Sunday, November 27, 2022

US oil supplies at a 21½ year low; highest November ​refinery ​utilization since 2004; DUCs rose first time in 28 months

US oil supplies at a 21½ year low, Strategic Petroleum Reserve at a 38½ year low; highest November ​refinery ​utilization rate since 2004; biggest jump in oil imports since February 2021; DUCs rose first time in 28 months​ 

US oil prices finished lower for the 3rd straight week this week as the Covid outbreak in China worsened and the G7 and EU failed to agree on a price cap for Russian exports.....after falling 10.0% to $80.08 a barrel last week as Covid cases in Beijing rose to record highs and the Fed signaled interest rates could go much higher, the contract price for the benchmark US light sweet crude for December delivery fell to near two-month lows in Asian markets on Monday, as supply fears receded while concerns over fuel demand from China and U.S. dollar strength weighed on prices, and then fell more than $5 to their lowest price level since early January after the Wall Street Journal reported an output increase of up to 500,000 barrels per day would be considered at the OPEC+ meeting on Dec. 4th, but reversed most of those losses after Saudi Energy Minister Abdulaziz bin Salman denied that the 23-nation oil producing alliance under his charge was working on any production hike for that meeting, and settled 35 cents lower at $79.73 a barrel as trading in the December oil contract expired, while the more active contract for US light sweet crude for January was down just 7 cents at $80.04 a barrel....with the January oil price now being quoted, oil prices rose in Asia on Tuesday after the Saudis reaffirmed that OPEC+ was sticking with output cuts and could take further steps to balance the market, outweighing global recession worries and concern about China’s rising COVID-19 case numbers. and settled 91 cents higher at $80.95 a barrel as traders awaited an expected announcement of a G7 price cap on Russian oil shipments that could potentially disrupt oil flows from Russian ports...oil prices edged higher in Asian trading on Wednesday after data from the American Petroleum Institute showed US crude stockpiles had dropped more sharply than expected last week, highlighting supply tightness ahead of a looming European Union ban and G7 price cap on Russian oil. but then fell more than 2% in early New York trading on indications that the European Union and G7 nations were softening the language dictating the looming price cap regulations on Russian oil exports in an apparent effort to cause minimal disruption to Russian oil trade this winter. and then extended those losses after the EIA reported big product inventory builds to finish the session $3.01 or 3.7% lower at $77.94 a barrel, as the G7 nations considered a price cap on Russian oil above the current market level and as gasoline inventories in the United States rose by more than analysts had expected...while US markets were closed for the Thanksgiving holiday, US oil contracts fell in Asian markets Thursday following indications that G7 nations were considering a price cap on Russian crude in the range of $65-70 per barrel, but settled 3 cents higher in Europe as EU diplomats remained locked in negotiations over how strict the Russian mechanism should be...oil prices rose in Asia on Friday as traders were encouraged by the declining US dollar, which makes dollar-indexed oil cheaper for them, while the worsening COVID epidemic in China dampened further price upticks, but turned lower in a thinly traded US session after China reported a new daily record for Covid-19 infections, and settled $1.66 or 2.1% lower at $76.28 a barrel as the European Union suspended talks over a Russian oil price cap amid disagreements between member states...oil price quotes thus finished 4.7% lower for the week, while the benchmark contract for US light sweet crude for January delivery finished the week 4.8% lower...

on the other hand, natural gas prices finished higher for the fourth time in five weeks, on colder forecasts and concerns about a possible rail strike... after rising 7.2% to at $6.303 per mmBTU last week on colder forecasts and an end to the storage injection season, the contract price of US natural gas for December delivery opened 14 cents higher at $6.443 per mmBTU on Monday as updated forecasts over the weekend called for a cold start to December and surged to settle 47.3 cents higher at $6.776 per mmBTU as traders mulled an updated restart timeline for the Freeport export facility, railroad union members considered a strike, and forecasts pointed to another round of wintry weather in early December...natural gas futures pared their gains in early trading Tuesday as updated forecasts showed less cold reaching the eastern Lower 48 in early December but recovered to end three-tenths of a cent higher at $6.779 per mmBTU, as worries about a possible rail strike offset the revised forecasts and as Gazprom warned it would reduce gas supplies to a Ukraine interconnection if they weren't reaching Moldova....natural gas prices jumped about 11% to a two-month high in early trading on Wednesday on festering worries about a railroad strike and revised forecasts for blasts of cold in the month ahead, but pulled back a bit to settle 52.9 cents or 7.8% higher at $7.308 per mmBTU after the EIA report showed last week's storage draw was slightly smaller than expected... however, natural gas prices fell 28.4 cents, or 3.9%, to settle at $7.024 per mmBTU on Friday on forecasts that the cold blast might not be as far reaching as originally feared, but still finished 11.4% higher on the week, while the contract for US natural gas for January delivery, which will be the front month contract next week, finished 9.1% higher at $7.330 per mmBTU...

