oil and gas production were exempt from sales and use tax. Stingray Pressure Pumping LLC asked the Ohio Supreme Court in a brief filed Thursday to reexamine the company's request for sales and use tax exemptions

47 New Shale Well Permits Issued for PA-OH-WV Jul 11-17 | Marcellus Drilling News - For the week of July 11-17, the three Marcellus/Utica states issued 47 permits to drill new shale wells, up 10 from the prior week. Pennsylvania issued the lion’s share with 35 new permits. CNX grabbed seven of those permits in Washington County, and Olympus Energy received six in Westmoreland County. Ohio issued 11 new permits, with four going to Ascent Resources in Jefferson County, and four to Hilcorp Energy in Columbiana County. West Virginia issued a paltry one new permit, which went to Southwestern Energy in Ohio County.tags: Apex Energy, Armstrong County, Ascent Resources, Bradford County, Butler County, Cabot Oil & Gas, Carroll County, Chesapeake Energy, Clarion County, CNX Resources,Columbiana County, Encino Energy, Energy Companies, EOG Resources, Hilcorp Energy, Inflection Energy, Jefferson County (OH), Laurel Mountain Energy, LOLA Energy, Lycoming County, Ohio County, Olympus/Huntley & Huntley, PennEnergy Resources, Range Resources Corp, Southwestern Energy, Susquehanna County, Washington County, Weekly Permits, Westmoreland County, Wyoming County (PA)

A shale well met an abandoned well a mile away. How did it happen? - Pittsburgh Post-Gazette On June 19, Zach Debolt noticed a geyser shooting up 15 feet above the ground on his property in New Freeport, Greene County.That’s how he described it to James Gillin, a township supervisor and his neighbor, when Mr. Gillin ran over to see what was going on. The geyser was gone by that point, but Mr. Gillin could see water rushing underground through a sinkhole that had formed around an old, abandoned gas well.Mr. Gillin called EQT Corp., the Downtown-based natural gas company that was fracking shale wells from a pad more than a mile away. At that moment, EQT was pumping large volumes of water, sand and chemicals through holes in a pipe that extends horizontally for thousands of feet underground. The pressure of that rush of water is intended to create fractures that extend through the Marcellus Shale formation, releasing the gas trapped inside.EQT stopped fracking the Lumber 13H well that day, and the liquid and gas in the abandoned well on Mr. Debolt’s property subsided. The next day, the company notified the Pennsylvania Department of Environmental Protection of a well communication issue — a term that means one well has interacted with another.Since then, the company and the DEP have been investigating exactly what happened.“They’re going to want to know where all this water went,” Mr. Gillin said, referring to the fast-flowing river he saw through the sinkhole.If fluid from a frack job 1.5 miles underground reached an old shallow well 1.2 miles away from the Marcellus Shale well pad, the impact would fall outside the radius that shale drillers must survey before they break ground and beyond the so-called zone of presumption (2,500 feet from the wellbore). That designated area allows landowners to get replacement water from a driller suspected of causing damage to their water supply.It would also raise questions about the complicated geology in southwestern Pennsylvania.Whatever happened underground was enough to momentarily suck all the water from Mr. Gillin’s house and dewater his septic tank, leaving a sludge.Several neighbors believe it may have also impacted their water wells.Tammy Yoders said her son broke out in hives after taking a shower the day of the incident, which they only learned about the next day from a Facebook postThe DEP and EQT came to her house and left with half a dozen bottles of water to sample. EQT supplied the family with several cases of bottled water, which are now long gone, Ms. Yoders said, but they haven’t asked the company for more. Now, they buy drinking water while they wait for the test results. In this small community, rumors started flying immediately, especially since it wasn’t EQT notifying people but their neighbors.Tom Bussoletti was shopping in Waynesburg when he ran into another township supervisor who told him about the well issue, called a “frack out.”Mr. Bussoletti thought about the high-pressure propane line that runs under his property. That line was why he opposed EQT’s Lumber well pad in the first place.He was already on edge about EQT’s trucks parking on top of the line. Finding out about a problem underground was more unwelcome news. That he was hearing about it days later was aggravating. Mr. Bussoletti called around. He heard from his neighbor, Liz Pebley, that the DEP found methane in her water well and suggested it be aerated to get rid of it. “Of course, I tried to light it and it didn’t [light],” she chuckled, figuring that methane would catch on fire. She doesn’t drink well water, Ms. Pebley said, and hasn’t since she lived in West Virginia, where fracking made her more cautious. But she does cook with it. Like the other families, she’s waiting for the results that she says will go to her landlord first.Wendy Saul, whose property is north of Mr. Bussoletti’s, found out about the incident on Facebook from Tammy’s daughter Tonya Yoders, who posted that the DEP was testing water. She, too, is awaiting water results. The DEP said it is investigating several water supply complaints while EQT’s spokesman Bridget McNie said in a statement that “water sampling and well monitoring have shown no other areas of concern at this time.”

Since the ‘frack out,’ it’s oily showers, mysterious smells and thirsty pets for residents of a Southwestern PA town - Frack out in PA town leaves residents questioning water safety. A strange smell wafted across the room as well water began to flow through the hose in Bill Yoders’ garage. The smell wasn’t quite sulfur, and it didn’t smell like gas. But it sure wasn’t plain water either.“That smell was never there before,” he said, adding that the water’s yellow tint was new, too. Since June 19, Yoders said, his two dogs have refused to drink the water. He’s still using the water to shower. “It kind of leaves an oily film on you,” he said. His wife, Tammy, said their 23-year-old son, Loran, broke out in hives after he took a shower at home on that June day. ”He was pure blood red, hives from head to toe,” she said.For a month, the Yoders family and other households in the Greene County hamlet of New Freeport have been living with deep concerns about their water supply. On June 19, some residents became aware, through word of mouth or a township supervisor’s Facebook post, that Pittsburgh-based EQT Corporation had reported a “frack out” at a nearby well drilling site. A frack out — sometimes spelled “frac out” — occurs when fluid pumped into a well to fracture shale formations and release gas instead enters an abandoned well. EQT, in a statement provided to PublicSource, indicated that “water was brought to the surface near an abandoned well” and that it had stopped drilling operations at its well a mile away “out of an abundance of caution.”Residents, meanwhile, are yearning for clarity on the quality of their water. Both the state Department of Environmental Protection [DEP] and Moody and Associates, a subcontractor for EQT, sent representatives to gather water samples for testing. Most residents said they have not yet received test results as of early this week. Independently, Duquesne University microbiology Professor John Stolz went to New Freeport to test the water. Preliminary data and on-site measurements from three private wells, he told PublicSource, were enough for him to conclude: “This water is not potable.” “Folks have to be provided alternative sources of drinking water,” Stolz said. The Yoders said EQT dropped off three cases and five jugs of water to the house after Bill called the corporation. That water is long gone now, they said. “A couple cases of water don’t mean anything,” he said.

CEASRA hosting landfill update -The Citizens’ Environmental Association of the Slippery Rock Area Inc. is hosting a program to share updates about the landfill being proposed by Tri-County Industries Inc.“Our Radioactive Landfill” will be held at 7 p.m. July 29 at the Grove City borough building, 123 W. Main St., Grove City, according to a news release from the organization, which is also known as CEASRA.There will be guest speakers from other parts of Pennsylvania who have experienced the effects of radioactive waste in their communities.CEASRA and community members have voiced concerns for a number of years about TCI’s plans to reopen a landfill on property the company owns in Liberty and Pine townships. As TCI continues to make its way through the rest of the permitting process, CEASRA wants to make residents aware of the potential dangers they believe the landfill presents, like radioactive fracking waste.The presentation will include information from DEP about how Vogel Holding Inc., which owns the TCI property, has dumped radioactive leachate from its Seneca landfill into the Connoquenessing Creek, CEASRA members said.TCI’s permit application for the new landfill notes that the leachate — which is liquid from landfill waste — will be similar to leachate at the Seneca landfill, said Jane Cleary, CEASRA member.Radioactive waste has become a huge problem for Pennsylvania residents, as most landfills are permitted to accept radioactive fracking waste.Dust from the waste can be airborne and inhaled, leading to serious health conditions like bone cancer, especially in children, she said.There is no easy way to remove the radioactivity from the liquid nor the landfill, and Dr. Julie Weatherington-Rice, a soil scientist at Ohio State University, has said that a landfill with fracking waste is a “permanent reactor near your house” with the same cancer-causing radon levels 500 years from now.

Pipeline explosion cause not yet provided - Bradford Era - It has been nearly two weeks since a section of the Tennessee Gas Pipeline (TGP) exploded near Clermont, and little is known about the cause. A representative from Kinder Morgan, the parent company of TGP, stated July 15, “A thorough investigation is underway and will take some time to complete.” On Thursday, Kinder Morgan responded to questions submitted regarding what happened and the process taken in the aftermath. Concerning a reported “release of gas,” Kinder Morgan was asked what kind of gas specifically and how far the release could travel in the air? “Natural gas is the type of gas that we transport in that pipeline, and that is the product that was released,” KM responded. “Natural gas is lighter than air, and many factors determine how it dissipates making it difficult to ascertain how far it travels.” The company was also asked if there was any danger to wildlife or residents in the area from a release of natural gas. “There were no adverse impacts to the residents or wildlife reported from this event,” KM responded. After the blast, KM indicated “the pressure was lowered.” The Era asked what is the difference between the pressure of the line being lowered and the line being completely shut off. KM responded, “During an incident, we shut down and isolate the impacted pipeline segment which was a portion of Line 1 on our Tennessee Gas Pipeline 300 system. We did so during this incident by closing mainline valve 309 and mainline valve 310, which are on either side of the segment that experienced the failure. The impacted segment remains shut down. “Line 2 on our TGP system parallels Line 1, and the operating pressure of that pipeline was lowered, as a precaution, until we determined that it hadn’t sustained any collateral damage as part of the in-service failure on Line 1. This line has resumed normal operations.” KM pointed to its website for further information concerning updated notices. From there, it was found that the company had declared a “Force Majeure” on Main Line Valve 309 and MLV 310, on Line 1, as of July 13 and until further notice. This is classified, on the report, as critical. According to the Wilcox Volunteer Fire Department, a call came in at 5:23 p.m. July 12, with a report of a suspected brush fire with flames “shooting over the trees with large columns of smoke” in the area of the Instanter Boat Launch on the East Branch of the Clarion River Dam. Dispatch reported the caller had heard a “loud roar” as well. However, fire crews could not find anything in the vicinity of the boat launch and the chief canceled additional units who were en route. An hour later, at 6:35 p.m., the Clermont Volunteer Fire Department requested assistance from several departments for a large wildfire and what had been reported as a gas line explosion. As crews began arriving at the Wilcox Clermont Road location, a command post was set up approximately 2 miles down the road. The crews walked the TGP line until they were able to find where the 24-inch line had ruptured. According to reports, this rupture caused the fire that burned approximately 5 acres of surrounding land. TGP lowered the pressure on the pipeline, which helped the crews who were extinguishing flames. One of the first updates received from Kinder Morgan stated, “As of (Tuesday, July 12) evening, Tennessee Gas Pipeline confirmed that there was a natural gas release and fire on a pipeline segment of its 300 system in a rural area of McKean County, Pennsylvania. The company shut down the impacted pipeline segment and worked with local responders to isolate the area. The fire was extinguished later that evening, and there were no injuries from the event. The incident remains under investigation, and the company is working with regulatory agencies as needed.”

New England gas prices top $20 on AGT system restrictions, demand spike - Natural gas prices in New England are up sharply over past several days as strong demand on Algonquin Gas Transmission collides with a planned service outage on the pipeline, prompting the system operator to impose operational flow orders to manage system pressure and deliveries. On July 20, the cash market at Algonquin city-gates surged to nearly $23/MMBtu, more than doubling on the day. At Iroquois Zone 2 spot prices jumped to nearly $21. At both locations, prices are up from weekend settlement levels at under $7/MMBtu, Intercontinental Exchange and Platts data showed. Earlier this week, constraints on Algonquin began lifting spot gas prices at the Boston-area city-gate. Since at least July 16, capacity on Algonquin's J-system delivering into Boston has remained at zero, down from over 250 MMcf/d owing to a planned maintenance outage that could continue to limit deliveries into the metro-area. The transmission outage on the J-system is currently scheduled to conclude July 21 but is subject to change and was previously extended an additional two days earlier this week by the pipeline operator. Over the past several days, the system outage on Algonquin has coincided with a surge in demand. On July 20, Algonquin deliveries to local distribution companies or LDCs edged up to nearly 600 MMcf/d, up from levels under 300 MMcf/d earlier this week. Power plant deliveries have also climbed over the past several days to an average 950 MMcf/d July 19-20, up from about 650 MMcf/d over the weekend, Platts Analytics data shows. Rising LDC and power demand on Algonquin's pipeline has accompanied a recent spike in temperatures with Boston and Hartford, Connecticut, recording highs in the low- to mid-90s Fahrenheit on July 20. Amid rising demand downstream demand, nomination requests on Algonquin have exceeded operational capacity at some locations, resulting in the imposition of some flow restrictions in accordance with capacity priority.

Gas industry drags FERC into tussle over pipeline scheme - Pipeline companies pushed back this week against claims that they are artificially inflating the price of natural gas, urging the Federal Energy Regulatory Commission to allow them to continue a sales practice of bundling gas capacity from nonadjacent sections of pipe.The comments from the Interstate Natural Gas Association of America (INGAA) and multiple pipeline companies are the latest in an ongoing tussle between key segments of the natural gas industry. They come in response to a recent petition from gas utilities, producers, shippers and others accusing the pipeline industry of anticompetitive behavior and asking FERC to step in to address it (Energywire, June 6).To obtain natural gas, gas utilities and other shippers that consume or process the fuel sometimes participate in “open seasons” held by pipelines, in which parties submit bids for capacity on a section of pipe. In recent years, pipelines have increasingly begun to bundle multiple noncontiguous capacity offers into a single bid, forcing shippers to purchase gas that they cannot use, according to the original petition.But in their comments to FERC, pipeline companies argued that the practice enables them to offer lower rates, which ultimately get passed onto residential customers and industrial consumers of gas. They also reminded FERC that it has repeatedly affirmed the use of noncontiguous capacity offers and dismissed past complaints about them.“The Petition is a plain attempt to get yet another bite at the apple and falls far short of offering the substantial evidence needed to justify a drastic departure from a policy that the Commission has applied consistently for decades,” INGAA, a trade group for pipeline companies, wrote in a comment this week to FERC.INGAA argued that FERC has taken the position for years that maximizing the revenue and use of pipeline capacity is good for all parties in the long run. In addition, other protections are already in place to ensure pipelines do not impose monopoly prices, the group said.

From Farmland to Frac Sand - One Monday in June, excavators were tearing into a field in Wedron, Illinois where the nubs of last season’s dried corn stalks were still sticking out of the ground. Behind where the crew worked, strips of earth had been carved out like steps on a wide staircase descending to the bottom of a deep pit. On the far side, fine sand the color of snow was piled in front of soaring, solid walls of sandstone. Picture standing on a ledge looking down into the biggest rock quarry you’ve ever seen. Then, enlarge that image 100 times, whitewash it, and add turquoise blue pools of wastewater. This is silica mining. Fracking, a process used to extract natural gas and petroleum, depends on silica sand, or “frac sand” to produce the fossil fuels. A single fracking site can use millions of pounds of sand. The sand is blasted into wells to keep fissures in the rock open so that oil and gas can be released. In the Midwest, farmland is being irreversibly lost in pursuit of silica sand. Wedron Silica, which is now owned by Ohio-based Covia, has been expanding this particular mine for years and now owns at least 2,500 acres in and around the tiny village. It’s just one of several that Covia owns across LaSalle County, Illinois, 90 miles southwest of Chicago. Here, U.S. Silica, Smart Sand, and other companies are also actively mining. Together, the companies have purchased hundreds of parcels of land and now own more than 9,000 acres in LaSalle, a Civil Eats investigation has found. The majority of those acres are former or current farmland. Silica mining is also prevalent in other parts of Illinois and regions of Wisconsin and Missouri. According to the U.S. Department of Agriculture (USDA), LaSalle County’s farmland acreage dropped 5 percent from 2012 to 2017, to 573,000 acres. But many of the acres still identified as farmland are owned by mining companies and leased to farmers. Across the street from the mining activity in Wedron, for example, Covia owns 600 acres, where tiny corn plants were just starting to green up in neat rows. In 2018, the county approved the company’s application to expand into those farm fields, despite the fact that LaSalle County Soil and Water Conservation District discouraged the decision based on a site assessment score that identified the land as “highly productive.” Digging could start at any time.

US sets course for natural gas production records - US natural gas production will push past 100 billion cubic feet per day by the end of the year as producers scramble to boost output to meet growing global demand for gas, according to a leading market analyst. The US is already the world’s largest gas producer but increased production in major shale plays is helping the nation expand its lead over Russia, Rystad Energy said this week. The primary producing regions will continue to be the Marcellus and Utica shales in the US north-east, the Haynesville shale in Louisiana and the Permian basin in Texas and Louisiana.

Rystad: US natural gas output to top 100 bcfd by end-2022 -US natural gas production is expected to hit a record high of more than 100 bcfd by the end of the year, Rystad Energy analysis shows. Production growth in major US gas-producing basins, in addition to associated gas production in the Permian, will cement the country's position as the world's largest gas producer, stretching its lead over Russia. Within shale gas plays, the Marcellus, Utica, and Haynesville are set to contribute the most. Rystad Energy expects production from the Haynesville alone to grow by 2.6 bcfd this year compared with 2021, pushing annual output to more than 14 bcfd. Production from the basin is forecast to jump next year as well, reaching 17.2 bcfd by end 2023. The company noted, however, that growth in Appalachia basin remains entirely dependent on progress of the proposed Mountain Valley Pipeline, which faces significant legal hurdles. The recent surge in global natural gas prices is pushing US exploration and production companies to increase investment in an effort to take advantage of competitive breakeven costs. A well-documented supply shortage in Europe is pushing up prices on the continent amid efforts to ease reliance on Russian gas. Given the wide US and European price differences, shipping US gas across the Atlantic, even considering the pricey liquefaction process, is economically advantageous. The US-Europe price spread has widened steadily since summer 2020. Russia’s invasion of Ukraine and the ensuing global energy crisis accelerated the disparity. As of July 15, Henry Hub prices were $7/MMbtu, while the TTF stood at $47/MMbtu. Although LNG production capacity constraints remain, with new LNG capacity expected to be added only after 2024, the US’s role in global gas markets should grow for some time to come, said Kristine Vassbotn, Rystad Energy senior analyst. Upstream investments in the Haynesville of $7.4 billion are set to exceed the Marcellus this year for the first time since 2009. Haynesville investments will grow 47% from 2021 to 2022, according to Rystad, followed by the Utica and Marcellus at 26% and 21%, respectively. The increase in investments in 2022 is a combination of increased activity in response to prices, particularly in the Haynesville, and increased well costs due to inflation. The Marcellus has the largest undrilled leased acreage of the three basins at 6.7 million acres. As policymakers seek ways to boost domestic output, the Marcellus has plenty of remaining commercial acreage and inventory to unlock, should takeaway constraints eventually ease in the Northeast. The Haynesville has the least undrilled acreage at 1.8 million acres. In terms of remaining gas reserves, the Marcellus has the most, with close to 380 tcf. The Haynesville follows, with 202 tcf.

LNG exports shoot up in Louisiana, US in 2022 amid booming demand --Led by a trio of Louisiana facilities, the United States’ liquefied natural gas export terminals are exceeding their 2021 pace amid growing demand for LNG in natural gas-starved Europe. Collectively, the seven operating LNG export terminals in the U.S. have pumped out more than 1.7 trillion cubic feet of LNG through May, according to the most recent data available from the Department of Energy. That’s nearly 260 billion more than the nearly 1.5 trillion cubic feet that U.S. terminals moved at the same point last year. Leading the way was Sabine Pass LNG in Cameron Parish, near the Texas border. Sabine Pass LNG has exported nearly 626.9 billion cubic feet through May, a 100 billion-cubic-foot spike compared with its total through the same month in 2021. The facility has accounted for more than a third of U.S. production so far. Sabine Pass LNG’s output nearly doubled the second-place facility, Corpus Christi Liquefaction in Corpus Christi, Texas, which exported 315 billion cubic feet through May. Both facilities are owned by Houston-based Cheniere Energy. Cameron LNG in Hackberry has produced 274 billion cubic feet through May, good enough for fourth in the U.S. rankings. That’s a jump of nearly 29 billion cubic feet from the same point a year ago. All six of the terminals that were in operation last year posted year-over-year gains in May. Venture Global LNG’s Calcasieu Pass facility, near the mouth of the Calcasieu Ship Channel in Cameron Parish, came online in January and has shipped more than 61 billion cubic feet so far this year. In total, U.S. LNG terminals sent more than 351 billion cubic feet of exports in May alone, an 11.5% increase from May 2021 and a 6.4% increase from April of this year.