The EIA's natural gas storage report for the week ending November 18th indicated that the amount of working natural gas held in underground storage in the US fell by 80 billion cubic feet to 3,564 billion cubic feet by the end of the week, which meant our gas supplies were 62 billion cubic feet, or 1.7% less than the 3,626 billion cubic feet that were in storage on November 18th of last year, and 39 billion cubic feet, or 1.1% below the five-year average of 3,603 billion cubic feet of natural gas that were in storage as of the 18th of November over the most recent five years....the 80 billion cubic foot injection into US natural gas working storage for the cited week was less than the average forecast for an 87 billion cubic feet withdrawal from storage by a Reuters poll of analysts, but it was much more than the 14 billion cubic feet that were pulled from natural gas storage during the corresponding week of 2021, and also more than the average 48 billion cubic feet of natural gas that have typically been withdrawn from 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 November 18th indicated that even after the biggest jump in our oil imports in a year and a half, we needed to pull oil out of our stored commercial crude supplies for the 9th time in 15 weeks, and for the 17th time in the past 31 weeks, mostly because of comparably modest increases in our oil exports and our refinery throughput....Our imports of crude oil rose by an average of 1,504,000 barrels per day to average 7,063,000 barrels per day, after falling by an average of 895,000 barrels per day during the prior week, while our exports of crude oil rose by 380,000 barrels per day to average 4,242,000 barrels per day, which together meant that the net of our trade in oil worked out to an import average of 2,821,000 barrels of oil per day during the week ending November 18th, 1,124,000 more 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 unchanged at 12,100,000 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 averaged a total of 14,921,000 barrels per day during the November 18th reporting week…

Meanwhile, US oil refineries reported they were processing an average of 16,410,000 barrels of crude per day during the week ending November 18th, an average of 258,000 more barrels per day than the amount of oil that our refineries processed during the prior week, while over the same period the EIA’s surveys indicated that a net average of 756,000 barrels of oil per day were being pulled out of the various 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 November 18th appear to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 733,000 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 (+733,000) 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 756​,000 barrel per day decrease in our overall crude oil inventories left our oil supplies at 822,183,000 barrels at the end of the week, which was our lowest total oil inventory level since March 16th, 2001, and therefore at a new 21 1/2 year low...Our oil inventories decreased this week as an average of 527,000 barrels per day were being pulled out of our commercially available stocks of crude oil, while 229,000 barrels per day of oil were being pulled out of our Strategic Petroleum Reserve. That draw on the SPR, (the smallest draw since February), was an extension of the emergency withdrawal under Biden's "Plan to Respond to Putin’s Price Hike at the Pump" (sic), that was originally intended to supply 1,000,000 barrels of oil per day to commercial interests over a six month period from its inception to the midterm elections in November, in the hope of keeping gasoline and diesel fuel prices from rising over that time....The SPR withdrawals under that program have been fluctuating in recent weeks because the administration has since been attempting to use the Strategic Petroleum Reserve to manipulate prices on a weekly basis; furthermore, Biden recently announced another 15,000,000 barrel release from the Strategic Petroleum Reserve to run thru December, while simultaneously announcing he'd buy crude to replenish the SPR if oil prices fall to or below the $67-72 a barrel range, effectively putting a floor under oil at that price.....Including the administration's initial 50,000,000 million barrel SPR release earlier this year, their subsequent 30,000,000 barrel release, and other withdrawals from the Strategic Petroleum Reserve under recent release programs, a total of 265,629,000 barrels of oil have now been removed from the Strategic Petroleum Reserve over the past 28 months, and as a result the 390,518,000 barrels of oil that still remain in our Strategic Petroleum Reserve is now the lowest since March 23, 1984, or at a new 38 1/2 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. The total 180,000,000 barrel drawdown of the current release program, now scheduled to run through December, 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 the current 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 6,327,000 barrels per day last week, which was 3.4% more than the 6,116,000 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 unchanged at 12,100,000 barrels per day because the EIA's rounded estimate of the output from wells in the lower 48 states was unchanged at 11,700,000 barrels per day, while Alaska’s oil production was 1,000 barrels per day lower at 448,000 barrels per day but had no impact on the 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 still 7.6% below that of our pre-pandemic production peak, but was 24.7% 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 93.9% of their capacity while using those 16,410,000 barrels of crude per day during the week ending November 18th, up from their 92.9% utilization rate during the prior week, and the highest November utilization rate since 2004.. The 16,410,000 barrels per day of oil that were refined this week were 4.9% more than the 15,640,000 barrels of crude that were being processed daily during week ending November 19th of 2021, and 0.5% more than the 16,334,000 barrels that were being refined during the prepandemic week ending November 22nd, 2019, when our refinery utilization was at 89.3%, within the normal utilization range for mid November...

Even with the increase in the amount of oil being refined this week, the gasoline output from our refineries was quite a bit lower, decreasing by 625,000 barrels per day to 9,164,000 barrels per day during the week ending November 18th, after our gasoline output had increased by 35,000 barrels per day during the prior week.This week’s gasoline production was also 9.2% less than the 10,099,000 barrels of gasoline that were being produced daily over the same week of last year, and 9.0% below the gasoline production of 10,065,000 barrels per day during the ​prepandemic ​week ending November 22nd, 2019. ON the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 14,000 barrels per day to 5,097,000 barrels per day, after our distillates output had decreased by 107,000 barrels per day during the prior week. ​And with that increase, our distillates output was 6.8% more than the 4,784,000 barrels of distillates that were being produced daily during the week ending November 19th of 2021, and 0.7% more than the 5,075,000 barrels of distillates that were being produced daily during the week ending November 22nd 2019...