We Gotta Get Out of This Place - Court Decision Helps Supply Access to LNG Export Facilities - Europe is trying to wean itself off Russian natural gas, and few things would help it more than an expansion of U.S. LNG export capacity. But LNG projects don't just need long-term commitments for their output, they also need pipelines to transport natural gas from the Marcellus/Utica and other distant production areas to their coastal liquefaction plants. And, in case you hadn't noticed, new interstate gas pipelines face a lot of hurdles during the regulatory review process these days — getting a pipeline approved is tougher than snagging a Saturday morning tee time. Which brings us to, of all things, an important court ruling. In today's RBN blog, we discuss the implications of the DC Circuit's decision in City of Oberlin v. FERC. On July 8, the U.S. Court of Appeals for the District of Columbia Circuit (a.k.a. the DC Circuit) updated a decision that could have a significant impact on the supply of feedgas to LNG export facilities. In the case of City of Oberlin, Ohio v. FERC, the DC Circuit reversed an earlier finding that the Federal Energy Regulatory Commission (FERC) had not explained why export volumes on a proposed interstate pipeline project can be used to help justify approval of the new pipe projects. The case involved the city of Oberlin's challenge to FERC's approval of the NEXUS pipeline, carrying natural gas from the Utica Shale in eastern Ohio to the gas hub in Dawn, ON (among other destinations). The project sponsors had included the gas flows to Dawn as support for approval of the pipeline, to help meet the requirements of FERC’s “certificate policy” that a public benefit had to be shown for pipeline construction to be authorized. In what the DC Circuit now refers to as its "Oberlin I" decision, the court, in 2019, found that FERC needed to explain why volumes on NEXUS going to Canada were a benefit to the U.S. public. That decision had been used by LNG opponents, such as Sierra Club, to claim that the same issue affects feedgas pipelines built to serve LNG export terminals. They argued that such pipelines shouldn’t receive certificates to allow construction or the eminent domain rights that automatically go with those certificates if they didn’t show a benefit to the U.S. public. The DC Circuit's decision last month (“Oberlin II”) reversed Oberlin I, finding that FERC has now explained itself well enough and that, yes, natural gas exports can provide public benefits in the U.S. So, does this reversal clear the way for LNG feedgas pipelines to be built without running into legal roadblocks? Well, it pretty much knocks down one potential roadblock, but that’s a start.Two parts of the Natural Gas Act of 1938 (NGA) are involved: Section 3 and Section 7. Section 3 deals with the import and export of natural gas. It’s jointly administered by the Department of Energy (DOE) and FERC. DOE decides whether an export is in the public interest and FERC decides whether to authorize an LNG export terminal. Section 7, in turn, deals with the construction of interstate natural gas pipelines. It's exclusively administered by FERC. One of the most important differences between the two sections is that Section 7 includes a grant of eminent domain (added to the NGA in 1947), so that if a pipeline developer cannot get a landowner to negotiate for right of way, it can petition a court for condemnation. This helps a lot in keeping pipelines straighter and cheaper than they otherwise would be. Section 3, however, does not include an eminent domain provision. Also, a Section 7 pipeline can transport interstate gas for any shipper, not just the LNG terminal. A Section 3 pipeline can’t — it’s just treated as a piece of the terminal. So, for a pipeline needed to feed gas to an LNG export terminal, it’s a big deal whether the pipeline is authorized under Section 3 or Section 7.

‘Super-Hot’ Weather Pattern Spurs on Natural Gas Futures Rally - Natural gas futures flew higher on Monday, building on the prior week’s gains, as soaring temperatures baked much of the Lower 48 and forecasts called for heat waves to fester through July and into next month. The August Nymex contract jumped 46.3 cents day/day and settled at $7.479. September gained 45.6 cents to $7.382.The prompt month advanced 16% last week, including a 41.6-cent gain on Friday.NGI’s Spot Gas National Avg. mounted further momentum of its own, rising $1.145 to $7.745. Hubs throughout the country posted strong gains.Cash prices cruised higher last week, too. NGI’s Weekly Spot Gas National Avg. for the July 11-15 period spiked 88.5 cents to $6.730.“The pattern remains in super-hot mode,” Bespoke Weather Services said Monday, adding its forecast calls for a few record gas-weighted degree days (GWDD) over the next two weeks. That would put the market “on pace for a July that ranks among the top three hottest months on record in terms of total GWDDs. This includes a continuation of blistering heat in places like Texas, where the hottest weather comes the next three days, bringing up the chance for at least one day of 110 in Dallas.“Looking ahead,” the firm added, “we have little reason to think we will not continue to see above normal heat on into at least the first part of the month of August, keeping weather easily on the supportive side.” Bears had previously seized upon the Freeport LNG outage that followed an early June fire. It cut U.S. export capacity by about 2.0 Bcf/d through at least early fall. That gas is now available for domestic consumption.However, “all of this extra heat is really chewing away at the 200-plus Bcf given to the market’s end-of-season storage projections by the Freeport LNG debacle,” Bespoke said. “In fact, just with the forecast we see through the first few days of August, we estimate that weather has negated as much as 85 Bcf. Should heat continue this strongly into the rest of August, prices will continue to move higher, as injections will remain rather low.”The U.S. Energy Information Administration (EIA) most recently printed an injection of 58 Bcf into natural gas storage for the week ended July 8. It lifted working gas in storage to 2,369 Bcf, yet stocks were 319 Bcf below the five-year average. Dry gas production gained 1.0 Bcf/d over the weekend to around 97 Bcf/d, EBW Analytics Group senior analyst Eli Rubin noted. That lifted output to near 2022 highs. “If supply continues to increase, it could adjust the long-term storage outlook and severely slash shortage risk premiums for later this year,” Rubin said. For now, however, “searing heat” is driving markets higher.

U.S. natgas futures slide 3% as output rises, technical resistance (Reuters) - U.S. natural gas futures fell about 3% on Tuesday after failing to break through a key point of technical resistance as overall output continues to rise to record levels and a small, brief decline in gas flowing to liquefied natural gas (LNG) export plants. That price decline came despite a preliminary one-day drop in output on Tuesday, a preliminary increase in LNG feed gas on Tuesday and forecasts for hotter weather and higher air conditioning demand next week than previously expected. Extreme heat has already boosted power demand to record highs in several parts of the country, including Texas and other U.S. Central states, as homes and businesses crank up their air conditioners to escape the weather. Also pressuring gas prices was the ongoing outage at the Freeport liquefied natural gas (LNG) export plant in Texas, which leaves more fuel in the United States for utilities to refill low storage. Freeport, the second-biggest U.S. LNG export plant, was consuming about 2 billion cubic feet per day (bcfd) of gas before it shut on June 8. Freeport LNG has said the facility could return around Oct. 22. Some analysts, however, expect the outage to last longer. Front-month gas futures fell 21.5 cents, or 2.9%, to settle at $7.264 per million British thermal units (mmBtu). On Monday, the contract closed at its highest since June 13. On the technical side, the front-month failed to break above its 50-day moving average for a second day in a row, making that a key level of resistance. So far this year, the front-month is up about 96% as much higher prices in Europe and Asia keep demand for U.S. LNG exports strong, especially since Russia's invasion of Ukraine stoked fears Moscow would cut gas supplies to Europe. Gas was trading around $49 per mmBtu in Europe and $37 in Asia. After the shutdown of Nord Stream 1 for maintenance on July 11, Russian gas exports have held around 1.4 bcfd on the three main lines into Germany: Nord Stream 1 (Russia-Germany), Yamal (Russia-Belarus-Poland-Germany) and the Russia-Ukraine-Slovakia-Czech Republic-Germany route. That is down from an average of 3.7 bcfd in the month before Nord Stream shut and an average of 9.4 bcfd in July 2021. The average amount of gas flowing to U.S. LNG export plants slid to 11.1 bcfd so far in July from 11.2 bcfd in June due to a brief upset at Venture Global LNG's Calcasieu Pass plant in Louisiana on Monday. That was down from 12.5 bcfd in May and a monthly record of 12.9 bcfd in March due to the Freeport outage. Feed gas to Calcasieu was expected to return to 1.5 bcfd on Tuesday after sliding to 0.8 bcfd on Monday. That compares with an average of 1.5 bcfd over the past week.

U.S. natgas futures jump 10% on hotter forecasts, output decline (Reuters) - U.S. natural gas futures jumped about 10% to a five-week high on Wednesday on forecasts for hotter weather over the next two weeks to boost air-conditioner use and gas-fired electrical demand following a recent decline in output. A brutal heat wave has already boosted power demand for air conditioning to record highs in several parts of the country, including Texas. "Power demand reached an all time high ... yesterday," analysts at Gelber & Associates said in a report, noting, "Next week is expected to be the hottest of the season." Power companies were burning lots of gas to produce all that power in part because coal prices were near record highs, making it uneconomic for many generators to switch to coal-fired plants. Gas prices rose despite a drop in feed gas to liquefied natural gas (LNG) export plants due to upsets at a couple facilities in Louisiana and the ongoing outage at Freeport in Texas, which leaves more fuel in the United States. Freeport, the second-biggest U.S. LNG export plant, was consuming about 2 billion cubic feet per day (bcfd) of gas before it shut on June 8. Front-month gas futures rose 74.3 cents, or 10.2%, to settle at $8.007 per million British thermal units (mmBtu), their highest close since June 13. In what has already been an extremely volatile year of trade, Wednesday's gain was only the biggest one-day percentage gain since early July. There have already been 11 days where the front-month has settled up or down over 10% in 2022. So far this year, the front-month was up about 115% as much higher prices in Europe and Asia keep demand for U.S. LNG exports strong, especially since Russia's invasion of Ukraine. Gas was trading around $48 per mmBtu in Europe and $38 in Asia. Data provider Refinitiv said average gas output in the U.S. Lower 48 states rose to 96.1 bcfd so far in July from 95.3 bcfd in June. That compares with a monthly record high of 96.1 bcfd in December 2021. On a daily basis, however, output was on track to drop 2.7 bcfd from a six-month high of 97.3 bcfd on Monday to a preliminary five-week low of 94.6 bcfd on Wednesday. Preliminary data is often revised later in the day. Refinitiv projected average U.S. gas demand including exports would slide from 100.9 bcfd this week to 100.1 bcfd next week as extreme heat starts to ease in some parts of the country. Those forecasts were similar to Refinitiv's outlook on Tuesday. With hot weather blanketing much of the country, next-day power in New England soared to $199 per megawatt hour for Wednesday, its highest since late January.

US working natural gas in storage increases by 32 Bcf on week: EIA | S&P Global Commodity Insights - US natural gas working stocks rose by 32 Bcf during the week ended July 15, undershooting market expectations and providing bullish fodder for US gas futures markets. Storage inventories rose to 2.401 Tcf for the week ended July 15, the US Energy Information Administration reported on July 21. The build was well below an S&P Global Commodity Insights survey of analysts calling for a 44 Bcf net injection, although it was within the wider range of 25-58 Bcf. The weekly injection also was less than the 50 Bcf build reported during the corresponding week in 2021, and below the five-year average draw of 41 Bcf, according to EIA data. As a result, the deficit to both the five-year average and year-ago week widened. Stocks in the most recent reporting week were 270 Bcf, or 10.1%, below the year-ago level of 2.671 Tcf, and 328 Bcf, or 12%, below the five-year average of 2.729 Tcf. The smaller-than-expected build initially galvanized US gas futures July 21, with the session's highs giving way to a more tepid response by the close of trading. The NYMEX Henry Hub August contract surged 35 cents to $8.10/MMBtu in the 10 minutes of trading following the weekly storage report, erasing the pre-storage report pricing weakness observed earlier in the session. The contract had been trading around $7.75/MMBtu in the 30 minutes before the July 21 storage report launched, down around 25 cents from its prior-day rally to $8.007/MMBtu. Prior to July 20, the NYMEX prompt-month contract last settled above $8/MMBtu in mid-June. At close, the August contract settled at $7.932/MMBtu, down 7.50 cents from its prior day's settlement. Ongoing heat wave conditions have spiked power sector demand for gas so far in July, absorbing volumes that might otherwise have flowed into storage. Total US power burn demand has exceeded the five-year average every day since June 18, Platts Analytics data showed. Between July 1-20, 14 days have seen power burn demand outpace the five-year maximum as well. Gas-fired power demand has been especially strong in Texas and the Southeast, which are largely captured in the EIA's South-Central region. The South-Central region saw a 16 Bcf withdrawal from storage for the week ended July 15, the region's first net pull so far this injection season. Withdrawals from salt caverns drove the net decrease in storage, with non-salt storage recording no change from the previous week.

Natural Gas Futures Fly Back Above $8 Amid Relentless Heat, Storage Concerns - Natural gas futures flexed some pricing muscle on Friday on the heels of a solidly bullish storage report and a shift hotter in an already sizzling late-summer weather outlook. The August Nymex gas futures contract gained 36.7 cents day/day and settled at $8.299/MMBtu to close the week. September advanced 38.0 cents to $8.195. NGI’s Spot Gas National Avg. followed suit, rising 1.5 cents to $8.385. Markets on Friday mulled the implications of a seasonally weak inventory build and the prospect of more to come as exceptional cooling demand has come to define the summer of 2022. The U.S. Energy Information Administration on Thursday posted a 32 Bcf injection of gas into underground storage for the week ended July 15. The print fell short of expectations and historic norms. Polls ahead of the EIA report pointed to an increase in the mid- to high-40s Bcf. The actual build compared to the 50 Bcf increase in the comparable week last year and a five-year average injection of 41 Bcf. The injection raised working gas in storage to 2,401 Bcf, though stocks were 328 Bcf below the five-year average. On a weather-adjusted basis, Tudor, Pickering, Holt & Co. (TPH) analysts said the latest EIA report implied the market was about 3 Bcf/d undersupplied. Summer heat remains a “primary driver of price action” for the natural gas market, having pushed power generation demand to an all-time high at 47.5 Bcf/d during the July 17-22 week, roughly 6 Bcf/d above seasonal norms, according to the TPH analysts. Analysts at The Schork Report said the government assessment came in 24% below the most conservative forecast in major polls. About halfway through the storage refill season, they said, the market has covered 45% of last winter’s gas deliveries. The market had anticipated that the Freeport LNG outage – caused by a June fire – would ease supply worries even in the face of prolonged heat. The outage cut export capacity by 2.0 Bcf for the summer – and likely longer – and that gas is now available for domestic use. But utilities are eating through the added supply and still struggling to narrow the storage deficit to the five-year average. Meanwhile, output climbed to around 97 Bcf early in the past week – near a summer high. But producers were not able to sustain that level as maintenance projects interrupted momentum and curbed output to around 95-96 Bcf late in the week. Bespoke Weather Services said widespread high temperatures in the 90s and 100s put this month on track to be one of the three hottest Julys on record. Now, the latest outlooks shifted hotter and put next month on a path to become one of the five hottest Augusts in the firm’s data set. “If this heat does indeed continue throughout August, it is likely that prices still move higher from here, and end-of-season storage projection could fall as low as 3.25 Tcf, with hot weather having eaten away most of what Freeport gave the market,” Bespoke said. “Such a scenario would mean prices could still manage to touch $10.00 yet.” ”

U.S. regulators to inspect shuttered Texas LNG plant in September (Reuters) - The U.S. Federal Energy Regulatory Commission (FERC) will inspect Freeport LNG's shuttered liquefied natural gas (LNG) export plant in Texas in September, the agency said on Tuesday. The plant shut on June 8 because of a fire and was expected to remain out of service until October, Freeport LNG said in an email on Tuesday. Both FERC and the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA) said they would not allow the facility to return to service until they approve the restart. The September inspection is a standard annual site inspection. The shutdown of Freeport caused natural gas prices in Europe to jump about 40% in the week after the plant shut because it reduced the volume of available exports from the United States at a time when the world is short on natural gas supply. Europe has been buying U.S. LNG heavily due to reduced flows from Russia following its invasion of Ukraine on Feb. 24 and subsequent sanctions placed on Russia by the United States and its allies. The Freeport shutdown also caused U.S. gas prices to drop because it left more of the fuel in the United States, allowing utilities to quickly rebuild low gas stockpiles. U.S. futures dropped about 44% due in part to the ongoing outage of Freeport from a near 14-year high of $9.66 per million British thermal units (mmBtu) on June 8, the day Freeport shut, to a three-month low of $5.33 on July 5. In addition to the notice about the upcoming Sept. 13-15 inspection, FERC asked Freeport to provide information about the plant, including "any abnormal operating conditions at the facility" and "any changes in the facility design, process equipment, process piping ... that have been made" since the last FERC inspection on June 23-24, 2021.

U.S. Coast Guard Contains Over 1 Mn Gallons From Longest Oil Spill -The U.S. Coast Guard and partner agencies have successfully contained and collected over one million gallons of oil discharged from subsurface oil wells connected to a toppled oil platform in Mississippi Canyon Block 20, some 11 miles offshore Louisiana. The platform collapsed in 2004 due to Hurricane Ivan, and oil continues to leak from the damaged wells making this the longest-running oil spill in U.S. history. Since April 2019, oil has been captured, contained, and removed from the site while a permanent plan to decommission the oil wells effectively and safely at the MC-20 site is being developed. According to the U.S. Coast Guard, 1,016,929 gallons of oil have been collected from the site as of July 12, 2022. A subsea containment system designed, fabricated, installed, and operated by Couvillion Group continues to collect an average of 900 gallons of oil per day with the Coast Guard overseeing continuous oil collection and necessary system maintenance. “The near elimination of the surface sheen and collection and removal of more than one million gallons of oil from the site over the previous three years is a major milestone in the Coast Guard’s efforts to contain the MC-20 oil spill that has affected the waters off the Gulf Coast for years,” said Kelly Denning, the Coast Guard’s Federal On-Scene Coordinator for the incident. “Though the containment system is considered a great success, the federal government is exploring all available response options, including properly decommissioning the impacted wells on site,” Denning added. To remind, a settlement between the United States and Taylor Energy was reached in late December last year in which Taylor Energy agreed to transfer all remaining funds in the Taylor Energy Decommissioning Trust to the United States. This meant that Taylor Energy would pay over $43 million for the settlement and transfer the $432 million decommissioning trust fund in its entirety. The funds will be used to properly decommission the oil wells which were originally connected to the downed platform at the MC-20 site. The terms of the settlement are outlined in the Consent Decree entered by the District Court for the Eastern District of Louisiana on March 17, 2022. The response to the active oil spill continues to be led by the Coast Guard Federal On-Scene Coordinator and is supported by its federal partners, including the Bureau of Safety and Environmental Enforcement and the National Oceanic and Atmospheric Administration. Currently, the Coast Guard is gathering key subsurface data which is intended to support future federal efforts to decommission the MC-20 wells which the Bureau of Safety and Environmental Enforcement and U.S. Coast Guard believe is the necessary step to ultimately bring this incident to a close.

Gulf of Mexico: 1 million gallons of oil collected from 18-year-old spill over past three years - The U.S. Coast Guard, in collaboration with partner agencies, has contained and collected over one million gallons of oil discharged from subsurface oil wells connected to a toppled oil platform in Mississippi Canyon Block 20 (MC-20), located 11 miles south of the Louisiana shoreline. The MC20 platform, operated by Taylor Energy, collapsed in an underwater mudslide caused by Hurricane Ivan in 2004, spilling oil into the Gulf of Mexico. The oil continues to leak from the damaged wells and this is described as the longest-running oil spill in the U.S. history. In an update last week, the U.S. Coast Guard informed that 1,016,929 gallons of oil have been collected – as of 12 July 2022 – from the MC-20 site with oil being captured, contained, and removed from the site since April 2019, while a permanent plan to effectively and safely decommission the oil wells at the MC-20 site is being developed. Capt. Kelly Denning, the Coast Guard’s Federal On-Scene Coordinator for the incident, remarked: “The near elimination of the surface sheen and collection and removal of more than one million gallons of oil from the site over the previous three years is a major milestone in the Coast Guard’s efforts to contain the MC-20 oil spill that has affected the waters off the Gulf Coast for years. “Though the containment system is considered a great success, the federal government is exploring all available response options, including to properly decommission the impacted wells on site.” Furthermore, a subsea containment system – which was designed, fabricated, installed, and operated by Couvillion Group, specifically in response to this incident – continues to collect an average of 900 gallons of oil per day with the Coast Guard overseeing continuous oil collection and necessary system maintenance. Back in December 2021, a settlement between the United States and Taylor Energy was reached in which Taylor Energy agreed to transfer all remaining funds in the Taylor Energy Decommissioning Trust to the United States.