Even with the decrease in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the 5th time in 15 weeks; and by the most since mid-July, increasing by 3,058,000 barrels to 210,998,000 barrels during the week ending November 18th, after our gasoline inventories had increased by 2,207,000 barrels during the prior week. Our gasoline supplies rose by more this week because the amount of gasoline supplied to US users fell by 415,000 barrels per day to 8,327000 barrels per day, and because our imports of gasoline rose by 13,000 barrels per day to 585,000 barrels per day, and because our exports of gasoline fell by 29,000 barrels per day to 898,000 barrels per day. But after 31 gasoline inventory drawdowns over the past 42 weeks, our gasoline supplies were ​still ​0.2% lower than last November 19th's gasoline inventories of 211,393,000 barrels, and about4% below the five year average of our gasoline supplies for this time of the year…

With the increase in our distillates production, our supplies of distillate fuels increased for the 11th time in 16 weeks and for the 25th time in the past year, rising by 1,718,000 barrels to 109,101,000 barrels during the week ending November 18th, after our distillates supplies had increased by 1,120,000 barrels during the prior week. Our distillates supplies rose by more this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, decreased by 17,000 barrels per day to 3,846,000 barrels per day, and because our exports of distillates fell by 41,000 barrels per day to 1,142,000 barrels per day, and because our imports of distillates rose by 13,000 barrels per day to 123,000 barrels per day.. But after fifty-two mostly larger inventory withdrawals over the past eighty-two weeks, our distillate supplies at the end of the week were were still 10.4% below the 121,717,000 barrels of distillates that we had in storage on November 12th of 2021, and about 13% below the five year average of distillates inventories for this time of the year...

Meanwhile, even after the big increase in our oil imports, our commercial supplies of crude oil in storage fell for the 11th time in 19 weeks and for the 32nd time in the past year, decreasing by 3,690,000 barrels over the week, from 435,355,000 barrels on November 11th to 431,665,000 barrels on November 18th, after our commercial crude supplies had decreased by 5,400,000 barrels over the prior week. After this week's decrease, our commercial crude oil inventories fell to around 5% below the most recent five-year average of crude oil supplies for this time of year, but were still 26​.7​% more than the average of our crude oil stocks as of the third weekend of November 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. And after our commercial crude oil inventories had jumped to record highs during the Covid lockdowns of the Spring of 2020, and then jumped again after February 2021's winter storm Uri froze off US Gulf Coast refining, our commercial crude supplies as of this November 11th were 0.5% less  than the 434,020,000 barrels of oil we had in commercial storage on November 19th of 2021, and 11.7% less than the 488,721,000 barrels of oil that we had in storage on November 20th of 2020, and 4.5% less than the 451,952,000 barrels of oil we had in commercial storage on November 22nd of 2019…

Finally, with our inventories of crude oil and our supplies of all products made from oil near multi-year lows over the most recent months, we are also continuing to watch the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR.  Mostly because of the gasoline and distillates inventory increases we've already noted for this week, 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, rose by 1,740,000 barrels this week, from 1,608,865,000 barrels on November 11th to 1,610,605,000 barrels on November 18th, after our total inventories had decreased by 10,640,000 barrels during the prior week. This week's increase still left our total liquids inventories down by 177,828,000 barrels over the first 46 weeks of this year, and just 0.1% from a new 18 year low...  

This Week's Rig Count

The number of drilling rigs active in the US increased for the 10th time in the past 17 weeks with this week's report, which only covers the five days ending Wednesday, November 23rd, due to the Thanksgiving holiday....But even after 91 weekly increases over the past 113 weeks, active rigs are still 1.1% below the prepandemic rig count....Baker Hughes reported that the total count of rotary rigs drilling in the US increased by 2 rigs to 784 rigs over those five days, which was also 215 more rigs than the 569 rigs that were in use as of the November 24th report of 2021, but was 1,145 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 increased by 4 to 627 oil rigs during the past week, after the number of rigs targeting oil had increased by 1 during the prior week, and there are now 160 more oil rigs active now than were running a year ago, even as they amount to just 39.0% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014, and as they are still down 8.2% from the prepandemic oil rig count….at the same time, the number of drilling rigs targeting natural gas bearing formations decreased by 2 to 155 natural gas rigs, which was still up by 53 natural gas rigs from the 102 natural gas rigs that were drilling during the same week a year ago, even as they were only 9.7% of the modern high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….

Other than those rigs targeting oil and natural gas, Baker Hughes also reports that two "miscellaneous" rigs continued drilling this week: one of those was a directional rig drilling to between 5,000 and 10,000 feet on the big island of Hawaii, while the other was a directional rig drilling to between 5,000 and 10,000 feet into a formation in Lake county California that Baker Hughes doesn't track....While we have​n't seen any details on either of those, in the past we've identified various "miscellaneous" rigs as being exploratory, for carbon dioxide storage, and for utility scale geothermal projects...a year ago, there were were also two such "miscellaneous" rigs running...

The offshore rig count in the Gulf of Mexico was unchanged at 16 rigs this week, with 14 Gulf rigs drilling for oil in Louisiana's offshore waters, and two rigs drilling for oil offshore from Texas....the Gulf rig count is still up by 1 from the 15 Gulf rigs running a year ago, when 13 of the Gulf rigs were drilling for oil offshore from Louisiana and two were deployed for oil offshore from Texas...​and ​in addition to rigs drilling in the Gulf, we still have an offshore directional rig drilling to between 5,000 and 10,000 feet for natural gas in the Cook Inlet of Alaska, while a year ago, drilling offshore from Alaska had already shut down for the winter...