US Shale Plays Expected to Boost Oil, Gas Output in August – Energy companies drilling in shale basins across the United States are projected to increase production of oil and natural gas in August, according to a new report from the U.S. Energy Information Administration. According to EIA’s Drilling Productivity Report, the seven identified shale regions across the country are projected to collectively increase oil production by 136,000 barrels a day and boost natural gas output by 748 million cubic feet per day next month compared to July. Energy producers in the Appalachian region — which includes the Utica shale in eastern Ohio and the Marcellus shale in Pennsylvania and West Virginia — expect to increase gas production by 207 million cubic feet per day and oil by 3,000 barrels daily from the previous month. The Appalachian region easily produces the largest volume of natural gas in the country. In August, daily production is estimated to rise to 35.3 billion cubic feet per day from 35.1 billion cubic feet in July. Oil output likely to grow slightly from 130,000 barrels per day this month to 133,000 barrels in August, according to the report. The Permian Basin, located mostly in western Texas, is the second largest gas producer with a projected output of 20.5 billion cubic feet of natural gas per day by next month. The region is the largest oil producer in volume, anticipating increasing production by 78,000 barrels to 5.4 million barrels per day. Six out of the seven shale plays anticipate more oil production in August, according to EIA’s report. The Haynesville shale in eastern Texas and western Louisiana expects no change in production. Natural gas production is estimated to increase all of the regions with the exception of the Anandarko Basin in Oklahoma, which expects to see a decrease of 12 million cubic feet per day next month, EIA reported.

US shale oil production is expected to rise by 136 thousand barrels per day -- The US Energy Information Administration expects shale oil production in the United States to increase by 136 thousand barrels per day during August of this year (2022).According to the drilling productivity report – issued by the administration today, Monday, July 18, it is expected that shale oil supplies from the seven major basins in America will rise to 9.068 million barrels per day next month, compared to the expected level of 8.932 million barrels per day, during the current July.US natural gas production from major shale basins is likely to increase by 748 million cubic feet per day in August, according to the report, seen by the Energy Research Unit.The Energy Information Administration estimates that production of shale oil in the Permian Basin will rise by about 78,000 barrels per day in August 2022, to reach 5.445 million barrels per day, which may be a new record.The Eagle Ford Basin production is expected to rise by about 25,000 barrels per day, bringing the total to 1.205 million barrels per day, according to the report, the details of which were followed by the Energy Research Unit.Shale oil production in the Bakken Basin is expected to rise to 1.192 million barrels per day, an increase of 19,000 barrels per day from the current July level.The Energy Information Administration expects supplies from the Niobrara, Anadarko and Appalachia basins to rise by 6, 5 and 3 thousand barrels per day, respectively.Natural gas production from shale basins is expected to rise to 93.019 billion cubic feet per day in August, compared to an expected level for June of 92.271 billion cubic feet per day.The Energy Information Administration expects Heinsville Basin production to rise by 217 million cubic feet per day, to a total of 15.478 billion cubic feet per day, according to the report seen by the Energy Research Unit.

Oil output in biggest US shale oil basin predicted to rise in August to highest on record --Oil output in the Permian in Texas and New Mexico, the biggest US shale oil basin, is due to rise 78,000 barrels per day (bpd) to a record 5.445 million bpd in August, the US Energy Information Administration (EIA) said in its productivity report on Monday. Total output in the major US shale oil basins will rise 136,000 bpd to 9.068 million bpd in August, the highest since March 2020, EIA projected. In the Bakken in North Dakota and Montana, EIA projected oil output will rise 19,000 bpd to 1.192 million bpd in August, the most since December 2020. In the Eagle Ford in South Texas, output will rise 25,000 bpd to 1.205 million bpd in August, the highest since April 2020. Total natural gas output in the big shale basins will increase 0.7 billion cubic feet per day (bcfd) to a record 93.0 bcfd in August, EIA forecast. In the biggest shale gas basin, EIA said, output in Appalachia in Pennsylvania, Ohio and West Virginia will rise to 35.3 bcfd in August, the highest since hitting a record 36.0 bcfd in December 2021. Gas output in the Permian and the Haynesville in Texas, Louisiana and Arkansas will also rise to record highs of 20.5 bcfd and 15.5 bcfd in August, respectively. But productivity in the biggest oil and gas basins has declined every month since setting records of new oil well production per rig of 1,545 bpd in December 2020 in the Permian, and new gas well production per rig of 33.3 million cubic feet per day (mmcfd) in March 2021 in Appalachia. In August, EIA expects new oil well production per rig will drop to 1,107 bpd in the Permian, the lowest since August 2020, and new gas well production per rig will drop to 27.6 mmcfd in Appalachia, the lowest since August 2020. EIA said producers drilled 938 wells, the most since March 2020, and completed 964, the most since October 2021, in the biggest shale basins in June. That left total drilled but uncompleted (DUC) wells down 26 to 4,245, the lowest since at least December 2013, according to EIA data going back that far. The number of DUCs available has fallen for 24 consecutive months.

Biden Pursues More Foreign Oil Despite Invite from U.S. Producers - Prior to heading to Saudi Arabia, the U.S. energy industry invited President Joe Biden to visit American energy sites.The Texas Oil and Gas Association, Texas Independent Producers & Royalty Owners Association, and over 25 U.S. energy associations invited Biden and his cabinet members to visit U.S. energy facilities throughout the U.S.The Texas groups represent high-skilled workers in a state that if it were its own country would be the world’s third largest producer of natural gas and fourth largest producer of oil. Texas producers are leading the U.S. in crude production in the Permian Basin and Eagle Ford Shale, recognizing that “energy is the cornerstone of security and prosperity,” Todd Staples, president of TXOGA, said. Nationwide, the groups represent 11 million workers in an industry that propelled the U.S. to lead the world in crude production in 2019. From cancelling federal land and offshore leasing permits, to increased regulation and proposed taxes, to depleting the Strategic Oil Reserves, to turning to foreign oil production, Biden has done everything to hamper domestic oil production, those in the industry contend. While in Saudi Arabia, Biden is continuing his efforts to encourage members of the Organization of the Petroleum Exporting Countries (OPEC) to expand output.Still, TIPRO President Ed Longanecker told The Center Square, “There are continued efforts to work with the Biden Administration to prioritize and support domestic oil and natural gas production to address global supply shortages, inflation and an escalating energy crisis in Europe.”The groups wrote Biden a letter, urging him to “consider taking another look at made-in-America energy” before he left for the Middle East. They said they’d “be honored to show you how our industry is involved in every step of the energy process, from fuel pumps to critical product delivery infrastructure to production zones across our vast nation.”But they didn’t hear back.Instead, Biden wrote an op-ed published by The Washington Post justifying his trip. “As president, it is my job to keep our country strong and secure,” he wrote. “We have to counter Russia’s aggression, put ourselves in the best possible position to outcompete China, and work for greater stability in a consequential region of the world.“To do these things, we have to engage directly with countries that can impact those outcomes. Saudi Arabia is one

Halliburton Warns Frack Growth "Almost Impossible" This Year - American shale drillers have shown how quickly they can boost oil production over the years. But after several years of divestment and decarbonization, the days of fracking roaring back to life are over. Halliburton Co.'s CEO Jeff Miller confirmed this to analysts during a conference call Tuesday. He said the oilfield equipment market is so tight that oil explorers are already discussing 2023 projects. Miller said oil companies don't have enough fracking equipment for newly leased wells this year. He said diesel-powered and electric equipment are in short supply, "making it almost impossible to add incremental capacity this year." This development is another setback for the Biden administration's efforts to increase US oil production to ease the worst inflation in forty years ahead of the midterm elections in November. A similar message was conveyed by Exxon Mobil, whose CEO said that global oil markets might remain tight for another three to five years primarily because of a lack of investment since the pandemic began.Chief executive Darren Woods said it'll take time for oil firms to "catch up" on the investments needed to ensure enough supply.Back to the shale patch, where even if exploration companies were to obtain fracking equipment for drilling new or existing wells, the frack sand used to blast through shale rocks is in short supply across Texas.Russell Hardy, the CEO of the world's largest independent oil merchant, Vitol, also believes oil prices will remain high because the market can't see where additional supply is coming from to balance demand. Meanwhile, Brent oil prices rose to $106 on Tuesday after President Biden returned from Saudi Arabia without an agreement on increasing output from OPEC+. "The message is that it is OPEC+ that makes the oil supply decision, and the cartel isn't remotely interested in what Biden is trying to achieve," said Naeem Aslam, the chief market analyst at Avatrade.Neither US shale nor OPEC+ appears to be increasing output in the immediate future for their own respective reasons, indicating tight crude supplies will keep energy prices elevated and inflation high. All the Biden administration can hope for now is a recession to curb consumer demand to rebalance markets.

Oil And Natural Gas Industry Taxes Power Texas Record Surplus -Texas is expecting a record surplus of nearly $27 billion for the 2022-23 biennium, Texas Comptroller Glenn Hegar says, mostly due to the record amount of taxes the Texas oil and natural gas industry contributed. Texas Comptroller Glenn Hegar revised the Certification Revenue Estimate (CRE) upward, increasing his November estimate of General Revenue-related (GR-R) funds available for certification by $13.75 billion. In a letter to state leadership, Hegar said the state will have $149.07 billion in GR-R funds available for general-purpose spending for the 2022-23 biennium, resulting in a projected fiscal 2023 ending balance of $26.95 billion, an increase of $14.95 billion from the November projected balance. The ending balance does not account for any 2022-23 supplemental appropriations the Legislature may make. “This revised estimate includes a net decrease in projected GR-R spending of $1.5 billion yet is mostly driven by tax revenues that rebounded strongly in recent months after being suppressed by the pandemic in the previous biennium,” Hegar said. “In fact, many tax revenue categories reached their highest collections on record, and this fiscal year has experienced the largest one-year increase in total tax collection, as compared with the prior fiscal year, in Texas history. This is especially true of state sales taxes, where monthly collections for each of the last 15 months exceeded $3 billion and averaged $3.5 billion. “Severance taxes performed extremely well due to elevated oil and gas prices caused by energy market volatility. This is due in part to a strong global economic recovery coupled with the war in Ukraine and a period of limited investment in fossil fuel production and refining capacity. It is important to realize that inflation is a significant contributing factor to why we have seen record tax collections in sales tax and other revenues over the last year.

Report: Texas oil and gas should temper job-creation claims - Texas oil and gas employment may not rebound to pre-COVID levels. Ever. That’s according to a new report from the Institute for Energy Economics and Financial Analysis. It also says the industry is not the job creator that many believe it is. At ground zero of Texas oil and gas employment — the Permian Basin — industry executives are telling a different story.Between September 2019 and September 2020, oil and gas extraction and affiliated industries in Texas shed about 20% of their workforce. And while there’s been a hiring uptick over the past few months, the industry isn’t back to pre-COVID numbers.“We’re only about halfway there as far as the recovery goes,” said Trey Cowan, who wrote the report for the IEEFA. “And it looks like we’re starting to plateau.” Cowan said there’s a number of reasons for the slow pace of hiring. One is that operators say they can’t find people who are healthy enough to work on a rig and can pass a drug test. Energy Workforce & Technology Council, an industry trade group, blames anti-fossil fuel rhetoric. CEO Leslie Beyer said in an email that “continued vilification of the industry has a negative impact on recruiting, especially with younger workers.”But it could be efficiency that’s leading to fewer jobs in places like the Permian Basin.“They’re getting more oil out of the ground, with fewer people having to work for it,”

Biden Crackdown On Permian Pollution To Trim Crude Output - The Biden administration’s plan to crack down on smog in the oil-rich Permian Basin threatens to curb crude production while gasoline prices are near record highs and energy scarcity grips the globe, the industry warned Thursday. Oil’s lobbying heavyweights are appealing directly to top White House officials to slam the brakes on the plan, arguing that any move to redesignate drilling hotbeds in Texas and New Mexico as violating ozone air quality standards poses such high economic risks it should be subject to greater analysis and public scrutiny. The Environmental Protection Agency’s proposal to cut smog raises “the potential for increased operating expenses, decreased federal leasing revenues, permitting delays and decreased oil and natural gas production in the nation’s most productive basin,” the groups said in a letter to leaders of the White House Office of Management and Budget and its regulatory affairs office. The missive was sent Thursday by the American Petroleum Institute, American Exploration and Production Council, Texas Oil and Gas Association and other groups, who have spent weeks huddling over the potential consequences of the ozone plan since it was first outlined in a public notice last month. The move by the EPA to consider giving the Permian a so-called non-attainment designation was encouraged by conservationists who say they are alarmed by indications ground-level ozone has surged along with oil and gas development. Ozone, which is the key ingredient of smog, is formed when volatile organic compounds and other air pollution that escapes smokestacks, tailpipes and oil wells reacts with sunlight. Even at low levels, it can worsen asthma, emphysema, and other respiratory illnesses. While Texas does not have monitors taking ozone readings on its side of the Permian, those just over the border in New Mexico’s Eddy and Lea counties have recorded average ground-level ozone exceeding the 2015 federal standard of 70 parts per billion several years running. If the region is deemed in violation, state regulators would have three years to develop plans for lowering ozone levels, including by preventing new industrial facilities from worsening air quality and ensuring existing sites deploy technology to keep pollution at bay. “A non-attainment designation would ensure that people and communities throughout the Permian Basin no longer suffer the harmful and costly effects of smog,” grassroots environmental and public health groups said in a July 12 letter to President Joe Biden. The oil groups argue that the clampdown could result in existing facilities being forced to shut down and “could have the unintended consequence of slowing the approval of oil and natural gas infrastructure designed to reduce greenhouse gas emissions across the basin.” The potential economic impacts are so severe, they contend, the White House should consider the proposal a “significant regulatory action,” a designation that triggers more stringent review, and the EPA should open it up for public comment.

Methane Is Leaking Over Native Grounds. Citizen Scientists Are Fighting Back. - From behind her FLIR GF320 infrared camera, Kendra Pinto sees plumes of purple smoke otherwise invisible to the naked eye. They’re full of methane and volatile organic compounds (VOCs), and they’re wafting out of an oil tank in New Mexico’s San Juan Basin. Pinto, a member of the Diné (Navajo) community and field advocate with environmental group Earthworks, relies on this device in her fight to keep her community’s air clean. She lives in the Eastern Agency of the Navajo Nation, home to booming oil and gas production. “When I walk outside, I can’t just think about fresh air. I’m thinking about the VOCs. I’m thinking about the methane that I’m breathing in, because I know what’s out there,” Pinto said. “I see it all the time.” She’s one of countless citizen scientists across the country who are tracking and reporting environmental harms committed by the oil and gas industry to regulators. And here there are many: The Environmental Defense Fund (EDF) estimates that each year, New Mexico’s oil and gas companies emit more than 1.1 million metric tons of methane, a greenhouse gas around 86 times more potent in its warming potential than carbon dioxide over a twenty year period. Much of this comes from wasted natural gas -– $271 million of it in this state alone, according to the EDF. It leaks out of faulty equipment and is intentionally expelled through the processes of venting and flaring, in which excess, unrefined natural gas is released or burned from oil wells and refineries to eliminate waste or reduce pressure buildups. This is bad for the planet—high volumes of methane released into the atmosphere accelerate the pace of the climate crisis. It’s also bad for the people who live around it who are exposed to the pollutants that typically come along withmethane emissions, like benzene, a carcinogen, and PM2.5 and PM10 — particulate matter small enough to get lodged deep in the lungs. Pinto said her neighbors experience disproportionately high rates of headaches, nosebleeds, allergies and respiratory issues, like sinus and throat discomfort. “I think the scariest thing about methane is it’s odorless,” Pinto said. “It’s a silent killer. And if my neighbors are breathing it in, that’s worrisome.”

US Oil, Gas Trump Renewable Energy in Public Land Leasing, Report Shows – Bloomberg - Despite President Joe Biden’s campaign vow to propel a “clean energy revolution,” the federal government continues to prioritize oil development over renewable projects on US public lands, a new report finds.The analysis by the left-leaning Center for American Progress shows that, in western states, significantly more public land is available for oil and gas leasing than for renewables development. That’s true even in areas that are better suited for solar, wind and geothermal projects than for drilling — a default position that gives fossil-fuel development a leg up over cleaner energy sources, according to Jenny Rowland-Shea, deputy director of the center’s public lands program.

How Manchin wobble may hit Biden's public land oil strategy - After Sen. Joe Manchin sent climate negotiations into chaos on Capitol Hill last week, the pressure is on President Joe Biden to take his own concrete steps to halt global warming, like toughening his stance on drilling for oil on public lands.The West Virginia Democrat waffled ahead of the weekend on whether he will support climate spending in ongoing negotiations over the reconciliation package that Democrats are trying to get passed ahead of the midterm elections — when the GOP is predicted to gain spots in Congress. He blamed inflation for his position.The political jockeying puts in doubt a legislative answer to Biden’s critical climate ambitions, such as the $300 billion in clean energy tax credits on the table in recent negotiations.But a slammed door in the Senate could also free the White House from having to appease Manchin, who’s made no secret from his bully pulpit as chair of the Senate Energy and Natural Resources Committee of his frustration with the White House’s response to high gas pump prices and its slow walking of federal oil and gas leasing.“If the White House has been modulating its oil and gas policy in recent months to woo Manchin’s support for clean energy incentives, then his latest defection could augment a post-election green pivot, including further strictures on federal lands,” said ClearView Energy Partners LLC in a client note Friday.Last week, The Washington Post reported the White House was considering Manchin as it decided whether to approve a controversial oil drilling project in the Arctic and future drilling access in federal waters in the Gulf of Mexico.But by Thursday night, Manchin had quashed hopes of major climate spending. He pivoted again the next day by saying he might be open to talking about a deal in September — if the country’s inflation picture looked better (Greenwire, July 15).“I can’t make that decision basically on taxes of any type and also on the energy and climate because it takes the taxes to pay for the investment in the clean technology that I’m in favor of,” he said in a recent interview with West Virginia’s MetroNews. “I’m not going to do something and overreach that causes more problems.”The stance has sparked controversy on the political left, with prominent progressives like Sen. Bernie Sanders (I-Vt.) accusing Manchin of sabotaging climate talks because he is beholden to fossil fuel companies. “We continue to talk to Manchin like he was serious. He was not. This is a guy who is a major recipient of fossil fuel money,” Sanders said

Cities: Report that Colorado methane pollution is down by half is wrong - Air pollution from oil and gas operations is on the wane, the industry says. But communities along the Front Range — with their own air monitors — counter that they are finding repeated spikes of methane and other pollutants. “Ground-level methane monitoring shows no decline in levels,” Cindy Copeland, an air and climate policy advisor for Boulder County, told a Colorado Air Quality Control Commission hearing Thursday. In Broomfield, air monitors recorded a dozen spikes where ambient benzene levels were estimated to have exceeded a 9 parts per billion health standard in the fourth quarter of 2021 — in one instance the level reached 223 ppb. Broomfield identified the peaks as coming during drilling, hydrofracturing, or fracking, and tubing wells — the so-called preproduction phase, Mindy Olkjer, the city’s oil and gas program manager told the commission. The air commission adopted new regulations in 2020 to cut emissions from the preproduction phase of oil and gas operations. What the spikes and eddies in emissions means for public health and safety is still undetermined. In May, two industry groups — the Colorado Oil and Gas Association and API-Colorado — made a presentation to the air commission with data showing that between 2013 and 2019 methane levels had decreased 52% and at the monitor in Platteville operated by the state, ethane concentrations were down 65%. The Platteville Atmospheric Observatory is about 5.5 miles southeast of Platteville, in Weld County, the most actively drilled county in the state. On Thursday the industry groups’ findings were challenged by air quality officials from Longmont, Erie, Broomfield and Boulder County, where some of the drilling closest to neighborhoods has taken place. The industry methane measurements were done by satellite for a large section of the Front Range, but the monitors located in communities — the Erie monitor is located next to the baseball field at the town’s community center — offer some “ground truthing,” Copeland said. The Platteville monitor, the local air officials also argued, is no longer representative since the area has already been drilled and operators have moved to new locations.

How oil companies endlessly avoid cleanup costs — High Country News – Jackson County, Colorado, is not known for oil and gas production. But there is some energy development here, including 110 wells on federal public land. K.P. Kauffman, an oil and gas operator with a history of environmental violations, acquired the wells in 2018 from a company called Bonanza Creek. They were not choice assets. At the time, the wells averaged around 32 years old — the oldest were over 70 — and their cumulative production had declined annually since 2011, according to state oil and gas data. About 60% were still actively producing. By 2017, the year before the sale, they were averaging less than two barrels of oil (BOE) per day. Below two BOE per day, a generally accepted industry standard, wells are often considered to not be economically viable. Bonanza was aware of this decline. In its 2014 year-end report to the U.S. Securities and Exchange Commission (SEC), it reported a stark drop in the wells’ value. The company’s estimate of their worth in a sale had fallen to zero dollars. Even so, Bonanza decided to sell. In two financial statements submitted to the SEC in 2015, it stated its intention to get rid of its Jackson County assets. For whatever reason, though, the sale did not take place right away. In early 2017, Bonanza declared bankruptcy. After some restructuring, it re-emerged a few months later, and, the next year, successfully sold the 110 wells for $100,000 and “full release of all current and future obligations” — meaning the legal responsibility to plug the wells. For 110 wells, $100,000 isn’t much. By comparison, drilling a single new, highly productive fracked well in Colorado could cost about $6 million today, according to an analysis of market data by Williams-Derry. “At no point in the process were companies asked to set aside the true cost for cleaning up these wells.” Oil infrastructure in Jackson County, Colorado. In 2018, K.P. Kauffman acquired 110 wells on federal public land in the county, many low-producing. These wells would cost at least $9.6 million to clean up. Since the sale K.P. Kauffman has not plugged any of the wells, which have showed declining net production every year, according to Colorado Oil and Gas Conservation Commission (COGCC) data, including a 19% production drop the year after the transaction. By 2021, the wells averaged a scant 0.37 BOE per day. K.P. Kauffman is unlikely to be making much money, according to a cash-flow analysis by Dwayne Purvis, a petroleum engineer for more than 25 years. “I estimate that these wells were not profitable to operate under normal operating standards,” he said. “An operator might be able to make money on them, but it would require spending little on items like supervision, preventative maintenance and repair.” So, what did each party see in the deal? For Bonanza, the sale coincided with a period of mergers, culminating in a consolidation with other Colorado drillers into a new company, Civitas Resources, now one of the state’s largest oil companies. The Jackson County wells had been in decline for years, so Bonanza got rid of assets with small value for a small return, or, as the company put it in SEC filings, “minimal net proceeds.” Bonanza removed the wells from its books, along with, crucially, the requirement that it pay to plug them someday. As for K.P. Kauffman, it got wells that are still producing oil, even in minor quantities. It got something that will turn a profit in the short-term. In response to a list of questions, a company spokesperson told High Country News: “Our own investigation of these assets at the time of the transfer makes us confident in their value.” It’s possible that K.P. Kauffman believed it could operate the wells more cheaply — thus profitably — than Bonanza. But even if that were true, Purvis said that, once plugging costs are included, he would consider them a “net liability.” “Even assuming reduced operating costs at the time of transfer, there was no viable scenario for the wells to generate enough profit in the future to pay for their plugging,” he said. This appears to be part of K.P. Kauffman’s wider strategy: Low-producing wells make up a significant slice of the company’s more than 1,200 Colorado wells. State data from 2021 shows that 84% of its wells — both active and inactive — produced less than two BOE per day. It’s a business model that appears to rely on not factoring in the true cost of plugging those wells.

Colorado county shuts down crypto operations at oil and gas sites - To the untrained eye, the nondescript boxes and containers scattered around some oil and gas wells in Colorado look a lot like the equipment typically found at a well pad — boxy, utilitarian and industrial. But inside these particular containers, a kind of otherwordly magic is happening. Dozens of high-powered computers quietly crunch complex math problems in an act of cryptocurrency “mining,” whereby virtual currencies like bitcoin are created and added to a kind of worldwide cryptocurrency ledger. A bitcoin miner is essentially in a race with others to solve these math problems — and the winner gets bitcoins as a prize for their efforts. The mobile data center on wheels is powered by a generator that whips up electricity using natural gas pulled up from the ground — gas that often has nowhere else to go but into the atmosphere. In Adams County, this novel mashup of old-school legacy fossil-fuel extraction and futuristic digital-currency creation is a bit too new — at least for now. County officials in May issued a cease-and-desist order, saying the arrangement — “a trailer full of computers powered directly by a producing well” — is unlike any land use Adams County has seen before. The county followed up last week with a lawsuit against an oil and gas producer that it claims has not complied with its order to shut down crypto mining operations in the oil patch. Adams County, according to community and economic development director Jenni Hall, first needs to create rules around the practice before allowing it to resume. “These are remote areas with a lot of dry grassland around them,” Hall said. “We also know they are running generators, which have emissions and make noise.” Adams County, she said, simply doesn’t have language in its land use code that speaks to cryptocurrency mining at the wellhead.

Water protector beats bogus charge, case raises questions about biased law enforcement --A District Court Judge in Aitkin County dismissed charges against water protector Shanai Matteson Thursday morning, on day two of her trial. Matteson was charged with “aiding and abetting” trespassing on Enbridge right of way during Line 3’s construction.The jury had been selected. It had heard from two prosecution witnesses. Before calling any defense witnesses, and before the case went to the jury, Matteson’s attorney Jordan Kushner moved to have it dismissed.Judge Leslie Mae Metzen gave it the heave ho.Matteson faced “bogus charges,” said Kushner, a Twin Cities-based private civil rights attorney. The state couldn’t back them up.“The prosecution failed in its attempt to criminalize Shanai’s use of free speech and to create guilt by association,” he said.It’s an embarrassing loss for the Aitkin County Sheriff’s Office and prosecutors who brought the charges. It’s just the latest example of the disparate justice systems faced by water protectors compared to Enbridge.While Minnesota’s regulatory agencies provided very lax oversight of Line 3 construction, Minnesota law enforcement came down hard on water protectors.(More background here.) The case “should never have been brought in the first place,” Matteson said in a statement released on her behalf.Matteson is a fifth-generation resident of Palisade (in Aitkin County) and a cultural organizer, artist and mother of two young children. She faced up to one year in jail and thousands of dollars in fines, if convicted.Matteson’s crime was speaking to a group of people gathered at the Water Protector Welcome Center in Aitkin County on Jan. 9, 2021 for about 90 seconds.“We are looking for people who might be in a position to potentially get arrested, if that’s what it comes to today,” she told the crowd. “… I hope some of you will consider that.”Then she offered information on jail support for those who might choose to get arrested.

Study: Enbridge Line 3 generated billions in economic impact - Since replacement of Enbridge's Line 3 pipeline began in 2017, a significant increase in economic activity has been experienced across the region, a recent economic impact study found.The study was commissioned by Area Partnership for Economic Expansion, a private-sector-led business development engine for northeast Minnesota and northwest Wisconsin. The study did not consider the social or environmental impacts of the project; its purpose was to solely estimate the economic impacts of replacing three segments of Line 3.This included the mainline which runs through Kittson, Marshall, Pennington, Red Lake, Polk, Clearwater, Beltrami, Hubbard, Wadena, Cass, Crow Wing, Itasca, Aitkin, Carlton and Saint Louis counties; Segment 18 in Douglas County in Wisconsin; and the Superior terminal building in Superior, Wisconsin.“Large-scale industrial projects are critical to continued growth and success throughout not just the APEX region, but also the entire state of Minnesota,” APEX board chair Lisa Bodine said during a Zoom press conference. “The project surpassed all economic impact projections and created family-sustaining jobs for many Minnesotans. APEX is proud to advocate for these types of projects in our region because we understand the economic, environmental and social benefits will be felt for decades to come.”

North Dakota oil production bounces back in May, but industry needs more workers - North Dakota oil production bounced back in May after getting hammered the previous month by ugly weather. The state pumped out 1.06 million barrels of oil a day, up 17% from April when back-to-back blizzards hit North Dakota. "We have almost recovered what we lost in April," Lynn Helms, North Dakota's minerals director, told reporters Tuesday. In May, North Dakota still was running below its March output of 1.12 million barrels per day. The 20% production decline from March to April was one of the worst month-to-month drops in state history. Oil prices in May averaged more than $100 a barrel, meaning North Dakota oil tax collections remain healthy. West Texas Intermediate — the benchmark U.S. crude price — closed around $103 Tuesday. North Dakota's drill rig count, a harbinger of future oil production, currently stands at 42, the same as in June, but ahead of May's tally of 40 and April's 38. The state still is short of the drilling activity it would need to grow production at a 2% annual rate. Helms said the optimal number of rigs for that output target is 50 to 55. At that level of production, about 25 fracking crews — who pump oil from the ground after wells have been drilled — would be needed. Currently, there are 18 crews, and the oil companies are struggling to find more workers, Helms said. Indeed, while inflation has been at 40-year high, the nation's unemployment rate of 3.6% in June is near an all-time low. "In the absence of a nationwide recession, which would send a lot of unemployed people to North Dakota, we will have to grow our own workforce," Helms said.

Keystone Force Majeure Cuts Oil Flows To U.S. - TC Energy, the operator of the Keystone Pipeline, declared force majeure on Monday following a power outage in South Dakota, which reduced the flows on the link carrying crude from Canada to the U.S.TC Energy said in a statement late on Monday that it was made aware of a non-operational incident resulting from third-party damage to the power supply to a facility on the Keystone Pipeline System near Huron, South Dakota. The system continues to operate safely, but it is operating at a reduced rate due to damage to the third-party power utility.“Initial damage assessments have been completed with no material impact to TC Energy owned facilities,” the company said.As a result of the power outage, TC Energy declared force majeure on the Keystone Pipeline, but did not provide a timeline for restoring crude flows to full capacity. “Repairs are being undertaken and we are working to restore full service as soon as possible. A timeline for full-service restoration is not available at this time,” the company said.The 2,687-mile Keystone Pipeline System plays a key role in connecting Alberta’s crude oil supplies to U.S. refining markets in Illinois, Oklahoma, and Texas, as well as connecting U.S. crude oil supplies from the Cushing, Oklahoma, hub to refining markets in the U.S. Gulf Coast through the Marketlink Pipeline System.The reduced flows of crude from Canada to the United States comes days after U.S. President Joe Biden returned from his trip to the Middle Eastern without receiving a specific commitment from the top OPEC producers to boost oil supply in the near term.Meanwhile, gasoline prices in the U.S. continued to fall for a fifth consecutive week, to a national average of $4.51 per gallon as of July 18, according to data compiled by fuel-savings app GasBuddy.

Keystone oil pipeline capacity may be restored next week: company source - The Keystone oil pipeline could return to full capacity next week if the necessary repairs to an electric substation are completed without any major supply chain disruptions for replacement parts, according to a company source. The 590,000 b/d crude artery from Canada to the US has operated at a reduced capacity since July 17 after vandalism damaged a transformer at an electric substation in rural South Dakota that solely services the TC Energy flagship oil pipeline. TC Energy has declined to offer any timeline for a return to full capacity. The company declared force majeure on the pipeline network July 18 and has continued operating at a reduced, but unspecified, capacity. "Our system continues to operate safely at a reduced rate as a result of the incident," the company said in a July 20 statement. "We are unable to further discuss operations as it involves commercially sensitive information. Currently, there is no timeline for completion of repairs and restoration of power service." East River Electric Power Cooperative, which operates the Carpenter Substation in Beadle County, said a criminal investigation is underway. East River said the damaged transformer was leaking mineral oil when the problem was detected. "Our crews are working as fast as they can, but I don't have a good timeline at this time," East River spokesperson Chris Studer said July 20. One market source said that, depending on the length of the outage, this could push differentials for crude oil in Western Canada lower, and lead to significant storage builds as the market depends heavily on Keystone to move crude out of the region. However, "If it is minor and back up soon ... it will be a non-impact event," the source said. The pipeline runs from Hardisty, Alberta, through North Dakota, South Dakota and Nebraska, where it splits with one leg moving crude east through Missouri for deliveries into Patoka, Illinois, and the other moving south to Cushing, Oklahoma, and then onto Houston. Values for heavy sour Western Canadian Select crude have come under pressure already in recent weeks as supply of heavier, sour grades along the US have increased following the release of barrels from the US Strategic Petroleum Reserve. Because crude oil takeaway capacity leaving Canada already is tight, said AJ O'Donnell, product team director for East Daley Capital, there are only a few alternate ways to move the displaced crude oil if Keystone remains at a lower capacity for longer. Enbridge's Mainline network into the US potentially could accommodate another 150,000-200,000 b/d in additional volumes into the US, O'Donnell said, and Enbridge's Express Pipeline to Guernsey, Wyoming, could handle maybe 30,000 b/d. However, there are limited ways to move crude beyond the Guernsey hub. Otherwise, more expensive crude-by-rail exports are the fallback option for shipping the heavy barrels of Canadian crude, he said.

New map shows where fracking-induced earthquakes could hit in Canada -Scientists from the University of Waterloo have developed a map showing which regions and population centers of Western Canada are likely to experience earthquakes induced by underground energy extraction. Hydraulic fracturing is used to produce cracks in the rock formation to enhance energy extraction from geothermal and unconventional resources. This process is typically accompanied by seismicity, or induced earthquakes, because injection changes pore pressures and temperatures, facilitating slippage of fractures and faults. "We are trying to better understand and therefore better predict the phenomenon of induced seismicity during subsurface engineering processes," said Maurice Dusseault, a professor of engineering geology at Waterloo. "Using Western Canada's Montney Formation as a case study is important as the 130,000 km2 area of western Alberta and northeast British Columbia is home to some of the world's largest petroleum and natural gas reserves." The report concluded induced earthquakes in this region continue to threaten communities that have already experienced of the largest fracking-caused earthquakes reported worldwide. This includes a magnitude 4.6 near Fort St. John, British Columbia on November 29, 2018, and a magnitude 4.1 near Fox Creek, Alberta on January 12, 2015. "The majority of injection-induced seismicity occurred near Fort St. John, British Columbia—close to the border of Alberta," said Ali Yaghoubi, the study's lead author and Ph.D. candidate in the Department of Earth and Environmental Sciences at Waterloo. "When I compare the seismicity map with the population density map of Canada, some earthquake-prone areas are indeed populated. However, the majority of seismogenic areas aren't populated." They also found that the area south of Grande Prairie, Alberta is far less prone to significant levels of induced seismicity, despite the fact that the Montney and Duverney formations in the region have been subjected to more than 700 multistage hydraulic fracturing operations. "This is particularly important considering that the area is home to Alberta's No.1 geothermal project," said Yaghoubi. Their map can serve as a baseline for future fluid injection projects or underground energy extraction in the region including wastewater disposal, hydraulic fracture stimulation, carbon sequestration, as well as geothermal energy extraction. The study, "Injection-induced fault slip assessment in Montney Formation in Western Canada," was recently published in the academic journal Scientific Reports.

Oil exploration picking up as drillers shrug off recession threat — Schlumberger said annual sales will rise the most in 11 years as concern over inadequate energy supplies outweighs recessionary fears among major oil explorers. Citing the biggest jump in demand for its services in more than a decade, the world’s biggest oilfield contractor sees sales reaching at least $27 billion this year, an 18% increase from 2021. Schlumberger shares climbed more than 8% after Chief Executive Officer Olivier Le Peuch predicted the uptrend in crude drilling is immune from economic contraction and has years to run. The rosy outlook for a sector recently battered by back-to-back oil busts capped a week of profit reports that included Halliburton Co.’s revelation that it’s nearly sold out of gear in the North American market and already is fielding inquiries from drillers looking ahead to 2023. “The multiyear upcycle continues to gain momentum with upstream activity and service pricing steadily increasing both internationally and in North America, resulting in a strengthened outlook for Schlumberger,” Le Peuch said in a statement Friday. “We are witnessing a decoupling of upstream from near-term demand volatility, resulting in resilient global oil and gas activity growth in 2022 and beyond.” Oil explorers are expanding the search for crude on land and at sea in almost every corner of the globe. In the sector’s most bullish forecast yet, Schlumberger reinforced its view from three months ago when it alluded to the heady days of 2008, when crude prices ascended to dizzying heights and oilfield contractors posted some of their best results in history. “We believe the accelerating international upcycle not only has multiple years to run, but will also unfold even if crude prices pull back modestly,” Scott Gruber, an analyst at Citigroup Inc., wrote in a note to clients. Spending by oil companies around the world is expected to grow 22% this year to $450 billion, according to James West, an analyst at Evercore ISI. That would rank 2022 as the fifth-biggest annual expansion in data going back to 1985.9:48 PM

Activists urge oil spill contingency overhaul - Environmental activists yesterday urged the Government to upgrade the country’s oil spill contingency plan following the 30,000-gallon Exuma leak, adding that The Bahamas must move from “a panicked” to a controlled response. Rashema Ingraham, Waterkeepers Bahamas executive director, told Tribune Business the last time she could recall revisions being made to the plan was 2011 - more than a decade ago - despite the movement of petroleum-based products through the country’s shipping lanes on an almost daily basis. While a “ruptured hose” was being blamed for diesel fuel leaking into waters off Georgetown, she added that issues of liability and who is responsible for environmental clean-up and the associated costs need to be better defined in Bahamian laws and regulations. Multiple Cabinet ministers and government officials raced to Exuma yesterday to assess the oil spill and its impact, but Ms Ingraham argued that a better response would be to ensure the necessary equipment to contain then remediate the incident was already in The Bahamas with trained personnel able to use it effectively. “The last oil spill contingency plan revision was in 2011. That’s been some time now, and that really needs to be given some attention sooner rather than later because we have so many petroleum products moving through our waterways on a regular basis,” Ms Ingraham told this newspaper. “Just think about everything that has happened between that timeframe and now. “This really brings to the forefront for the Prime Minister and his Cabinet to again look at oil industry reform, and not only because we have experience with oil drilling and marine and terrestrial spills in The Bahamas.” Those spills include the loss of 558,000 barrels of oil when the tank roofs at Equinor’s South Riding Point storage terminal in Grand Bahama were compromised when Hurricane Dorian struck the island in early September 2019. “It definitely needs upgrading,” Ms Ingraham said of The Bahamas’ plan for dealing with major oil spills, “and it also needs to point who should be responsible for paying for the spill. It definitely should not be the Government of The Bahamas. The Government should look at putting a levy in place on those moving oil through the country to make them more responsible for their transhipment.” Besides identifying who is liable for clean-up, remediation and the associated cost, she added that The Bahamas needs to completely overhaul how it reacts to oil spills. “We need to move away from the panicked response to these situations to one where we have a more controlled response,” Ms Ingraham told Tribune Business. “This is so we know, based on the spill and the response, what type of resources need to be executed right away. Having men in suits rush over to look at a spill is not the right response. The right response is to have the equipment in place to contain the spill initially, and that equipment needs to be in country.” Other environmental activists yesterday argued that the Exuma spill strengthens the case for banning oil exploration and drilling in Bahamian waters, although there is no link at all between the latter activity and what happened in Georgetown. Joe Darville, Save the Bays’ chairman, said the leak of diesel fuel destined for Bahamas Power & Light (BPL) was “another warning” given the potential consequences for Exuma’s “pristine” waters and environment - the very assets that attract the tourists and homeowners which drive the island’s economy. “It’s a catastrophic disaster because, similar to Equinor, there is no contingency plan available,” he argued. It will be up to Mother Nature to deal with this catastrophic event. “It’s another event to show we have no business thinking about drilling for oil in our waters. It would be a total disaster.”

Top Energy Regulator Warns Germany Won't Survive Winter Without Russian NatGas - Germany is grappling with its worst energy shortage in decades as it might not meet the threshold of adequate natural gas reserves before winter. Germany's national Sunday newspaper Bild am Sonntag interviewed Klaus Muller, head of the Federal Network Agency, the government regulator of electricity, gas, telecommunications, post, and railway markets, who warned NatGas inventories are "nearly 65% full" and "it's better than in the previous weeks," though not enough to "go through the winter without Russian gas."The German government sets a yearly target of 90% by November for NatGas inventories, and with nearly 3.5 months until the target date, injections have turned to withdraws due to the Nord Stream 1 pipeline scheduled maintenance and a menacing heatwave that has bolstered electricity demand. Muller said Nord Stream's 10-day scheduled maintenance ends July 21 or this coming Thursday. The energy situation could worsen if Russian state-controlled natgas exporter Gazprom doesn't resume deliveries or continues to restrict flows. When asked how long until energy prices decrease, Muller said, "there hasn't been any significant price surge this week, even though the Nord Stream 1 was shut off." He said this could signify that "markets have already internalized the loss of Russian gas supplies, and we've reached a gas price plateau."Berlin triggered the second stage of its national NatGas emergency plan last month -- the next phase is rationing NatGas. Muller said there is a rising probability of rationing, which would wreak havoc on the economy and supply chains.Germany also receives NatGas from Belgium, Norway, and the Netherlands, but the plunge in Russian supplies indicates Germany is behind on filling up its storage facilities to create reserves for winter. Dutch front-month gas, the European benchmark, traded around 163 euros per megawatt-hour last week.