In addition to rigs running offshore, there are still three water based rigs drilling through inland bodies of water this week; those include a directional rig drilling for oil to between 10,000 and 15,000 feet, inland in St Mary Parish, Louisiana, a directional rig drilling for oil at a depth greater than 15,000 feet in Terrebonne Parish, Louisiana; and a directional rig drilling for oil to between 5,000 and 10,000 feet, inland in Lafourche Parish, Louisiana.....a year ago, there were two such rigs drilling on inland waters...

The count of active horizontal drilling rigs was unchanged at 714 horizontal rigs this week, which was still 201 more rigs than the 513 horizontal rigs that were in use in the US on November 24th of last year, but just 52.0% of the record 1,374 horizontal rigs that were drilling on November 21st of 2014....​in addition, the vertical rig count was also unchanged at 23 vertical rigs this week, which was still up by one from the 22 vertical rigs that were operating during the same week a year ago…on the other hand, the directional rig count was up by two to 47 directional rigs this week, and those were alsoup by 13 from the 34 directional rigs that were in use on November 24th 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 November 23rd, the second column shows the change in the number of working rigs between last week’s count (November 18th) and this week’s (November 23rd) count, the third column shows last week’s November 18th 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 24th of November, 2021...

checking the Rigs by State file at Baker Hughes for the changes in the Texas Permian, we find that there was just one oil rig added in Texas Oil District 7B, which includes two counties overlying the far eastern Permian Midland, while rigs in other districts in the Texas Permian were unchanged...since the national Permian basin count was up by three, we can thus conclude that both rigs added in New Mexico were set up to drill in the far western Permian Delaware, in the southwest corner of that state...elsewhere in Texas, there were three rigs pulled out of Texas Oil District 6, which appears to account for two natural gas rig removals from the Haynesville shale, since there was concurrently a Haynesville shale addition in northwestern Louisiana, and the removal of another rig targeting a basin that Baker Hughes doesn't track....there was also a rig pulled out of Texas Oil District 9, which would account for the oil rig removed from the Barnett Oklahoma, there was an oil rig addition in the Cana Woodford and an oil rig removal from the Arkoma Woodford, and since the state count is up by one, apparently the addition of a rig in a basin not tracked by Baker Hughes....likewise, the rig added in California was also in a basin not tracked by Baker Hughes..

DUC well report for October

Monday of last week saw the release of the EIA's Drilling Productivity Report for November, which included the EIA's October data on drilled but uncompleted (DUC) oil and gas wells in the 7 most productive shale regions (click tab 3)....that data showed a​n​ increase in uncompleted wells nationally for the first time in 28 months, as both completions of drilled wells and drilling of new wells increased in October, but remained well below average pre-pandemic levels...for the 7 sedimentary regions covered by this report, the total count of DUC wells increased by 8 wells, rising from a revised 4,400 DUC wells in September to 4,408 DUC wells in October, which was still 17.3% fewer DUCs than the 5,333 wells that had been drilled but remained uncompleted as of the end of October of a year ago...this month's DUC increase occurred as 984 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during October, up by 27 from the revised 957 wells that were drilled in September, while 976 wells were completed and brought into production by fracking them, up by 7 from the 969 well completions seen in September, and up by 49 from the 927 completions seen in October of last the October completion rate, the 4,408 drilled but uncompleted wells remaining at the end of the month represents a 4.5 month backlog of wells that have been drilled but are not yet fracked, matching the 4.5 month DUC well backlog of a month ago, and just above the 7 1/2 year low of 4.4 months, despite a completion rate that is still almost 15% below 2019's pre-pandemic average...

DUCs in the oil producing regions netted out to unchanged during October, while natural gas DUCs rose, since a DUC well decrease in natural gas producing Appalachian basins was more than offset by a ​bigger ​DUC well increase in Haynesville shale....the number of uncompleted wells remaining in the Permian basin of west Texas and New Mexico decreased by 13, from 1,097 DUC wells at the end of September to 1,084 DUCs at the end of October, as 421 new wells were drilled into the Permian basin during October, while 434 already drilled wells in the region were being addition, the number of uncompleted wells remaining in Oklahoma's Anadarko basin decreased by 5, falling from 723 at the end of September to 718 DUC wells at the end of October, as 68 wells were drilled into the Anadarko basin during October, while 73 Anadarko wells were the same time, DUCs in the Eagle Ford shale of south Texas decreased by 3, from 582 DUC wells at the end of September to 579 DUCs at the end of October, as 109 wells were drilled in the Eagle Ford during October, while 112 already drilled Eagle Ford wells were fracked....meanwhile, DUC wells in the Bakken of North Dakota remained unchanged at 494 at the end of October, as 77 wells were drilled into the Bakken during September, while 77 of the drilled wells in the Bakken were being fracked....on the other hand, DUC wells in the Niobrara chalk of the Rockies' front range increased by 21, rising from 393 at the end of September to 414 DUC wells at the end of October, as 133 wells were drilled into the Niobrara chalk during October, while 112 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, decreased by 3 wells, from 576 DUCs at the end of September to 552 DUCs at the end of October, as 100 new wells were drilled into the Marcellus and Utica shales during the month, while 103 of the already drilled wells in the region were fracked....on the other hand, the uncompleted well inventory in the natural gas producing Haynesville shale of the northern Louisiana-Texas border region rose by 11, from 535 DUCs in September to 546 DUCs by the end of October, as 76 wells were drilled into the Haynesville during October, while 65 of the already drilled Haynesville wells were fracked during the same period....thus, for the month of October, DUCs in the five major oil-producing basins tracked by this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) were unchanged at 3,289 wells, while the uncompleted well count in the major natural gas basins (the Marcellus, the Utica, and the Haynesville) was up by eight to 1,119 DUC wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas...