EU signs new gas deal as fears grow over Russian supplies cutoff — The EU signed a new gas deal with Azerbaijan on Monday, as officials scramble to secure future supplies amid growing fears about a Russian cutoff.European officials have been preparing for a potential complete shutdown of gas supplies from Russia in the wake of Moscow's invasion of Ukraine. Russia has for several years been Europe's most important source of natural gas, but there's now a firm push by Brussels to reverse this.European Commission President Ursula von der Leyen and Europe's energy chief, Kadri Simson, were in Azerbaijan on Monday to finalize the deal. In a statement, the commission said Azerbaijan had committed to delivering at least 20 billion cubic meters to the EU annually by 2027.Azerbaijan was already on track to increase it deliveries to the region. According to the commission, gas supply from the country will increase from 8.1 billion cubic meters in 2021 to an expected 12 billion cubic meters this year."Amid Russia's continued weaponization of its energy supplies, diversification of our energy imports is a top priority for the EU," the European Commission said in a statement Friday ahead of the trip.Russia has denied it is using gas as a weapon against the West, however supplies have fallen by more than 60% in recent weeks. In addition, the shutdown of the Nord Stream 1 pipeline — a crucial transit point of Russian gas to Germany and beyond — for maintenance work has added to concerns that Moscow could potentially end its supplies of gas to the bloc altogether. Azerbaijan, which borders Georgia, Turkey, Armenia, Russia, Iran and the Caspian Sea, started exporting natural gas to Europe via the Trans Adriatic Pipeline at the end of 2020. At the time, Azerbaijan said it planned to send 10 billion cubic meters of gas to Europe every year, mostly to Italy, but also to Greece and Bulgaria.

Russia’s Gazprom declares force majeure on some gas supplies to Europe -Russia’s Gazprom has declared force majeure on gas supplies to Europe to at least one major customer, according to the letter from Gazprom dated July 14 and seen by Reuters on Monday. The letter said Gazprom, which has a monopoly on Russian gas exports by pipeline, could not fulfil its supply obligations owing to “extraordinary” circumstances outside its control. It said the force majeure measure, a clause invoked when a business is hit by something beyond its control, was effective from deliveries starting from June 14. A trading source said the letter concerned supplies through the Nord Stream 1 pipeline, a major supply route to Germany and beyond. Gazprom had no immediate comment. The measure will likely escalate tensions between Russia and the West over the Russian invasion of Ukraine, action Moscow calls a “special military operation.” The European Union, which has imposed sanctions on Moscow, aims to stop using Russian fossil fuels by 2027 but wants to supplies to continue for now as it shifts away from Russian supplies. Russian gas supplies have dropped via major routes, including via Ukraine and Belarus and through Nord Stream 1 under the Baltic Sea. Nord Stream 1 is currently undergoing maintenanc

Russia nears gas shutdown in Europe as Germany rejects claims it can't fulfil contracts — Russia's energy giant is threatening to send less gas to Europe — but Germany, one of its main importers, has rejected the idea.Majority state-owned Gazprom said Monday that due to unforeseeable circumstances it is not in a position to comply with gas contracts in Europe.Germany's energy firm, Uniper, confirmed to CNBC that Gazprom had claimed "force majeure" on its supplies. Force majeure, a legal term, occurs when unforeseeable circumstances prevent one party from fulfilling its contractual duties, in theory absolving them from penalties."It is true that we have received a letter from Gazprom Export in which the company claims force majeure retroactively for past and current shortfalls in gas deliveries. We consider this as unjustified and have formally rejected the force majeure claim," Lucas Wintgens, spokesperson for Uniper, told CNBC's Annette Weisbach.RWE, another German energy company, confirmed to CNBC that it had also received a force majeure notice from Gazprom.Gazprom was not immediately available for comment when contacted by CNBC on Tuesday.Officials in Germany and elsewhere in Europe have become increasingly concerned about the possibility of a complete shutdown of gas supplies from Russia. These fears intensified after Nord Stream 1 — a key gas pipeline from Russia to Germany — was closed earlier this month for maintenance work, with some doubting that flows will be fully restored after the work is concluded on July 21. European nations received about 40% of their gas imports from Russia before it invaded Ukraine. European officials have been scrambling to end this dependency, but it's a costly process and hard to achieve overnight.

Russia’s squeeze on gas means Germany’s energy giant is having to draw supplies from storage - German energy giant Uniper on Friday said it is having to draw down gas from storage facilities, reducing supplies needed for winter even as Europe is experiencing an extreme heatwave. The embattled utility told CNBC in a statement that reducing gas volumes from its own storage facilities was necessary “in order to supply our customers with gas and to secure the Uniper’s liquidity.” Finnish majority-owner Fortum said last week that Uniper submitted a bailout application to the German government after running into extreme financial distress due to a scarcity of gas and soaring prices. Germany’s economy ministry said Friday that there is still no timeframe for government assistance, according to Reuters. Speaking to reporters at a press conference on July 8, Uniper CEO Klaus-Dieter Maubach warned that drawing down gas supplies from its storage facilities was a possibility due to the “enormous decrease” of imported gas from Russia. It comes even as Europe is sweltering amid a heat wave that has seen temperatures exceed 40 degrees Celsius (104 degrees Fahrenheit) in several countries. Droughts and wildfires have been recorded in Spain and Portugal and sweltering temperatures have spread to the U.K. and France. Climate scientists have repeatedly made clear that human-caused global heating is making heat waves more likely and more intense. As scorching temperatures spread across the region, European policymakers remain focused on preparations for when the cold weather returns. Governments are scrambling to fill underground storage with gas supplies to provide households with enough fuel to keep the lights on and homes warm during winter. Uniper was the first German energy company to sound the alarm over soaring energy bills in the wake of Russia’s onslaught in Ukraine. The company has received only 40% of Russian contracted volumes in recent weeks and has been forced to source the replacement volumes at significantly higher prices. What’s more, annual maintenance on the Nord Stream 1 pipeline — the European Union’s biggest piece of gas import infrastructure — has fueled fears of further disruption to gas supplies. Russia suspended deliveries via the Nord Stream 1 pipeline on July 11. The summer maintenance works are scheduled to run through to July 21. Germany fears Russia may continue to throttle Europe’s energy supplies beyond the scheduled end of the Nord Stream 1 pipeline maintenance for “political reasons.”

Italy’s gas storage ‘well above 65%’ of capacity, on track for 90% by October - Italy has filled far more than 65% of its gas storage capacity and is on track to achieve its target of reaching storage levels of 90% in October, the ecological transition minister said on Saturday. “Our storage is well above 65%. We must achieve 90% and possibly more in October. For now we are doing well,” Roberto Cingolani said during an online event.

Italy signs clutch of deals with Algeria in bid to boost gas supply -Italian Prime Minister Mario Draghi sealed 15 agreements with Algeria’s president Monday, ahead of the expected conclusion of another deal to boost gas deliveries and reduce Italy’s reliance on Russian supplies. ADVERTISING Draghi was received by President Abdelmadjid Tebboune, and the two went on to sign agreements and memorandums of understanding in areas ranging from energy to sustainable development, justice and micro-enterprises. The energy agreement signed on Monday is “a testament to our determination to achieve even more in this domain,” Draghi said, ahead of the expected signing of an oil and gas supply deal between Algeria and a clutch of companies including Italian energy giant Eni. “Tomorrow, an important agreement between (US energy firm) Occidental (Petroleum), Eni and (French oil company) Total providing significant volumes of natural gas” to Italy will be signed, Tebboune earlier told reporters at a joint news conference with Draghi. This contract will allow “the development of a site situated in the Berkine perimeter, and which should generate more than a billion barrels” of hydrocarbons, a government source told AFP. Tebboune said the deal was worth $4 billion. The government source confirmed that Algeria will also increase gas exports to Italy by four billion cubic metres in the coming days, as part of a deal reported Friday. Italy buys the majority of its natural gas from abroad, with some 45 percent of its imports historically coming from Russia. But Rome has increasingly looked to Algeria, historically its second biggest supplier, to reduce that dependence after the war in Ukraine sparked sanctions against Moscow and sent energy prices soaring. Algeria has therefore supplanted Russia to “become in recent months the biggest supplier of gas” to Italy, Draghi told reporters on Monday.

Macron seeks 'energy sobriety' from French, turns off street lights - French President Emmanuel Macron warned Thursday to prepare for a total cutoff of Russian natural gas by supporting alternatives, having public lights switched off at night and implementing, what he called, a period of nationwide "energy sobriety." The Russian invasion of Ukraine and the West's sanctions have aggravated other factors driving up prices for energy and other goods. With no end in sight for the Ukraine war, Macron said, the French should brace themselves for costs to remain high. “This war will continue," he said in a televised interview marking France's national holiday, Bastille Day. “The summer, early autumn will be very hard,” he added. "Russia is using energy, like it is using food, as a weapon of war,” Macron argued. “We should prepare ourselves for the scenario where we have to go without all Russian gas,” he warned. He said the government would prepare a “sobriety plan” to conserve energy, which would start with turning off public lights at night when they are not being useful. France will keep looking to diversify gas sources, he said, calling for a faster shift toward offshore windfarms and more European cross-border energy cooperation to weather the current crisis. Macron's political opponents on the far right and far left have blamed EU sanctions for reducing the purchasing power of French consumers while failing to persuade Russian President Vladimir Putin to pull troops out of Ukraine. France's president gave no indication during the interview of a policy shift toward Ukraine. “What do you want us to do?” he asked. “We want to stop this war without getting involved in this war. At the same time, we want to do everything so that Russia doesn’t win, so that Ukraine can defend its territory. We don’t want a world war,” he explained.

EU To Reduce Natural Gas Use By 15 Pct On Russian Supply Woes -The European Union is set to propose a voluntary 15% cut in natural gas use by member states starting next month on concern Russia may halt supplies of the fuel. The goal would be embedded in a regulation accompanying a demand-reduction plan the European Commission is scheduled to unveil Wednesday to cope with a potential full cutoff by Moscow. The measure also will include a mandatory trigger if the situation worsens and voluntary curbs are insufficient, according to three EU diplomats with knowledge of the matter. Under its “Save gas for a safe winter” plan, the commission plans to recommend steps that include reducing heating and cooling, as well as market-based measures. As much as 1.5% of the region’s gross domestic product is at risk in the event of a harsh winter, according to a draft commission estimate seen by Bloomberg News. The EU’s biggest challenge this winter is to ensure sufficient gas supplies to fuel furnaces and power generators. This is a modal window. The media could not be loaded, either because the server or network failed or because the format is not supported. The commission is working under the assumption that Russia will not resume full deliveries via the Nord Stream 1 pipeline that has been closed since earlier this month for repairs, Budget Commissioner Johannes Hahn said on Tuesday. The pipeline was only flowing at about 40% capacity before the repairs began. Curtailments of Russian shipments have affected 12 member states and prompted Germany to raise its gas-risk alert to the second-highest level last month. Overall flows from Russia in June were less than 30% of the 2016-2021 average, according to the document. The planned regulation would grant the commission the right to declare a union-wide alert when there is a substantial risk of a severe supply shortage or a demand spike, according to the diplomats, who asked not to be identified as talks on the proposal are private. The EU has a policy of not commenting on draft rules.

Spain, Portugal reject EU plan to cap natural gas use -(AP) — The European Union’s plan to reduce the bloc’s gas use by 15% to prepare for a potential cutoff by Russia this winter has been met with sharp skepticism by Spain and Portugal, two governments that are usually big supporters of the bloc. Madrid and Lisbon on Thursday said they would not support the initiative announced by European Commission Ursula von der Leyen on Wednesday. The proposal by the EU’s head office would start with voluntary reductions but it also wants the power to make 15% savings mandatory for bloc's 27 nation in the event of an EU-wide energy emergency provoked by Russia’s invasion of Ukraine. Spain and Portugal, however, said making reductions obligatory is a non-starter. They noted that they use very little Russian gas compared to other EU nations such as Germany and Italy and that there are scant energy connections linking them to the rest of Europe. “We will defend European values, but we won’t accept a sacrifice regarding an issue that we have not even been allowed to give our opinion on,” Spain’s Ecological Transition Minister Teresa Ribera said. “Not matter what happens, Spanish families won’t suffer cuts to gas or to the electricity to their homes,” she said. “(The measure) would serve for nothing if the gas that could not be used by Spanish industries could not then later be used by the homes or industries of other countries.” Portugal’s secretary for the environment and energy, João Galamba, said the proposed measure was “unsustainable” and “disproportionate.” “The whole logic behind rationing presupposes interlinked (European gas distribution) systems and it appears the European Commission forgot about that,” he told the Portuguese newspaper Publico. He added that “Portugal was for years and years disadvantaged because it had no links” to the rest of Europe’s energy distribution network and the country has always had to buy “more expensive gas.” The reduced electrical connections and gas pipelines between Spain and France led to the EU allowing Iberian countries to install their own price control mechanisms this spring. All EU countries — as well as many nations around the world — are battling soaring inflation driven by energy prices. Spanish officials also noted their expanded infrastructure for importing LNG — liquified natural gas. With six plants in Spain and one in Portugal, they account for one-third of Europe’s LNG processing capacity. EU member states will discuss the proposed gas-saving measures at an emergency meeting of energy ministers next Tuesday.

EU expects Russian gas cutoff, to release winter energy plan - (AP) — Expecting that Russian President Vladimir Putin will cut off vast natural gas supplies to the European Union, the bloc's head office is set to propose energy cuts and savings Wednesday that might make for a much colder winter, but one without massive disruptions. Since Russia invaded Ukraine, the EU has approved bans on Russian coal and most oil to take effect later this year but did not include natural gas because the 27-nation bloc depends on it to power factories, generate electricity and heat homes. Now, it fears that Putin will cut off gas anyway to try to wreak economic and political havoc in Europe this winter. “We are working on the worst possible scenario," said Eric Mamer, spokesman for the European Commission, the EU’s executive arm. “And that scenario — an assumption, therefore — is that Gazprom would no longer deliver any gas — any gas — to Europe.” Experts were still plotting how to spread the pain of cuts equally among member states under the plan. Up to the last hours, EU officials were putting final touches on how the proposals would look, including how far guidance would go and where mandatory rules would have to kick in. Early leaks said the plan for call for EU nations to limit gas consumption by as much as 15%, but changes could still come at the last moment. The aim is to ensure essential industries and services like hospitals could keep functioning, while others would have to cut back. That could include lowering heat in public buildings and enticing families to use less energy at home. EU nations and the Commission have gone on a buying spree to diversify its natural gas sources away from Russia, but they are still expected to fall far short of providing businesses and homes with enough energy in the cold months. Just Monday, the leaders of Italy, France and the 27-nation EU sealed energy deals with their counterparts in Algeria, Azerbaijan and the United Arab Emirates. Even if the EU has enough gas to keep the lights on and factories running right now, it does so at painfully high prices that have fueled runaway inflation and caused public uproar. Russia has cut off or reduced gas to some EU countries, and there are fears that the energy crisis will get worse if Moscow does not restart a key pipeline to Germany after scheduled maintenance ends Thursday. “We already have 12 countries or in certain cases, companies within countries that, from one day to the next, have experienced disruptions, either full or partial flow from gas from Gazprom,” Mamer said. “It is impossible for us to predict how Gazprom is going to act.” Reliance on Russian gas varies greatly among member states, with Germany heavily affected by any possible cutoff. Germany’s biggest importer of Russian gas, Uniper, said it had received a letter from Russia’s Gazprom claiming “force majeure” — events beyond its control — as the reason for past and current shortfalls in gas deliveries, a claim that the Uniper rejected.

Putin Says Nord Stream Will Restart, With Conditions -Russian President Vladimir Putin signaled that Europe would start getting gas again through a key pipeline but warned that unless a spat over sanctioned parts is resolved, flows will be tightly curbed. Europe is on tenterhooks, waiting to see whether gas flows resume on Thursday when maintenance on the Nord Stream pipeline is set to end. Putin gave the clearest signal yet that Moscow plans to restart at least some flows. But if a pipeline part that was caught up in sanctions isn’t returned to Russia, then the link will only work at 20% of capacity as soon as next week -- as that’s when another part that’s now in Russia needs to go for maintenance, Putin said. After frantic diplomatic efforts by Germany, the turbine is on its way home from Canada. “If another comes, two will operate. If not, just one, so 30 million cubic meters will be pumped per day,” he told reporters after a summit in Iran late Tuesday. He wants the part back in Russia, along with all its paperwork, he said. Gas prices were little changed. Now no gas is flowing through the biggest pipeline to Europe because of maintenance, just as the continent is trying to refill its storage for winter. Before maintenance, gas was flowing at about 40% of capacity. Gazprom PJSC is poised to restart flows, Bloomberg reported on Tuesday, but at reduced levels, according to people familiar with the situation. Ultimately, it’s a decision for the Kremlin. Across the region, officials and businesses have been on edge as to whether Russia will reopen the tap for Nord Stream. The European Union is working on the assumption flows will be cut and scrambling to find ways to reduce consumption. The bloc is facing its worst energy crisis in decades, with the threat of shortages undermining the euro and adding to the risks of recession.

Vladimir Putin wants to keep Europe in 'perpetual panic' as Russia restarts Nord Stream gas flows, analyst says -While gas flows through the pipeline have resumed at 40% of capacity, the Kremlin could later cut it to 20% to turn the screws further on Europe, which has accused Russia of weaponizing energy in retaliation for its sanctions after Putin launched a war on Ukraine."He wants to keep the continent in perpetual panic," Helima Croft, global head of commodity strategy at RBC Capital Markets, told CNBC."He wants to remain in the driver seat of this crisis."She added that she expects Russia to make further cuts to European gas deliveries, calling Thursday's Nord Stream restart a temporary reprieve.To be sure, Europe is preparing for reduced gas flows. On Wednesday, the European Commission proposed a 15% cut in EU gas consumption that could become mandatory if the energy situation worsens.Croft added that Europe will have a difficult time maintaining unity as countries look to ration gas supplies.She noted that Greece, Spain and Portugal have already raised concerns over the proposed 15% cut, with Spain suggesting it shouldn't bear as heavy a burden on rationing."Germany is going to bear the brunt of this 50% of German consumers use gas to heat their homes, and so this is going to be a real challenge for Germany when they have to think about rationing," she said.

Germany again rejects Russian explanation for gas supply cut - (AP) — The German government said Monday that a turbine at the center of uncertainty about future gas deliveries through a major pipeline from Russia to Europe was only supposed to be installed in September, underlining its insistence that there should be no technical obstacle to the gas flow. Meanwhile, Germany's biggest importer of Russian gas said it had received a letter from Russia's Gazprom claiming “force majeure” — events beyond its control — as the reason for past and current shortfalls in gas deliveries, a claim that the importer rejected. Analysts say the impact of the move on future gas deliveries is uncertain. Gazprom reduced gas deliveries through the Nord Stream 1 pipeline to Germany by 60% last month. The state-owned gas company cited alleged technical problems involving equipment that partner Siemens Energy sent to Canada for overhaul and couldn’t be returned because of sanctions imposed over Russia’s invasion of Ukraine. The Canadian government said over a week ago that it would allow the gas turbine that powers a compressor station to be delivered to Germany, citing the “very significant hardship” that the German economy would suffer without a sufficient gas supply to keep industries running and to generate heat and electricity. German politicians have dismissed Russia’s technical explanation for last month’s reduction in gas flowing through Nord Stream 1, saying the decision was a political gambit by the Kremlin to sow uncertainty and further push up energy prices. “We don't see technical reasons,” Economy Ministry spokeswoman Beate Baron told reporters in Berlin. “Our information is that this turbine is a replacement turbine that was earmarked for use in September but, again, we are doing everything to take away possible pretexts for the Russian side.” Nord Stream 1 shut down altogether for annual maintenance on July 11. German officials are concerned that Russia may not resume gas deliveries at all after the scheduled end of that work Thursday and could cite an alleged technical reason not to do so.

Germany agrees to bail out energy giant Uniper as Russia squeezes gas supplies - Germany on Friday agreed to bail out Uniper with a 15 billion euro ($15.24 billion) rescue deal, as the embattled energy company becomes the first major casualty of Russia's natural gas squeeze. The package will see the German state take a 30% equity stake in Uniper. The company's shares initially rose when the deal was announced, before falling sharply. They were trading more than 21% lower an hour later. Uniper was the first energy company in Germany — Europe's largest economy — to sound the alarm over soaring energy bills, and submitted a bailout application for government support earlier this month. As Germany's biggest importer of gas, it has been hit hard by vastly reduced flows via pipelines from Russia, which have sent prices soaring. In a statement, Finnish majority-owner Fortum said Uniper and the German government had agreed on a "comprehensive stabilisation package" to provide it with financial relief. "We are living through an unprecedented energy crisis that requires robust measures. After intensive but constructive negotiations, we found a solution that in an acceptable way met the interest of all parties involved," Fortum's president and CEO, Markus Rauramo, said in the statement. "We were driven by urgency and the need to protect Europe's security of supply in a time of war." Following the bailout, Fortum will own a 56% stake in Uniper — down from around 80% before the deal. The German government is ready to provide further support if Uniper's losses — as a result of the gas squeeze — exceed 9 billion euros, Fortum added. Russian gas supplies to Europe have fallen since its unprovoked invasion of Ukraine earlier this year — and the subsequent sanctions placed on Moscow by the West. Uniper has received only "a fraction of its contracted gas volumes" from Russian gas giant Gazprom since mid-June, according to Fortum, meaning it has had to buy gas at much-higher spot market prices. This has had severe consequences for Uniper's financial position, Fortum added. The front-month gas price at the Dutch TTF hub, a European benchmark for natural gas trading, was around 5% higher Friday at 164 euros per megawatt-hour. Prices are up more than 650% over the last year. Last week, Uniper said it was already having to draw down gas from storage facilities, reducing supplies needed for winter. In a statement to CNBC, the company said that reducing gas volumes from its own storage facilities was necessary "in order to supply our customers with gas and to secure the Uniper's liquidity."

Key gas pipeline from Russia to Europe restarts after break - (AP) — Natural gas started flowing through a major pipeline from Russia to Europe on Thursday after a 10-day shutdown for maintenance — but the gas flow remained well short of full capacity and the outlook was uncertain, which leaves Europe still facing the prospect of a hard winter.The Nord Stream 1 pipeline under the Baltic Sea to Germany had been closed since July 11for annual maintenance work. Amid growing tensions over Russia’s war in Ukraine, German officials had feared that the pipeline — the country’s main source of Russian gas, which recently has accounted for around a third of Germany’s gas supplies — might not reopenat all.Network data showed gas beginning to arrive through the Nord Stream 1 pipeline as scheduled after 6 a.m., and the operator said that it had “successfully completed all planned maintenance works.” But deliveries were still far below the pipeline's full capacity, as they were for weeks before the maintenance break.The head of Germany's network regulator, Klaus Mueller, said Russia’s Gazprom had notified deliveries Thursday of about 30% of the pipeline's capacity. He later tweeted that actual deliveries were above that amount and could reach the pre-maintenance level of some 40%.That wouldn't be enough to resolve Europe's energy crisis. “The political uncertainty and the 60% reduction from mid-June unfortunately remain,” Mueller wrote.When Gazprom reduced the flow last month, it cited alleged technical problems involving equipment that partner Siemens Energy sent to Canada for overhaul and couldn’t be returned because of sanctions imposed over Russia’s invasion of Ukraine.The Canadian government earlier this month gave permission for the turbine that powers a compressor station at the Russian end of the pipeline to be delivered to Germany.The German government has rejected Gazprom’s technical explanation for the gas reduction, charging repeatedly that it was only a pretext for a political decision to sow uncertainty and further push up energy prices. It has said the turbine was a replacement that was only supposed to be installed in September, but that it’s doing everything to deprive Russia of the pretext to reduce supplies.

Vladimir Putin wants to keep Europe in 'perpetual panic' as Russia restarts Nord Stream gas flows, analyst says -While gas flows through the pipeline have resumed at 40% of capacity, the Kremlin could later cut it to 20% to turn the screws further on Europe, which has accused Russia of weaponizing energy in retaliation for its sanctions after Putin launched a war on Ukraine."He wants to keep the continent in perpetual panic," Helima Croft, global head of commodity strategy at RBC Capital Markets, told CNBC."He wants to remain in the driver seat of this crisis."She added that she expects Russia to make further cuts to European gas deliveries, calling Thursday's Nord Stream restart a temporary reprieve.To be sure, Europe is preparing for reduced gas flows. On Wednesday, the European Commission proposed a 15% cut in EU gas consumption that could become mandatory if the energy situation worsens.Croft added that Europe will have a difficult time maintaining unity as countries look to ration gas supplies.She noted that Greece, Spain and Portugal have already raised concerns over the proposed 15% cut, with Spain suggesting it shouldn't bear as heavy a burden on rationing."Germany is going to bear the brunt of this 50% of German consumers use gas to heat their homes, and so this is going to be a real challenge for Germany when they have to think about rationing," she said.

Turbine for Nord Stream 1 Is Still Travelling To Germany - A gas turbine for the operation of Gazprom PJSC’s Nord Stream 1 pipeline that’s the main route of gas transport from Russia to Germany is held up in transit after maintenance in Canada, the latest twist in an ongoing spat between the two countries. “Under normal circumstances, the maintenance of turbines is a routine operation for us. Naturally, we want to transport the turbine to its place of operation as quickly as possible. However, the time it takes is not exclusively within our control,” a spokesman for Siemens Energy, the manufacturer for the turbine, said in an emailed statement Thursday. The turbine, only a spare part for the pipeline, was sent to Siemens Energy’s Montreal site for repairs but became stranded due to sanctions on Russia’s oil and gas industry unveiled last month. Germany’s Economy Minister Robert Habeck proposed a workaround whereby the part would be delivered first to Germany, and from there to Russia. Gazprom last week said it requested documents from Siemens that will allow the return of the turbine. The papers, which the Russian gas giant requested July 15, should help move it amid sanctions regimes in Canada and the European Union back to the Portovaya compressor station -- “a critical facility for the Nord Stream gas pipeline,” the firm said Saturday. Reuters reported earlier Thursday that the turbine was held up in transit in Cologne after returning from Canada and that Moscow had so far not provided documents needed to import it into Russia, including details on where exactly to deliver it and via which customs station. Portovaya is located about 20 kilometers from the Finnish border on the Russian side.

China LNG Demand Revival Can Add to Europe Energy Troubles - Europe may face a further setback in efforts to manage its energy crisis if there’s a revival in China’s demand for liquefied natural gas, according to Goldman Sachs Group Inc. Weaker LNG consumption as a result of coronavirus curbs has seen the nation add to inventories, and enabled importers to capitalize on high prices by reselling cargoes -- boosting the availability of shipments for European buyers, Goldman’s head of natural gas research Samantha Dart told Bloomberg Television in an interview. “They have been reselling their LNG cargoes out in the spot market. The more they resell, the more is available for Europe,” Dart said. “That brings up an important risk -- the moment Chinese economic activity picks up, we may see this quickly change and as a result fewer cargoes for Europe.” China’s total domestic demand for natural gas was down in April and May from a year earlier, and about flat in June, she said. The country’s LNG imports could fall 14% this year on factors including higher prices and a subdued economy, according to Wood Mackenzie Ltd. The global energy squeeze means countries will need a more flexible short-term approach on the move to low-emissions sources, because growth in renewables isn’t yet sufficient to offset any gap in natural gas supply, Dart said. “The energy transition is not going to stop, but it is going to have to be more tolerant of hydrocarbons for a little bit longer when we don’t have enough natural gas,” Dart said. “There is no other way but to bring in coal, bring in oil, bring in other fuels.”

ExxonMobil acquires majority exploration rights for Crete region - Hellenic Petroleum on Tuesday announced that ExxonMobil acquired the majority of hydrocarbon exploration rights in the region of west and southwest of Crete, following the departure of TotalEnergies. ExxonMobil and TotalEnergies, with 40% each, and Hellenic Petroleum (20%), previously had the majority of hydrocarbon exploration rights. Hellenic Petroleum said that ExxonMobil now has 70% of exploration rights and Hellenic Petroleum the remaining 30%. A series of seismic research was conducted in the region in 2012. In December 2021, Cyprus and a consortium made up of ExxonMobil and Qatar Energy signed a natural gas exploration and production sharing contract relating to an offshore field. The signing came in the face of a strong reaction by Turkey, which claims exploration rights in an area off the southwestern Cypriot shores, which includes block 5 of the officially declared Cyprus Exclusive Economic Zone (EEZ) that was licensed to the consortium. Turkey has claimed that by licensing gas exploration, Cyprus violated its continental shelf and warned that it would not allow unauthorized exploration in its marine jurisdiction. It also said that the agreement violated the rights of Turkish Cypriots, who live in a part of Cyprus controlled by Turkish troops. Cyprus rebuffed the Turkish assertions, saying that it “deliberately fails to comply with International Law, by making groundless claims and disregarding the international community’s position in full support of the sovereign rights of Cyprus in its own continental shelf.”

Russian and Iranian energy giants reach $40 billion deal to develop oil and gas projects as Putin visits Tehran -Russia and Iran reached a tentative deal to develop future oil and gas projects Tuesday, signing a memorandum of understanding worth $40 billion.Gazprom and the National Iranian Oil Company reached preliminary terms for the Russian state-run energy giant to aid in the development oil and gas fields as well as the construction of pipelines and liquefied natural gas projects."The National Iranian Oil Company does not ignore any investment opportunity," Mohsen Khojastehmehr, NIOC's chief executive, told Iran's state media.The agreement comes on the same day Russian President Vladimir Putin visits Tehran to meet with Iranian and Turkish heads of state.Iran owns the largest supply of natural gas reserves ahead of Russia. A deal between the two comes amid a strained energy market suffering from skyrocketing prices and unstable sourcing.Europe is preparing for a potential full-scale shutdown of Russian gas flows after the invasion of Ukraine upended global energy markets and drew condemnation that resulted in sanctions from the West.As a result, Russia is turning to other countries to send energy supplies. A Russia-China gas pipeline will break ground within the next two years, as the two allies deepen their economic and energy ties. The pipeline will run 2,600 kilometers and is expected to begin service in 2030. Meanwhile, the European Union signed a new gas deal with Azerbaijan on Monday to double imports of natural gas by 2027 to at least 20 billion cubic meters.

Russian And Iran Ink $40 Billion Oil And Gas Agreement - Ahead of Russian President Vladimir Putin’s visit to Iran on Tuesday, his second foreign trip since he invaded Ukraine in February, Russian Gazprom and the National Iranian Oil Company have inked a $40-billion agreement for the development of oil and gas fields. Moscow and Tehran signed the $40-billion Memorandum of Understanding (MOU) just ahead of Putin’s arrival in the Iranian capital. The deal, in its preliminary form, will see Gazprom assist Iran’s state oil company in the development of both oil and gas fields and the construction of LNG project pipelines. According to Iran’s PressTV, the deal includes a $10-billion project in Kish and North Pars gas fields in the Persian Gulf, along with the $15-billion project to boost pressure at South Pars, which is the largest gas field in the world, shared by Iran and Qatar. Additionally, the deal will see Iran’s national oil company cooperate with Gazprom to complete LNG projects and construct export pipelines for gas. Finally, the MoU paves the way for energy swap deals between the two countries. The Iranian National Oil Company is calling the deal the “largest foreign investment commitment on record” in Iranian oil industry history, claiming that the Russian investment represents one-quarter of all oil sector investments in the country from now until 2025. Also on Tuesday, Iran launched Iranian rial-Russian ruble trading in its foreign exchange market in a further effort to shore up ties with Moscow and to boost exports to Russia. The move comes as Russia steps up efforts to abandon the petrodollar due to sanctions. In his second post-invasion international trip, Putin is meeting with Iranian President Ebrahim Raisi in Tehran on Tuesday, followed by meetings with Iranian Supreme Leader Ali Khamenei and Turkish President Recep Tayyip Erodgan. The meetings will discuss energy, the conflict in Syria, global grain exports and the conflict in Ukraine.

Price cap on Russian oil is a 'ridiculous idea' and could push oil to $140, says think tank --The proposed price cap on Russian oil is a "ridiculous idea" that could backfire on the U.S. and the other Group of 7 countries, according to the co-director of the Institute for the Analysis of Global Security. "It's kind of a ridiculous idea in my view," Gal Luft told CNBC's "Squawk Box Asia" on Monday. "It ignores the fact that oil is a fungible commodity," he said. The term fungible means interchangeable, implying equal value between two barrels of oil, for example. The U.S. wants to put a cap on Russia's oil prices to reduce funds flowing into the the country's war chest, while also bringing down the cost of oil for consumers. Luft likened the plan to going to a shop and asking the seller to accept less money than the listed price. "That's not how the oil market works," he said. "This is a very sophisticated market, you cannot force the prices down." What's likely to happen is that Russia will restrict its production and create an artificial shortage in the market, he predicted. "Those Europeans and Americans that are talking about $40 a barrel, what they're going to get is $140 a barrel," Luft warned. Bloomberg, citing people familiar with the matter, has reported that the U.S. and its allies have discussed capping the price of Russian oil between $40 and $60 per barrel. "You cannot trick the laws of supply and demand, and you cannot defy the laws of gravity when it comes to a fungible commodity," he said. Oil prices have been volatile and shot up as demand roared back after countries rolled back Covid measures and reopened. Russia's war on Ukraine also contributed to the spike in energy prices. To punish Moscow for the invasion, the U.S. banned imports of Russian oil, while the European Union has plans to impose a gradual embargo. Meanwhile, some oil-producing countries are struggling to raise output.

Tanker Companies Race To Ship Russian Oil Ahead Of New Sanctions - Western sanctions have so far failed to crush Russia’s oil exports as Moscow is redirecting crude to its more than willing Asian buyers, China and India. European vessel owners, especially private Greek operators, are moving a lot of the Russian oil in the months before the EU ban on seaborne Russian oil imports kicks in at the end of this year. Greek tanker owners have increased their exposure to Russian oil shipping in the past two months as they race to profit from the higher demand for heavily discounted Russian oil in China and India. Once EU sanctions on seaborne imports of Russian oil take effect this December, Greek tanker operators will have to stop shipping Russian oil. A much bigger blow to Russian oil exports that will have dramatic consequences on the global oil tanker market and oil prices comes from provision number two in the sixth sanctions package - EU operators will be prohibited from insuring and financing the marine transportation of Russian oil to third countries.Until the sanctions enter into force, European, especially Greek, tanker owners are moving a lot of Russian oil to Asia, making a lot of money in the process. Shippers from Greece, China, and Turkey are eagerly taking advantage of the situation, according to data compiled by Bloomberg. By shipping Russian ESPO crude from Kozmino to the Chinese coast, a ship owner can make $1.6 million—three times what they would have made before the war in Ukraine. Earlier this month, Ukraine called out Greece for shipping Russian oil. “We see Greek companies providing almost the largest tanker fleet for the transportation of Russian oil,” Ukrainian President Volodymyr Zelensky said in a speech to a conference in Athens via video link. “Once again: this is happening precisely when another Russian energy resource is being used as a weapon against Europe and against the family budget of every European. I am sure that this does not meet the interests of Europe, Greece, or Ukraine,” Zelensky added. Greek vessel owners made 151 port calls from Baltic and Black Sea Russian ports between May 1 and June 27, up by 41% compared to the same period last year, according to data compiled by Lloyd’s List using Lloyd’s List Intelligence. Almost half of all crude and refined products exported from key Baltic or Black Sea ports were shipped on vessels Greek tanker owners beneficially own, the data showed. TMS Tankers of billionaire George Economou is the biggest Greek player in the Russian market and second overall, second only to Russia-owned Sovcomflot, which is under Western sanctions, according to the data. Greek tankers are also participating in ship-to-ship (STS) transfers offshore Greece, Malta, and south of Gibraltar, Lloyd’s List data showed. It’s difficult to predict what will happen to the global tanker market when the EU sanctions enter into force, but demand for oil remains high, so tankers will be used on other routes, a CEO at a Greek shipping firm told The Wall Street Journal.

Russia's crude deliveries to China and India have plunged 30% from their wartime peak as concerns mount that Asia can't fully absorb Moscow's shrinking oil market -- Russia's crude shipments to China and India have fallen nearly 30% since they peaked after the war in Ukraine began, a Bloomberg report found, signaling that Asia may not be equipped to fully absorb Russian barrels once European sanctions fully set in.So far, expensive crude prices have bolstered Russia's export-duty revenues and helped mitigate the influence of a shrinking market. Soaring oil prices have allowed the Kremlin to continue funding its war efforts even amid tightening sanctions. Since the war began, India went from importing nearly zero barrels a day of Russian crude to almost 1 million barrels a day last month, according to Vortexa data. China, too, has ramped up imports dramatically, nearly doubling Russian crude imports between February and June. But deliveries have slipped to roughly 30% below their highs, Bloomberg reported. According to Bloomberg data, Moscow is netting roughly $160 million a week in crude export duties, about 25% higher than in prewar months but down by about the same amount from April peaks.Since mid-June, Russia's seaborne crude flows have declined on a rolling four-week average of exports calculated by Bloomberg. Flows have slipped to 3.24 million barrels a day leading up to July 15, seeing a dip in each of the prior four weeks. While flows to Asia have accounted for over half of Russia's total crude flows since Vladimir Putin ordered the invasion of Ukraine, shipments to Asia hit their lowest four-week average in nearly four months in the lead-up to July 15.Still, for Moscow's oil income to take a hit, there would need to be a drop in global demand, which analysts say remains unlikely for some time.

China Gets Competition For Its Favorite Russian Oil From India - India has ramped up purchases of crude from Russia’s far east, a grade that’s typically favored by Chinese oil refiners. Four vessels hauling Russian ESPO oil are making their way to India, with two tankers heading for Paradip port on the east coast, where a refinery operated by Indian Oil Corp. is located, according to shipbrokers and data compiled by Bloomberg. That compares with three vessels in June and one in April, said Emma Li, an analyst at Vortexa in Singapore. State-owned Indian Oil didn’t immediately respond to a request for comment. The trade is typically not attractive to Indian buyers due to the long distance from the Russian loading port of Kozmino and because ESPO crude cargoes are usually transported in aframax vessels, which carry smaller volumes. However, the cheaper price compared with other grades from the Persian Gulf and West Africa are likely to have prompted the buying, according to traders. Cargoes of ESPO can be shipped to China in around five days, and the nation’s refiners have been eagerly snapping up the cheap Russian barrels, which have displaced flows from other suppliers such as West Africa and Brazil.

World's Oil Hot Spots May Shift as Industry Adopts Wind, Solar - The world’s oil map is being redrawn as the industry becomes increasingly intertwined with renewables, according to consultancy Wood Mackenzie Ltd. Oil majors that want to reduce their carbon footprint will have to shift their activities to energy basins where drilling rigs can be powered by renewables and which have ample space for carbon sequestration, said Andrew Latham, vice president at Wood Mackenzie, in a new report.

Brazil, Guyana, Mexico Projects To Offset Declines In Other Areas -In the coming years, upstream capex in Latin America will shift into deeper and deeper water with Brazil, Guyana, and Mexico likely to lead the charge for new spending, Rystad Energy said. While onshore investments stabilized at around $14 billion and shallow water spending continues to decline, deepwater expenditure is projected to grow at a compound annual growth rate (CAGR) of 15 percent from 2021 to 2025. Rystad estimates that deepwater investment in seismic, drilling, and facilities will exceed $25 billion by 2025, nearing 2013’s historical high of $28 billion driven by Brazil’s pre-salt fields. Three countries will lead upcoming growth – Brazil will retain its dominant position with Guyana growing on the back of recent discoveries and Mexico extending exploration from legacy shelf regions to deeper waters. Combined, anticipated mega projects in these three countries will help buoy the supply chain for drillships, floating production storage and offloading (FPSO) vessels, and subsea equipment following a steady decline since 2014 when activity peaked in the U.S. Gulf of Mexico, West Africa, and Australia. In 2022, deepwater capex is projected to exceed $72 billion globally. This represents substantial growth from last year when spending bottomed out at $58 billion, a level not since 2006 and not even half of 2014’s peak of $154 billion. Back then, long-cycle investment was seen as critical to meeting the energy needs of growing global populations with North America’s shale revolution in full swing, spurring the U.S. to become a swing producer as operators drilled for short-cycle returns in response to rising oil and gas prices. From 2015 to 2020, they effectively capped oil and gas prices until the recent investor backlash against growing production in North America. Now, operators appear to have lost their appetite for massive deepwater projects as their attention and capital shifts to more certain returns from onshore plays. Now, however, amid relative restraint from onshore operators in the U.S. and Canada, we see this trend abating led by offshore developments in Brazil, Guyana, and Mexico. The effects of this downturn in deepwater activity were felt across the oil and gas supply chain. After a massive build cycle in deepwater drillships associated with the previous growth in spending, the decline beginning in 2015 led to 267 rig years of canceled contracts and offshore drillers desperately trying to delay or cancel newbuild orders.