Ohio Leads the Way in Responsible Oversight of Natural Gas Operations - Energy In Depth In the midst of a global energy crisis where Ohioans have seen rising gas prices, familiar anti-natural gas activists are petitioning the federal government for increased government oversight of Ohio’s well resources, ignoring the state’s long documented history of responsible management. In a petition led by “Keep it in the Ground” actors such as the Sierra Club and Earthjustice, activists are demanding the U.S. Environmental Protection Agency (EPA) revoke Ohio’s Class II injection well program and put the state’s rulemaking authority back in the hands of the federal government. However, the petition is backed by flawed logic that ignores Ohio’s consistent record of best-in-class oversight that has been proven to be even stricter than that of the federal government’s, meaning the petition in question would actually weaken Ohio’s operating standards. Ohio has consistently been recognized for having rules more stringent than those set by the federal government. For example, federal regulations require one well inspection each year and a demonstration of mechanical integrity at least once every five years. In contrast, Ohio has unannounced inspections every 10-12 weeks and continuous mechanical integrity monitoring to ensure proper well functionality. In addition, all new wells in Ohio are required to be continuously monitored and include an automatic shut-off device to terminate operations if the permitted maximum allowable surface injection pressure is exceeded, meaning they can be shut down at a moment’s notice if required.

Shale academy to use grant for beautification - The Utica Shale Academy has gained grant funding which officials plan to use for beautifying Salineville. Instructor Matt Gates, who teaches horticulture, welding and industrial maintenance, obtained a $660 Best Practice Grant through the Jefferson County Educational Service Center and will put the funding to use for his “Park Waterfall Pond” project in the village. The grant will help purchase a pond form, pump, pump filter, waterfall rock and small rocks to construct a pond near the academy site on East Main Street and students will exhibit the skills they’ve learned with hand tools and heavy equipment to install the project. Officials said plans should begin soon. Gates said the pupils will operate a backhoe to dig the hole and place the liner for the pond, plus they will learn the importance of work and values while incorporating teamwork into the project. He said these learned skills will help them be successful throughout their life and career. “The project will benefit 25 students,” Gates added. “I have not applied for or received the Best Practice Grant before. I’m really excited to be chosen for the grant, and this gives us an extra opportunity to do a great project with the students while enhancing the community.” JCESC Superintendent Chuck Kokiko said the grants help support education and engage students in unique learning opportunities.

Monaca - How Shell's New Steam Cracker Is (and Isn't) Impacting Northeast NGL Markets --Shell’s new, multibillion-dollar steam cracker in Monaca, PA — the first of its kind in the Marcellus/Utica shale play — is finally up and running and breathing new life into a small town on the Ohio River. When it’s running flat-out, the cracker will churn out up to 9 million pounds of ethylene a day to supply three adjoining polyethylene units. Shell Polymers Monaca, as the petrochemicals complex is formally known, is a world-scale giant, consuming about 95 Mb/d of ethane, which raises this question: How is the start-up of the region’s only large ethane consumer affecting the broader market? In today’s RBN blog, we provide the answer.In energy-industry circles, it’s often said that you can’t get anything permitted and built in the northeastern U.S. — there are simply too many regulatory and legal hurdles to clear. There are certainly many tried-but-failed projects you could point to as evidence — natural gas takeaway pipelines into New York, New England and New Jersey come to mind, and the long-planned Mountain Valley Pipeline into Virginia remains in limbo. But it’s also true that many energy-related projects do advance to construction and operation. A prime example is the subject of today’s blog, Shell’s ethylene-and-PE complex northwest of Pittsburgh, which the company committed to building in 2016 and which recently came online, very close to Shell’s original schedule (despite some COVID-related setbacks). As we said in our Ain’t Wastin’ Time No More and Only Time Will (Sh)ell blogs six years ago, Shell received strong local support for its Shell Polymers Monaca project in Beaver County (see photo below), as well as substantial financial incentives from the commonwealth of Pennsylvania. Under the Keystone State’s Local Resource Manufacturing Tax Credit (which was enacted to bolster Shell’s prospective cracker project), any company that develops an ethane-consuming ethylene plant valued at $1 billion or more and that creates at least 2,500 jobs during the construction phase would be eligible for a tax credit equal to 5 cents/gal (or $2.10/bbl) of ethane purchased and used to produce ethylene. (For perspective, the current price of ethane at Mont Belvieu is 41 cents/gal.) The tax credit, which applies to ethane purchased between January 2017 and December 2042, can be used to reduce Shell’s overall tax liability to the state by up to 20%. Assuming that the cracker remains operational through December 2042 (20 years and two months in total) and consumes an average of 85 Mb/d (close to full capacity, that is), the tax credit’s value would total more than $1.3 billion ($2.10/b x 85,000 b/d x 365 days x 20.167 years). Separately, Shell reached "payments in lieu of taxes” agreements with the local government and school district.

Pennsylvania Fines CNX for Production Fluid Spills, Lengthy Cleanup - The Pennsylvania Department of Environmental Protection (DEP) said a CNX Resources Corp. affiliate has paid a $200,000 fine for allegedly failing to control and properly dispose of production fluids at shale well sites in the southwestern part of the state. DEP said 1,680 gallons of production fluid breached containment and discharged onto the ground in September 2019 at the company’s RHL 71 and RHL 87 well site in Greene County’s Richhill Township. About three months later, another 30 gallons of fluid breached containment and flowed into a sediment basin during hydraulic fracturing operations at the company’s RHL 4 well pad. In both cases, DEP said CNX postponed removing the contaminated soil until fracturing was completed. CNX postponed remediation at the RHL 71 and RHL 87 sites for nearly 70 days. “Delays like these are unacceptable,” said DEP’s Dan Counahan, southwest district oil and gas manager. “DEP expects, and the regulations require, prompt reporting and cleanup of spills and that operators will take measures to prevent future incidents.” DEP said CNX Gas Co. LLC paid a $125,000 civil penalty for violations at the RHL 71 and RHL 87 site. The company also paid a $75,000 civil penalty for violations at the RHL 4 site. Those penalties went into the state’s well plugging fund.

Water For Dimock? The Latest in the Long Fracking Saga -- The Associated Press is reporting that a Susquehanna County community made famous by flaming tap water and the fight over high-volume hydraulic fracture horizontal drilling for natural gas is about to get a staple most people take for granted.A new water line is reportedly going to be installed to deliver a clean, reliable drinking water supply to Dimock for the first time in 14 years.The AP report says on November 22, a public utility released the first details of a plan to mitigate the damage that a gas driller is charged with causing in the community located about 15 miles south of Binghamton.The allegations of contamination in Dimock drew national notoriety after residents were filmed lighting their tap water on fire in the Emmy Award-winning 2010 documentary “Gasland.” The case has been called one of the most notorious to ever emerge from the U.S. drilling and fracking boom.The AP published a statement from Pennsylvania American Water’s engineering manager, Dan Rickard saying “Pennsylvania American Water is pleased it had the opportunity to partner with the Attorney General’s office to develop a safe drinking water solution for the residents of Dimock, who like all of us, deserve access to clean, safe, reliable, and affordable drinking water.”Dimock residents were briefed on the plan on November 21 at a meeting with Pennsylvania American Water and high-level officials in the state attorney general’s office, which is pursuing criminal charges against Cabot Oil & Gas, one of the country’s biggest drilling companies, blamed for polluting Dimock's aquifer. (Cabot recently merged with a Denver-based company to form Corterra Energy Inc.). The news service report goes on to say that the residents declined comment Monday night as they left the meeting at a high school near Dimock, saying they’d been instructed by a prosecutor not to talk.“Our office remains laser focused on using our limited tools to restore clean drinking water for the residents of Dimock,” Jacklin Rhoads, a spokesperson in the attorney general’s office, said in a statement November 22. “Yesterday, our attorneys along with Pennsylvania American Water updated the impacted residents on the status of the case and the extensive independent research done with one goal — how best to provide clean water to their homes.”Further details of the water line plan, including its cost and whether the driller, Coterra Energy Inc., will bear the financial burden as part of any settlement of the criminal case, were not publicly released Tuesday.Residents of Dimock have used bottled water, bulk water purchased commercially, and even water drawn from creeks and artesian wells, saying they don't trust the water coming from their wells.The state attorney general’s office got involved in June 2020, filing criminal charges against the former Cabot Oil & Gas Corp. after a grand jury investigation found the company had failed to fix its faulty gas wells, which leaked flammable methane into residential water supplies in Dimock and surrounding communities.