Russia distances itself from the US dollar further as it moves to trade oil with India using the UAE's local currency: report - Russia is looking to complete an oil deal with Indian refiners using the United Arab Emirates' local currency, rather than in dollars, according to a Reuters report. An invoice seen by Reuters revealed an Indian refiner was asked to pay for deliveries in dirhams, though the figure was first calculated in dollars. A payment in dirhams was made out to Gazprombank via Mashreq Bank, its corresponding bank in Dubai.At least two Indian refiners have already settled some transactions using dirhams, and there are more to come soon as trading firms used by Rosneft only just started asking for payments in dirhams this month, the report added. The moves signal Moscow is increasingly distancing itself from the US dollar as a way to minimize the impact of Western sanctions. Typically, the dollar is the primary international trade currency, especially for commodities like oil. This also affords the US political and financial leverage over other nations, as exhibited by recent sanctions imposed on Moscow. But Russia's looking to alternate currencies now.Earlier in March, Russia and India were in talks to revive a Cold-War era currency pact to evade sanctions too. A rupee-ruble ledger would allow the nations to do business without the use of US dollars. Additionally, in recent months trade volume between yuan and rubles have soared, hitting a six-month high in June, Bloomberg data shows. Spot trading between the two currencies hit $48 million in the interbank market last month.

UK steps up support to prevent major oil spill off the coast of Yemen – --Efforts to prevent a major oil spill in the Red Sea have been boosted by a further £2 million announced by the Minister for the Middle East Amanda Milling today. The FSO Safer tanker is moored off Yemen’s Red Sea coast and contains more than a million barrels of oil. The tanker is beyond repair, and it is feared that it could soon break apart or explode, destroying the environment around it and potentially exposing communities in Yemen to life-threatening toxins. The UN has been coordinating international efforts to prevent a disastrous oil spill from the tanker. The £2 million announced by the UK for the UN appeal today is in addition to £4 million pledged in May, making the UK one of the leading donors. At a meeting with counterparts from Oman, Saudi Arabia, the United Arab Emirates and the US today, Minister Milling called on the international community to step up its support. Minister for the Middle East and Asia Amanda Milling said: A major oil spill from the Safer oil tanker would create an ecological disaster in the Red Sea and exacerbate the dire humanitarian crisis in Yemen. The UK is stepping up our support to resolve this crisis. The UN are ready to implement an emergency operation but the international community must increase funding to allow them to get started. In May, the UK pledged £4 million pounds to the appeal as part of a UN conference to launch the emergency plan. Of the $80 million requested by the UN for Phase 1 of the operation, $60 million has been pledged so far. The UN’s plan involves a 4-month emergency salvage operation during which a ship-to-ship transfer will be conducted to remove the oil from the Safer onto a UN-leased vessel. The tanker will then be cleaned and eventually a replacement tanker will be installed. At almost 400 metres long, it is among the largest tankers in the world and holds roughly 4 times the crude oil that was spilled during the Exxon Valdez disaster in 1989.

Eroton Announces Successful Containment of Oil Spill in Rivers -- Eroton Exploration and Production Company Limited, has announced that it had successfully shut in CAWC015 Well amid efforts to contain CAWC047 wild well oil spill in Rivers State. Following the oil spill incident in Cawthorne Channel Well 15 (CAWC015L/S) which occurred on June 15, 2022, the indigenous oil producer has confirmed that the spill has been successfully contained and the well brought under control. The company in a statement also expressed delight “to confirm that CAWC-047 that was also vandalised within the same month and flowing to the environment since July 14 has just been controlled.” It added that efforts are ongoing to complete a spill clean-up of the wellhead slot, a proper securement, and the subsequent installation of subsurface downhole plugs. Eroton recalled that both spills were due to willful sabotage by unknown persons. In the statement issued by the company spokesperson, Mercy Max-Ebibai, it stated that the well engineering team and the well control vendor assiduously worked to establish control across all the flowing points on the vandalised wellhead. The statement affirmed that in the light of the sabotage, the team had to fabricate a platform on a work barge (as the well head platform had been initially totally cannibalised) before control valves could be installed and well shut-in was achieved. Max-Ebibai also stated that following the preliminary Joint Investigative Visit (JIV), the JIV with all relevant stakeholders, including NOSDRA, the Ministry of Environment and the community was held on July 15, 2022, with the intent to estimate spill volume and Post Spill Impact Assessment, confirming that the clean-up exercise will be wrapped up at the earliest possible time. However, she commended members of the affected community, stating that: “As excellent hosts, they provided all the necessary support in arresting the situation despite the hazards posed by the incident. We are happy that their seafaring and economic activities can return to normal in no time.” The statement noted that Eroton is one of Nigeria’s foremost indigenous Oil and Gas Companies. “It is the Operator of OML 18 Field on behalf of the NNPC/Eroton JV. OML 18 is situated in the Eastern Niger Delta and covers a total area of 1,035 SQKM in an onshore swamp terrain. Eroton has a clear vision for the future, which is evident from the six-fold increase in production since the asset was acquired in 2015. Eroton is based in Lagos and Rivers States,” it said.

CAWC015 Well oil spill successfully contained - Following the oil spill incident in Cawthorne Channel Well 15 (CAWC015L/S) which occurred on June 15 2022, the indigenous oil producer confirmed that the spill has been successfully contained and the well brought under control. The company also was please to confirm that CAWC-047 that was also vandalised within the same month and flowing to the environment since Sunday, 10th July has just been controlled today. Efforts are ongoing to complete a spill clean-up of the wellhead slot, a proper securement, and the subsequent installation of subsurface downhole plugs. Both spills were due to willful sabotage by unknown persons. In an update sent out to the press, company spokesperson, Mercy Max-Ebibai, stated that the Well engineering team and the Well Control vendor assiduously worked to establish control across all the flowing points on the vandalised wellhead. Affirming that in the light of the sabotage, the team had to fabricate a platform on a work barge (as the well head platform had been initially totally cannibalised) before control valves could be installed and well shut-in achieved. She also informed reporters that following the preliminary Joint Investigative Visit (JIV), a JIV with all relevant stakeholders, including NOSDRA, the Ministry of Environment and the community was held on the 15th of July 2022 with the intent to estimate spill volume and Post Spill Impact Assessment. Confirming that the clean-up exercise will be wrapped up at the earliest possible time. Finally, she commended members of the affected community, stating “As excellent hosts, they provided all the necessary support in arresting the situation despite the hazards posed by the incident.

Mangaluru: Sunken Princess Miral vessel still lying in sea, oil removal delayed - Nearly a month gone by after Princess Miral vessel of Syria sunk into the sea at Battappady of Ullal. In the present weather conditions, the oil that is held in the cargo section of the vessel, will not be emptied till the end of August. Two separate teams had arrived from Goa and Mumbai and did the spot inspection with regards to removal of oil and other matters pertaining to its salvage. The ship is stuck to the base of the sea but has not sunk completely. But as the deck is under water, expert operation is required to enter the vessel. Tugboat Waterlilly of water transport ministry is stationed at NMPT. The main aim of this is to prevent or restrict the oil spillage, in case if it happens. Coast guard and police are also keeping watch on the vessel. The crew of the ship are in the city itself as their repatriation process is not yet complete. Representatives of the ship owner are putting in all efforts in this regard and they are likely to be repatriated next week.

India’s diesel, gasoline sales taper off adding to oil’s gloom - India’s gasoline and diesel sales during the first half of July dropped from last month as seasonal rains curtailed demand in the world’s third-biggest energy consumer, that could help keep a lid on oil prices. The three biggest retailers sold 1.28 million tons of gasoline during July 1-15, down about 8% from the corresponding period in June, according to refinery officials with knowledge of the matter. Diesel sales fell almost 14% from last month, said the people, who asked not to be identified discussing unpublished data. The retracement in India’s fuel demand adds pressure on the price of oil amid rising pessimism about a global economic slowdown that dragged it below $100 a barrel for the first time since early April. The softening of demand could also add to a supply glut in the region that’s curtailing the profits from processing gasoline and diesel. This is the first monthly decline in sales in three months after resurgent economic activity, summer travel and increased use of diesel-fired generators during a severe heat-wave drove the South Asian nation’s fuel demand. Fuel consumption in India typically declines in this time of the year because of the monsoon rains that lasts till September. It hampers trucking and construction activities, weighing on demand for diesel, the country’s most-used petroleum fuel.

Oil import bill increased by 96% in 10MFY22 - Pakistan Today -The government imported oil worth $17.03 billion during the first 10 months (July-April) of the last fiscal year (10MFY22) to meet the country’s energy needs, an increase of almost 96% increase from the oil import bill compared to the same period of FY21. “Latest data indicates that the import bill of oil has increased by 95.9% to $17.03 billion during July-April FY22 compared to US$8.69 billion during the same period last year,” according to an official document. The surge in oil import bill has been attributed to increased import of petroleum products that went up by 121.2% in value and 24.2% in quantity. The document said the crude oil imports rose by 75.34% in value and 1.4% in quantity. Similarly, the Liquefied Natural Gas (LNG) witnessed an increase of 82.9% in value while the Liquefied Petroleum Gas (LPG) imports also jumped by 39.86% in quantity during the period under review. It may be mentioned here that around 75.64% of gas was domestically produced while 24.4% was imported during the period under review.

Oil output rises to 1.23mbpd, but less than OPEC quota - -- Crude output rose to an average 1.238 million barrels per day (mbpd) in Nigeria in June but less than the 1.766 mbpd allocated by the Organisation of Petroleum Exporting Countries (OPEC). OPEC Oil Market Report for July 2022 shows that Nigeria’s oil production increased by 5,000 bpd in June compared with 1.233 mbpd in May. The cartel has raised Nigeria’s quota to 1.799 mbpd in July. “According to secondary sources, averaged 28.72 mbpd in June 2022, higher by 234,000 barrels per day month-on-month. “Crude oil output increased mainly in Saudi Arabia, the United Arab Emirates, Iran, Kuwait and Angola, while production in Libya and Venezuela declined,’’ the report said. Despite the improvement in fossil fuel prices, it explained, the short-term economic outlook for Nigeria was affected by high inflation, which had reduced private sector optimism and weakened consumer spending. It noted that the composite Consumer Price Index (CPI) rose to 17.7 per cent in May from 16.8 per cent in April. “In response to the elevated inflationary pressures, the Central Bank of Nigeria [CBN] raised its policy rate by 150 basic points to 13 per cent bringing borrowing costs to the highest since April of 2020. - Advertisement - “It was the biggest rate hike since July of 2016 amid concerns that persistent inflationary pressures could weigh on the country’s fragile recovery.”

Oman’s crude oil production rises 9.7% to 190m barrels in H1 - Oman’s crude oil and condensate production reached 189.6 million barrels during the first half of 2022, recording a 9.7 percent growth over the same period last year, according to data released by the Ministry of Energy and Minerals. This comes as the Sultanate’s exports of liquefied natural gas climbed to around 5.9 million tons in the first six months of the year, registering an 8 percent increase over the same period in 2021, Oman News Agency reported. During the first three months of 2022, Oman’s LNG export was around 3 million, however, the figure declined a bit in the second quarter as it exported about 2.9 million tons. The oil prices continued to rise throughout June trading, reaching $112.9 per barrel as a consequence of global economic conditions and political escalations around the world, the ministry added.

Libya’s NOC to restart crude exports at four ports -- Libya's state-owned NOC said it is preparing to resume crude exports from four terminals over 19-21 July, ending weeks of blockades that have nearly halved the country's oil production. The company said it expects a tanker to load at Es Sider over 19-20 July, another is scheduled to pick up 1mn bl of Bu Attifel crude from the Zueitina terminal on 20 July, and two tankers are expected at Ras Lanuf on 20-21 July. Another vessel will collect 600,000 bl of Brega crude from the Marsa el-Brega terminal over this period. The latter port has already resumed loadings of condensate. The company did not disclose the names of the ships scheduled to load. Tracking data and a shipping source indicate the Crudemed and Caspian Sea are due to reach Ras Lanuf within the week. The tanker Matala has been fixed to arrive at Es Sider today and is flagging the terminal as its next destination. Restarting crude exports is a critical first step to increasing Libyan production. The country has very limited storage availability and its output is disrupted or has to stop completely when shipments cannot take place. The 90,000 b/d El Feel field, which has been under force majeure since 17 April, is now gradually resuming output, according to NOC subsidiary Mellitah Oil and Gas. It will initially produce at a rate of 40,000 b/d. El Feel, whose output is comingled with Wafa condensate to create the Mellitah crude blend, has in the past typically produced around 70,000 b/d, below its nameplate capacity. Libyan crude production dropped by 150,000 b/d to 600,000 b/d in June from the month before, Argus estimates, as a result of blockades at some terminals since the middle of April. NOC lifted force majeure restrictions from all oil terminals on 15 July.

Energy consultancy keeps lowering worldwide recoverable oil resources 0 It's hard to say that three years makes a trend. But one of the world's major energy consulting firms has lowered its estimate of world oil reserves for three years in a row now. Rystad Energy provides a publicly available analysis of world oil reserves each year. In 2020 Rystad wrotethat "the world’s recoverable oil [dropped] by around 282 billion barrels." That represented a 12.9 percent decline in just one year. In 2021 the firm stated its analysis showed that recoverable resources declined by another 178 billion barrels or about 9.4 percent. Rystad said the decline was due in part to new modelling based on resources "at well level rather than field level." The closer Rystad looked, the less oil there seemed to be.In 2022 Rystad noted yet another decline of almost 9 percent in its press release headline. Recoverable oil resources dropped another 152 billion barrels. (For all estimates Rystad uses figures for crude oil and lease condensate which is the accepted definition of oil.)With estimated recoverable resources standing at 1.572 trillion barrels, there is no seeming immediate threat to oil supplies. But the trend, should it continue, would be troublesome. There is a lot to look at "under the hood" of these estimates. Rystad reduces its broad 2022 estimate to an amount it believes could be produced profitably if oil is around $50, namely 1.2 trillion barrels. Price always matters when talking about recoverable resources. Higher prices, of course, make harder-to-get resources more likely to be profitable.Rystad notes the lowering of investment in oil exploration as one of the culprits. This drop has been driven by the uncertainties surrounding the pandemic and a world about to be ever more stringent regarding fossil fuel emissions.Companies and countries holding oil under their soil have long been known to exaggerate. Lack of independent audits among the world's government-owned oil companies should give us pause. Saudi Arabia, Iraq, Iran, United Arab Emirates and Kuwait all have national oil companies that control oil development within those countries. For a more comprehensive list, see here. Because of the lack of transparency into much of the world's oil resources, we are left taking the word of governments, many of whom are part of OPEC—and those OPEC members have an incentive to inflate their reserves in order to increase their OPEC production quotas because those quotas are based in part on the size of members' reserves. It's worth noting that OPEC countries claim to have 80 percent of recoverable world oil resources. (For a more detailed analysis of this issue, see my 2012 piece "Has OPEC misled us about the size of its oil reserves? Does it matter?" which is still almost entirely relevant.) Those of us who've been skeptical about recoverable oil reserve claims are not particularly surprised that estimates of worldwide reserves are falling. Another part of the story is that new discoveries meant to replace reserves produced each year are not nearly as great as consumption for many years running. Worldwide consumption has hovered between 27 and 30 billion barrels per year in the last decade. But new discoveries have been far behind with the highest year showing 12.9 billion barrels (2012) of discovery for data from 2011 through 2018. Rystand notes that discoveries were 12.2 billion barrels in 2019 and 10 billion barrels in 2020. But these numbers include turning natural gas discoveries into what their equivalent would be in terms of oil based on their energy content. Last year the industry discovered the lowest amount of oil and gas combined since 1946.

Who Really Controls The World's Oil Reserves? -Big Oil majors in the United States have found themselves the target of much pressure to boost production lately, as prices go wild amid a tight—and tightening—market. At the same time, the U.S. government, as well as the EU, have been looking all over the world for more supply. Wood Mackenzie just had some bad news for them. According to new research from the energy consultancy, more than half—65 percent, to be precise—of the world’s discovered oil and gas reserves are under the control of national oil companies. The reason this is bad news is that, in addition to NOCs like Saudi Aramco, QatarEnergy, and Abu Dhabi’s Adnoc, these companies also include Russia’s Rosneft and Gazprom, the National Iranian Oil Company, and Venezuela’s PDVSA. These seven companies, according to Wood Mac analysts, can keep producing oil and gas at their current rates for the next 40 to 60 years or even longer if they tap their spare capacity. It was national oil companies that have made 41 percent of all new oil and gas discoveries in conventional resources since 2011, the analysts noted. What’s more, the NOCs’ share in new discoveries has been on the increase since 2018 as the energy transition push prompts the evolution of their exploration strategies, the report said. In total, national oil companies have discovered more than 100 billion barrels of oil equivalent since 2011, the report said, which was twice what oil majors discovered. But not all is rosy for the NOCs. Unlike the majors, NOCs were significantly worse at commercializing these new discoveries, the Wood Mac analysts noted. Two-thirds of what Big Oil has discovered since 2011 is considered viable and advantaged. On the other hand, two-thirds of what the NOCs have discovered is considered contingent. This could, of course, change with the right incentive. Right now, however, it seems that the NOCs, especially in the Middle East, don’t have much of an incentive, especially as prices begin sliding under the weight of recession fears. The fact remains, however, that most of the already discovered oil and gas in the world, two-thirds of it, is under the control of just seven companies, of which four are subject to sanctions from some of the world’s biggest oil and gas consumers.

US believes OPEC can expand oil production, expects more steps soon - The United States believes that the OPEC countries have the opportunity to increase oil production and expects that they will take steps in this direction in the upcoming weeks, US Senior Adviser for Energy Security Amos Hochstein said on Sunday. Hochstein accompanied US President Joe Biden on his trip to the Middle East, which included a visit to Saudi Arabia and the participation in the summit of the Gulf Cooperation Council. "Based on what we heard on the trip I'm pretty confident that we will see a few more steps in the upcoming weeks," Hochstein said on "Face the Nation" CBS show.

Saudi Arabia Reveals Oil Production Capacity Limits -- Saudi Arabia, the world’s top crude oil exporter, will not have additional capacity to increase production above the 13 million barrels per day (bpd) it has pledged to have by 2027, Saudi Crown Prince Mohammed bin Salman told the leaders of the United States, the Gulf Cooperation Council (GCC) states, Jordan, Egypt, and Iraq at a summit this weekend.“We also stress the importance of continuing to inject and encourage investments in fossil energy and its clean technologies over the next two decades to meet the growing global demand, with the importance of assuring investors that the policies adopted do not pose a threat to their investments to avoid their reluctance to invest and to ensure that no shortage of energy supply would affect the international economy,” Crown Prince Mohammed bin Salman said in his address. “The Kingdom will do its part in this regard, as it announced an increase in its production capacity to 13 million barrels per day, after which the Kingdom will not have any additional capacity to increase production,” he added, as carried by the Saudi Press Agency.Last year, Saudi Arabia said it expects to have boosted its oil production capacityto 13 million bpd by 2027 from 12 million bpd now.Earlier this year, the Saudis confirmed this target, with Energy Minister, Prince Abdulaziz Bin Salman, telling TIME in an interview, “We are targeting our production capacity to become 13.4, 13.5 million barrels a day by 2027.” At the Jeddah summit, the Saudi crown prince also criticized the growing backlash against fossil fuels, saying that “The adoption of unrealistic policies to reduce emissions by excluding major sources of energy without taking into account the resulting impact of these policies on the social and economic pillars of sustainable development and global supply chains will lead in the coming years to unprecedented inflation, rise in energy prices, increase unemployment and exacerbate serious social and security problems, including an increase in poverty and famine and crime rates, extremism and terrorism.”