New England ‘importing European prices’ in looming gas supply crunch | Financial Times -- A European-style winter energy crunch is looming over New England in the north-east US, even as American natural gas producers export record volumes and a wave of fuel heads across the Atlantic.Utility bosses in the region have called for emergency assistance from Washington to pre-empt a crisis, while lashing out at a century-old law that has cut New England off from some of America’s prolific shale output and left it more dependent on expensive imports.On Friday, a vessel laden with liquefied natural gas will land in Massachusetts — but the federal law preventing foreign vessels sailing between US ports means the gas will come from Trinidad, not the US export plants along the Gulf of Mexico that are shipping record amounts of fuel abroad.“You would think that charity would begin at home . . . that American fuel would go to American ports,” Joe Nolan, chief executive of Eversource Energy, one of New England’s biggest utilities, said in an interview. “We’re going to have to compete just like everybody else — in the global market.”The New England regional grid operator has said it will be able to cope under normal weather conditions this winter, but warned that a prolonged period of particularly cold temperatures could force it to ration electricity supply, potentially through rolling blackouts.Prices for gas to be delivered in Boston this winter have soared to almost $30 per million British thermal units on the Intercontinental Exchange, comparable to current prices in Europe, where utilities are scrambling to find international supplies to replace Russian energy. Gas elsewhere in the US for the same months is trading at about a quarter of that level. Spot prices even plunged below zero in western Texas in recent weeks, as production has climbed to new highs.Plans to pipe more gas to New England from huge shale deposits in nearby Appalachia were scrapped in recent years, while the 1920 Jones Act prevents foreign vessels — such as LNG carriers — from delivering gas superchilled on the Gulf to customers in the north-east.As Gulf terminals export record volumes of gas, Elizabeth Warren, the Democratic senator from Massachusetts, this year urged the administration of Joe Biden to curb LNG exports “to keep prices low for American consumers”.The vessel arriving from Trinidad at the Everett LNG terminal near Boston will be the 11th to land in the region this year, up from nine last year, according to Kpler, a tanker tracker. The price is likely to be close to European levels, said analysts. The terminal owner, Constellation Energy, said the US Coast Guard prohibited it from publicly disclosing information about cargoes arriving into the terminal.Despite the imports, utilities responsible for electricity transmission in the region, including Avangrid and National Grid, have warned of New England’s “tenuous reliability position” as temperatures drop. “On the precipice of the 2022-2023 winter period, New England is facing retail energy supply prices that are approximately twice what they were last winter and, perhaps more concerning, a dangerous fuel security situation should the region experience prolonged cold weather or an unplanned disruption to fuel supplies,” they wrote in a submission to the Federal Energy Regulatory Commission last week. The region has been in the vanguard of efforts to decarbonise US energy supply and build up new renewable power generation capacity, and a nascent offshore wind industry is starting to take root. But those developments will take time and analysts say the retirement of nuclear capacity, the blocking of new power transmission lines from Canada and gas pipelines from western Pennsylvania’s shale gasfields, as well as overly rosy assumptions about cheap foreign supplies, have left New England exposed. “You sleep in the bed you make,” The dim outlook for natural gas supplies is mirrored in the market for liquid fuels known asdistillates, including diesel and the heating oil that is used as a fuel in many New England households. The Energy Information Administration on Thursday warned households using heating oil — about a third of homes in the north-east, versus 4 per cent nationally — would pay 45 per cent more for their fuel this winter than last because of a tight market. Stocks of the fuel in the north-east have fallen by nearly half over the past year. An assessment by the non-profit North American Electric Reliability Corporation this week found that without “considerable effort” to replenish stocks of oil and LNG, there were concerns as to “whether there will be sufficient energy available to satisfy electricity demand during an extended cold spell”.

Jones Act Is Making The US Diesel Shortage Worse -The Merchant Marine Act of 1920, popularly known as the Jones Act, requires all cargo shipped between US ports to use vessels that are built, owned, and registered in the US, and have US crews. Still in force after several revisions, most recently in 2006, it is one of the main factors underpinning the price of diesel in the US. As a result, it is playing a key role in keeping upward pressure on inflation and increasing the risk of a sharp economic slowdown next year. Refining margins have soared to record levels this year. Prices have been much stronger for refined products than for crude, because of a global refining capacity shortage and disruption caused by widespread self-sanctioning as many countries stopped buying from Russia. The effect has been particularly marked for diesel. As crude prices have declined since the summer, the average on-highway cost price of diesel has fallen slowly, dropping 7% since mid-June to $5.317 a gallon last week. The low level of inventories underpins US diesel prices. US stocks of distillate fuel oil, which includes diesel, were about 106 million barrels in the first week of November, which is their lowest level on record for this time of year, in data that go back to 1982. However, Mark Williams, Wood Mackenzie’s research director for short-term oils, says the aggregate US data give an over-simplified picture of what is happening in the market. The real shortage of diesel is regionally specific to the northeastern US, and to New York Harbor. In most of the PADD (Petroleum Administration for Defense District) regions monitored by the EIA, distillate fuel oil stocks are broadly in line with their previous five-year ranges for this time of year. In PADDs 2-4, they are at or close to the lower end of the range, and in PADD 5, which includes the west coast, Alaska, and Hawaii, they are above it. It is only in PADD 1, the east coast, and PADD 1B, the Central Atlantic region from New York to Maryland, that inventories are well below their previous five-year range. Those low levels of inventories in PADD 1B have an outsize impact on the market because the area includes New York Harbor, the delivery point for the diesel futures traded on Nymex. The obvious solution to those regional imbalances would be to increase shipments of diesel from the other PADDs to New York. But because of the Jones Act, shipping fuel from one US port to another can be more expensive than sending it to Europe, which does not require US vessels and crews.

December Natural Gas Futures Rally on Coming Cold, Eclipse $6.700 Threshold - Natural gas futures found fresh footing on Monday, as traders mulled an updated relaunch timeline for a major export facility, railroad union members considered a strike, and forecasts pointed to another round of wintry weather in early December. After shedding 6.6 cents on Friday, the December Nymex gas futures contract surged 47.3 cents day/day and settled at $6.776/MMBtu to start the new week. January gained 50.7 cents to $7.223. NGI’s Spot Gas National Avg. advanced 24.5 cents to $6.930. Executives at the Freeport LNG export plant in Texas, forced offline in June following a fire, said Friday they now anticipate they will begin to bring operations back online in mid-December. This came after the liquefied natural gas facility missed an earlier goal to return to service by mid-November amid ongoing repairs and work to secure regulatory approvals. Management said reconstruction work necessary to commence initial operations, including utilization of all three liquefaction trains, was about 90% complete. They expected to complete repairs by the end of this month and updated their targeted relaunch to mid-December. The company expects to then ramp up to 2.0 Bcf/d of production capacity by January, with full restoration to 2.38 Bcf/d to follow. That final push may not happen until March, officials said. While a jolt to markets Friday because the protracted absence of Freeport further hinders U.S. exporters’ ability to meet strong global LNG demand, EBW Analytics Group analyst Eli Rubin said the update from the facility, once digested Monday, “helped settle the growing rumor mill that had exerted growing influence over Nymex natural gas.” This allowed the market to refocus on winter weather as “the leading short-term indicator for natural gas” prices in a holiday-shortened trading week leading to Thanksgiving on Thursday. He noted that forecasts shifted from calls for a moderate start to December to a “burgeoning cold pattern,” igniting Monday’s rally. The cold would drive robust heating demand and, potentially, cause wellhead freeze-offs that could slow production. This could follow a harsh blast of winter over the past week that galvanized demand across much of the Lower 48 and dropped output by more than 2 Bcf/d from around 101 Bcf/d at the start of November. Should widespread cold resume in early December, “a breakout to the upside” is possible, Rubin said. NatGasWeather also anticipated another round of cold. Over the weekend, the American and European models trended warmer for Wednesday through Dec. 1, but the firm said forecasts “tease a colder pattern attempting to return Dec. 2-4.” “Due to ongoing cold temperatures over the northern and central U.S., wellhead freeze-offs have dropped U.S. production by 2 Bcf/d-plus to 98-99 Bcf/d,” NatGasWeather added.