WTI Futures Top $100 as USD Slumps, No US-Saudi Oil Deal -- Oil futures nearest delivery on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange mostly moved higher in early trade Monday after Saudi officials indicated no additional production would come online following U.S. President Joe Biden's first visit to the Middle East, while weakness in the U.S. dollar triggered by a repricing of how aggressive Federal Reserve will raise interest rates at the next week's meeting further boosted the oil complex. "The decision to increase oil production is within OPEC+ and should follow the policies of keeping the markets balanced not a particular agreement." said Saudi State Minister of Foreign Affairs Adel Al-Jubeir on July 16 as U.S. President Biden wrapped up his trip to the Middle East without a pledge for higher crude supplies from the Gulf producers. U.S. officials have confirmed they do not expect Saudi Arabia to immediately boost output and await the outcome of OPEC+ meeting on Aug. 3, which will include Russia. Riyadh was clear it's sticking with the alliance. Furthermore, OPEC+ spare capacity remains low, according to the analysts, with most producers currently pumping at maximum rate. It is unclear how much extra Saudi Arabia could bring to the market and how quickly. In financial markets, the U.S. Dollar Index dropped more than 0.67% against the basket of foreign currencies to trade near 107.195, easing pressure on commodities traded in U.S. currency. Dollar weakness follows market's repricing of how aggressive Federal Reserve will move next week's on raising interest rates, with 67% of investors now expecting a 75-baisis-point hike compared with 33% still anticipating a 100-basis-point increase, according to CME's FedWatch Tool. Fed Governor Christopher Waller suggested last week that markets are overestimating the potential for a 1% increase in federal funds rates but added the central bank will be data-driven in making its rate decision. This sentiment was supported by Atlanta Federal Reserve President Raphael Bostic who said Friday that moving interest rates "too dramatically" could undermine the positive trends still seen in the economy and add to the already large amount of uncertainty. Near 7:30 a.m. EDT, West Texas Intermediate August contract rallied $1.93 to $99.54 barrel (bbl). International benchmark Brent for September delivery climbed above $103 bbl, up by more than $2 bbl in overnight trading. NYMEX August RBOB futures advanced 7.65 cents to $3.2897 gallon, while front-month ULSD added 2.27 cents to $3.7217 gallon.

Oil price up US$5 on weaker US$, tight supplies - Oil prices rose more than US$5 on Monday, boosted by dollar weakness and expectations that the U.S. Federal Reserve won't raise interest rates by a full percentage point at its next meeting to combat inflation. Brent crude futures for September settlement gained $5.11, or 5.1%, to settle at $106.27 a barrel, after rising 2.1% on Friday. U.S. West Texas Intermediate (WTI) crude futures for August delivery settled up $5.01, or 5.1%, at $102.60 after rising by 1.9% in the previous session. On Friday two U.S. Federal Reserve officials indicated the central bank would likely only raise interest rates by 75 basis points at its July 26-27 meeting. Previous reports that the Fed was considering a 100 basis point decision sent markets lower late last week. The U.S. dollar .DXY retreated from multi-year highs on Monday, supporting commodities prices. A weaker dollar makes dollar-denominated commodities more affordable for holders of other currencies. "Today’s strong advance resulted largely from a sizable and broad-based weakening in the U.S. dollar that has been providing a key driver behind daily oil price swings during the past several weeks," Both Brent and WTI last week registered their biggest weekly declines in about a month. Oil supplies remain tight. As expected, U.S. President Joe Biden's trip to Saudi Arabia did not yield any pledge from the top OPEC producer to boost oil supply. Biden wants Gulf oil producers to step up output to help to lower oil prices. Russian gas export monopoly Gazprom declared force majeure on gas supplies to Europe to at least one major customer, according to the letter seen by Reuters, potentially ratcheting up the conflict between Moscow and Europe. That added support to oil prices, as traders saw it potentially as a precursor to actions by Russia to use energy as a weapon. "The other clear risk...is that Russia will further slash energy supplies to Europe to try to raise the cost of supporting Ukraine and imposing sanctions,"

Oil Prices Slip On Recession Worries --Oil prices slipped on Tuesday after surging more than $5 a barrel in the previous session on concerns about tight supply. Benchmark Brent crude futures declined 0.6 percent to $105.60 a barrel, while WTI crude futures were down half a percent at $98.89. New COVID-19 cases in China jumped to almost 700 and data showed the euro zone's inflation accelerated as estimated in June to set a fresh record high, raising worries about a possible recession. Meanwhile, reports emerged that European Central Bank policymakers may consider a bigger-than-expected rate hike later in the week. The euro rallied after Reuters said policymakers will discuss whether to raise interest rates by 50 bps on Thursday to tame record-high inflation. Amid lingering concerns over gas supply from Russia, investors await U.S. crude supply data from the American Petroleum Institute later in the day for further direction.

WTI Lifted by Stocks Rally While USD Slides to 2-Week Low - West Texas Intermediate futures reversed higher in afternoon trade Tuesday helped by a sharp drop in the U.S. dollar index and rallying stock market as investors reassessed risks of a recession amid better-than-expected earnings reports from top U.S. companies and an improved macroeconomic outlook. Stocks on Wall Street staged a remarkable rebound on Tuesday, sending Dow Jones Industrials more than 700 points higher and the S&P 500 up 2.7% late afternoon on the back of better-than-expected earnings results for the second quarter. Oilfield services provider Halliburton rose 0.9% after its profit and revenue topped forecasts. Further spurring gains in financial markets, Reuters reported Russian energy giant Gazprom may indeed restart Nord Stream 1, a key natural gas pipeline to Europe, on Thursday (July 21) in line with a routine maintenance schedule. The pipeline, which accounts for one-third of Russian gas exports to the European Union, was halted for 10 days of annual maintenance on July 11. Speculation had swirled in recent days as to whether Russia would restart the pipeline after Gazprom declared force majeure on several European natural gas buyers citing "past and current shortfalls in gas deliveries," according to German utility Uniper. The European Commission said this morning that it did not expect the pipeline would be back online. The restart of the major gas pipeline would be welcomed news for the European Union as it battles a record-breaking heatwave that has gripped much of the continent in recent days, pushing its energy systems to the limit. German day-ahead power prices rose to 397 euros per megawatt-hour, the highest since March, while the French equivalent climbed to the highest since April at 521 euros. At settlement, West Texas Intermediate August contract advanced $1.62 to $104.22 bbl, with the next-month delivery WTI expanding its discount to $3.48 bbl. Brent crude futures for September delivery climbed above $107 bbl, up $1.08 bbl. NYMEX August RBOB futures advanced 4.32 cents to $3.3075 gallon, while front-month ULSD fell 2.87 cents to $3.6268 gallon.

WTI Leaks Lower After Crude, Gasoline Builds - Solid risk-on moves in stocks, a weaker dollar, and a disruption along the Keystone pipeline were enough - in thin liquidity - to send oil prices notably higher (WTI back above $100).“Right now liquidity is thin, people are away on holiday, there’s more machines than humans,” Amrita Sen, co-founder of consultant Energy Aspects Ltd., said in a Bloomberg Television interview.“We can continue to trade in this very technical band. But structurally this is a market defined by underinvestment.”Oil markets have been volatile in recent weeks as traders navigated concerns that a looming recession would hurt demand and the fallout from a stronger dollar against the signs of tight physical supplies.Signals of demand destruction are showing up in inventory data and all algo-eyes will be tonight's API print for a hint of what's to come tomorrow... API

• Crude +1.86mm
• Cushing +523k
• Gasoline +1.29mm
• Distillates -2.153mm

If API is confirmed during tomorrow's DOE data, then this would be three straight weeks of crude builds (and rising stocks at Cushing). Gasoline inventories also built for a second straight week... WTI hovered around $100.60 ahead of the API print and slipped very modestly lower on the builds...

Oil Prices Unmoved By Small Crude, Gasoline Build - The American Petroleum Institute (API) reported a build this week for crude oil of 1.860 million barrels, while analysts predicted a build of 333,000 barrels.The build comes as the Department of Energy released 5 million barrels from the Strategic Petroleum Reserves in Week Ending July 15, to 480.1 million barrels.U.S. crude inventories have shed some 61 million barrels since the start of 2021, with a 1.83 million barrel gain since the start of 2020, according to API data.In the week prior, the API reported a build in crude oil inventories of 4.762 million barrels after analysts had predicted a draw of 1.933 million barrels.WTI was trading up on Tuesday as fears of the tight market over take recession fears—at least for today. WTI was trading up 1.32% on the day at 2:09 p.m. ET in the runup to the release at $104 per barrel—a rise of roughly $8.50 on the week. Brent crude was trading up 1.02% on the day at $107.30—a nearly $8 rise on the week.U.S. crude oil production data for the week ending July 8 slipped by 100,000 bpd to 12 million bpd, according to the latest EIA data. The API also reported a build in gasoline inventories this week of 1.290 million barrels for the week ending July 15, compared to the previous week's 2.927-million-barrel build.Distillate stocks saw a draw of 2.153 million barrels for the week, compared to last week's 3.262-million-barrel increase.Cushing inventories rose by 523,000 barrels this week, on top of last week’s build of 298,000. Official EIA Cushing inventories for week ending July 8 was 21.646 million, up slightly from 21.330 in the prior week. At 5:05 pm, ET, WTI was trading up at $103.80 (+1.17%), with Brent trading up at $107.20 (+0.86%).

WTI Extends Losses After Large Gasoline Build Signals Demand Destruction - Oil prices have slipped lower overnight following API's reported builds for crude and gasoline and thanks to a slight headwind from a stronger dollar. Optimism about the return of gas flows from Russia tomorrow ease pressure on the potential 'transition' demand to oil also.“Right now liquidity is thin, people are away on holiday, there’s more machines than humans,” Amrita Sen, co-founder of consultant Energy Aspects Ltd., said in a Bloomberg Television interview. “We can continue to trade in this very technical band. But structurally this is a market defined by underinvestment.”All eyes are on the official data this morning for signs of demand destruction...“The market is hyper focused on demand metrics and recent US demand data has failed to inspire confidence,” said Rebecca Babin, a senior energy trader at CIBC Private Wealth Management. Today's official data will be closely watched for bulls to reengage with the market. DOE

• Crude -445k
• Cushing +1.143mm
• Gasoline +3.498mm
• Distillates -1.295mm

US Crude inventories unexpectedly drew-down last week (-445k) but gasoline stocks surged by 3.498mm barrels (the second straight week of increases)... There was a 5mm draw from SPR last week. Total nationwide oil inventories, including commercial stocks and oil held in the SPR, fell by 5.4 million barrels in the week to July 15. Last week’s implied gasoline demand data was jarring to say the least – the sheer volume of decline in the weekly figure, whether it proves to be an outlier or not, represents a stark shift around the demand destruction narrative. With a week-on-week decline of 1.35 million barrels a day, the plunge is the third largest on record dating back over thirty years, only bested by the first two weeks of Covid lockdowns in March 2020.

Oil slips on lackluster U.S. summer gasoline demand -- Oil prices slipped on Wednesday, after U.S. government data showed lower gasoline demand during the peak summer driving season and as interest rate hikes by central banks to fight inflation fed fears the economy could slow, cutting energy demand. However, prices pared losses during the session after TC Energy said that the Keystone pipeline, one of Canada's major oil export arteries, was operating at reduced rates for a third day on Wednesday. Repairs continued on a third-party power facility in South Dakota, prompting concerns about tighter supplies. Brent crude prices for September settled 43 cents lower at $106.92 per barrel. U.S. West Texas Intermediate (WTI) crude for August settled 1.88% lower at $102.26. The WTI contract expires on Wednesday. U.S. gasoline inventories rose 3.5 million barrels last week, government data showed, far exceeding analysts' forecasts in a Reuters poll for a 71,000-barrel rise. Product supplied of gasoline - a proxy for demand - was about 8.5 million barrels per day, or about 7.6% lower than the same time a year ago, the data showed. "Gasoline demand is subpar to say the least," said John Kilduff, partner at Again Capital LLC in New York. "Certainly these high gas prices have undermined consumer confidence." Americans were shocked in June as pump prices climbed to a record of over $5 per gallon. Meanwhile, U.S. crude inventories fell by 446,000 barrels last week, data showed, compared with analysts' expectations for a 1.4 million-barrel rise. Oil prices have been extremely volatile, caught in a tug-of-war between supply fears caused by Western sanctions on Russia and worries that the fight against inflation could weaken the global economy and cut demand. On Friday, open interest in New York Mercantile Exchange futures fell to its lowest since September 2015 as concerns that the Federal Reserve will keep raising U.S. interest rates led investors to cut exposure to risky assets. Analysts expect oil supply tightness to keep supporting prices while U.S. shale oil production expands at a modest pace. "With little room for OPEC+ to increase production, the oil market will struggle to balance out in the coming months, thereby propping up prices," said Stephen Brennock of oil broker PVM. Limited supplies have kept Brent above $105 a barrel and prompt Brent inter-month spreads in wide backwardation at over $4.40 a barrel. In a backwardated market, front-month prices are higher than those in future months.

Oil prices fall amid demand concerns --Crude oil prices declined on Thursday due to demand concerns in the US. Around 1130 am, the September contract of Brent on the Intercontinental Exchange was at $106.30 per barrel, down 0.58% from previous close. The September contract of West Texas Intermediate (WTI) fell 1.88% to $102.26 per barrel on NYMEX. According to data, supply of gasoline in the US was about 8.5 million barrels per day last week, around 7.6% lower on year, indicating a fall in demand. Further, rise in gasoline inventory also weighed on prices. Last week, US gasoline stockpiles rose 3.5 million barrels. Ravindra Rao, head of commodity research at Kotak Securities, said, “Crude trades lower weighed down by mixed inventory report which noted an unexpected decline in US crude oil stocks but also a sharp rise in gasoline stocks reflecting weaker demand despite ongoing summer driving season." “Also weighing on crude are demand concerns amid disappointing US economic data and persisting virus risks in China. Supply concerns have, however, kept prices supported. Crude rallied sharply in last few days however with mixed inventory report, demand concerns and shaky risk sentiment, we expect to see some correction," he said. The fall in crude prices comes as a relief for India as the country imports 85% of its energy requirements. Given the fall in global prices, the central government on Wednesday reduced windfall tax on crude oil imposed at the beginning of this month by about 27% to ₹17,000 a tonne. It also withdrew an export tax on petrol and lowered the same on diesel and jet fuel. Domestic retail fuel prices have largely remained unchanged for about two months now. In the national capital, petrol is sold for ₹96.72 and diesel is priced at ₹89.62 per litre.

Oil slumps $3/bbl on gasoline stockpiles, rate hikes and resuming supply -Oil prices fell more than $3 a barrel on Thursday on higher U.S. gasoline stockpiles and after a European Central Bank (ECB) rate hike stoked demand worries, while returning oil supply from Libya and the resumption of Russia’s gas flows to Europe eased supply restraints. Brent crude futures settled at $103.86 a barrel, falling $3.06, or 2.9%. U.S. West Texas Intermediate crude settled at $96.35 a barrel, declining $3.53, or 3.5%. Both were down more than $5 earlier in the session. U.S. gasoline futures settled at $3.15, losing 13 cents, or 3.8% following a jump of 3.5 million barrels of the commodity in storage last week, U.S. government data showed on Wednesday, far exceeding analyst forecasts. [EIA/S] “If you don’t need the gasoline, then you don’t need the crude oil to make the gasoline, and that’s the math that’s killing crude oil right now,” said Robert Yawger, executive director of energy futures at Mizuho. Oil futures trading volumes have also been thin and prices volatile as traders attempt to square weaker energy demand with tighter supply resulting from the loss of Russian barrels after the country’s invasion of Ukraine. Flows through Russia’s Nord Stream 1 natural gas pipeline, which runs under the Baltic Sea to Germany, partially resumed after being shut for maintenance on July 11. The pipeline had already run on reduced volumes following a dispute sparked by Russia’s invasion of Ukraine. “The resumption of Nord Stream gas flows appears to be conjuring up images of a more conciliatory posture on the part of Russia regarding continued movement of crude and products into Europe in the coming weeks/month,” said Jim Ritterbusch of Ritterbusch and Associates in a note. The European Central Bank on Thursday joined many other central banks in raising interest rates, focusing on fighting runaway inflation rather than the economic downturn, which can weigh on oil demand. The Bank of Japan maintained ultra-low interest rates to stimulate stalling economic growth. On Wednesday, Libya’s National Oil Corp (NOC) said crude production had resumed at several oilfields after the lifting of force majeure on oil exports last week. The reduced flow on one of Canada’s major oil export arteries, the Keystone pipeline, should only have a slight impact on oil deliveries, analysts said.

WTI Slides Below $95 on Growth Concerns, Libyan Supplies -Oil futures eroded further in early morning trade Friday, with all petroleum contracts on course for hefty losses this week after overnight data out of Europe showed manufacturing activity unexpectedly contracted in July, heightening concerns about recession in the bloc, while the return of Libya's oil exports to the global market further weighed on the complex. The Eurozone Manufacturing purchasing managers index fell to a 25-month low 49.6 in July compared with expectations for a 51.0 showing. Concerns over weakening demand were exacerbated by energy, supply and inflation worries to push business expectations lower, and also cause a pullback in new hiring. The bloc's Services PMI also dropped sharply to 50.6 in July from 53.0 in the previous month. The indicator reached a 15-months low. "The eurozone economy looks set to contract in the third quarter as business activity slipped into decline in July and forward-looking indicators hint at worse to come in the months ahead," S&P Global Chief Business Economist Chris Williamson, commented on the data release. Excluding pandemic lockdown months, July's contraction is the first signal by the PMI since June 2013, indicative of the economy contracting at a 0.1% quarterly rate. Although only modest at present, a steep loss of new orders, falling backlogs of work and gloomier business expectations all point to the rate of decline gathering further momentum as the summer progresses. On Thursday, the European Central Bank surprised the markets with a larger-than-expected rate hike of 50 basis points, with the rate hike the first in 11 years. Inflation in the EU climbed to a record-high 8.6% in June, up from 8.1% in the previous month, dashing hopes for a retreat in high consumer prices. This comes against a backdrop of slowing growth, the war in Ukraine and threats to energy supplies. Compounding the bearish development, Libya is restoring oil production, with output rising above 700,000 barrels per day (bpd) after restrictions on exports were lifted. Output is expected to return to 1.2 million bpd within a week to 10 days, according to government officials. The premium of the nearest crude futures contract over the next month eased, indicating cooling concerns about market scarcity. Near 7:15 a.m. EDT, NYMEX September West Texas Intermediate futures declined $1.58 to $94.75 barrel (bbl), while the front-month Brent contract fell $1.52 to $102.34 bbl. NYMEX RBOB August futures slumped 5.32 cents to $3.0963 gallon and ULSD futures fell 3.69 cents to $3.5534 gallon.

U.S. Crude Ends Below $95/bbl as EU Tweaks Russian Oil Sanctions (Reuters) -U.S. crude prices settled below $95 a barrel for the first time since April in choppy trading on Friday after the European Union said it would allow Russian state-owned companies to ship oil to third countries under an adjustment of sanctions agreed by member states this week. U.S. West Texas Intermediate crude (WTI) settled $1.65, or 1.7%, lower at $94.70 a barrel, while Brent crude futures fell 66 cents, or 0.6%, to $103.20. WTI closed lower for the third straight week, pummelled over the past two sessions after data showed that U.S. gasoline demand had dropped nearly 8% from a year earlier in the midst of the peak summer driving season, hit by record prices at the pump. In contrast, signs of strong demand in Asia propped up the Brent benchmark, which settled higher for the first time in six weeks. Trading in oil futures has been volatile in recent weeks as traders try to reconcile possibilities of further interest rate hikes that could cut demand against tight supply from the loss of Russian barrels. Russian state-owned companies Rosneft and Gazprom will be able to ship oil to third countries in a bid to limit the risks to global energy security. Under tweaks to sanctions on Russia that came into force on Friday payments related to purchases of Russian seaborne crude oil by EU companies would not be banned. The EU announcement comes after Russian Central Bank Governor Elvira Nabiullina said it will not supply crude to countries that decide to impose a price cap on its oil and instead redirect it to countries which are ready to "cooperate" with Russia. "Perceptions are growing that the U.S. and EU will implement price caps on Russian oil by year end," "Past history shows that government-induced price caps on commodities are usually short lived and can result in exaggerated prices soon after," he added. Prices, however, were held back by worries of interest rate hikes that could slash demand and the resumption of some Libyan crude oil output. Libya's oil production is at more than 800,000 barrels per day (bpd) and will reach 1.2 million bpd by next month, the Libyan oil ministry said. Iraq has the capacity to increase its oil production by 200,000 bpd this year if asked, an executive of Iraq's Basra Oil Co said. U.S. oil rigs, an early indicator of future output, remained steady at 599 this week, according to data from energy services firm Baker Hughes. The global economy looks increasingly likely to be heading into a serious slowdown, just as central banks aggressively reverse ultra-loose monetary policy adopted during the pandemic to support growth, data showed on Friday. Recent moves in crude oil and interest rate futures anticipate a downturn in the business cycle that will cause oil consumption to dip before the end of the end of the year and into the first three months of 2023. Investors were also watching for the U.S. Federal Reserve decision on interest rates next week. Fed officials have indicated that the central bank would likely raise rates by 75 basis points at its July 26-27 meeting. Still, demand in India has remained strong, with refining holding above pre-pandemic levels, while China is also set to make great efforts to consolidate its economic recovery particularly in the third quarter, state media reported. Money managers raised their net long U.S. crude and Brent futures and options positions in the week to July 19, the U.S. Commodity Futures Trading Commission (CFTC) and Intercontinental Exchange showed.