U.S. natgas holds at two-week high on rail strike worries (Reuters) - U.S. natural gas futures held at a two-week high on Tuesday as worries that a possible rail strike offset forecasts heating demand would decline as the weather turns milder than normal. A rail strike would disrupt shipments of coal to utilities, forcing power generators to burn more gas to produce electricity. Traders also noted the market had questions about whether Freeport will be able to restart its liquefied natural gas (LNG) export plant in Texas in mid December as planned. Freeport LNG has not yet submitted a full request to the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA) to restart the export plant, according to sources familiar with the company's filings. This matters because once the 2.1-billion cubic feet per day (bcfd) plant restarts it will consume U.S. gas to turn it into LNG for export, boosting demand for gas at the same time cold winter weather will boost heating demand. Even though the delayed Freeport restart caused one LNG vessel - LNG Rosenrot - to turn away from the plant last week, several other ships have remained near the facility - some for weeks - including Prism Brilliance, Prism Diversity and Prism Courage. In addition, the Prism Agility was expected to arrive at the plant site in a few days, according to ship tracking data from Refinitiv. In other LNG news, the Cadiz Knutsen arrived at the Everett LNG terminal in Massachusetts with a cargo of the super-cooled fuel from Trinidad, the first LNG vessel to visit Everett since August, according to Refinitiv data. But with Everett competing with European buyers willing to pay around $35 per million British thermal units (mmBtu) for gas versus just $7 in the United States, the Massachusetts port has imported only 16.7 billion cubic feet (bcf) of gas as LNG during the first 10 months of this year. That is down from 18.1 bcf during the same period in 2021 and a five-year (2017-2021) average of 33.3 bcf, according to federal energy data. New England depends on LNG and oil to fuel some power plants on the coldest days when most of the region's pipeline gas is being used to heat homes and businesses. About half of the power generated in New England comes from gas-fired plants. Front-month gas futures for December delivery rose 0.3 cent to settle at $6.779 per mmBtu, their highest close since Nov. 7 for a second day in a row.

Natural Gas Futures, Spot Prices Pop on Wintry Weather Outlook, Storage Withdrawal - Natural gas futures flew ahead Wednesday, rallying a third consecutive day on festering worries about a railroad strike, expectations for blasts of cold in the month ahead and the first storage withdrawal of the season. Prices also advanced in Europe and Asia over the past week, reflecting Russia-imposed supply concerns and continued strong demand for LNG sent from the United States. The December Nymex gas futures contract on Wednesday settled at $7.308/MMBtu, up 52.9 cents day/day. January jumped 30.2 cents to $7.708. NGI’s Spot Gas National Avg. gained 6.5 cents to $6.745. The U.S. Energy Information Administration (EIA) reported a withdrawal of 80 Bcf natural gas into storage for the week ended Nov. 18. The print proved lighter than market expectations, but it was notably steeper than the five-year average. “We are clearly well into the heating season now,” Refinitive analyst John Abeln said on the online energy platform Enelyst. His firm forecast this winter overall will be colder than the 30-year average. It “will be the third La Niña winter in a row, something that has not happened since 2000-01. La Niña winters typically feature cold weather in the Northwest,” which can spread throughout much of the Lower 48. Prior to the EIA report, major polls found expectations coalescing around a withdrawal in the mid-80s Bcf. The actual result easily exceeded a decline of 14 Bcf in the year-earlier period and a five-year average decrease of 48 Bcf. The 80 Bcf pull for the latest EIA week lowered inventories to 3,564 Bcf. That compared with 3,626 Bcf a year earlier and the five-year average of 3,603 Bcf. Looking ahead, analysts expected another bullish print relative to historic norms. Early estimates for the week ending Nov. 25 submitted to Reuters ranged from withdrawals of 79 Bcf to 119 Bcf, with an average decrease of 103 Bcf. The estimates compare with a decrease of 54 Bcf during the similar week of 2021 and a five-year average decrease of 34 Bcf.

U.S. natgas price drop trims weekly gains as milder weather predicted (Reuters) - U.S. natural gas futures fell nearly 4% on Friday on the upcoming expiration of the front-month contract and forecasts for less cold weather over the next two weeks, while solid gains earlier in the week still led the market to its biggest weekly gain in three. Front-month gas futures for December delivery fell 28.4 cents, or 3.9%, to settle at $7.024 per million British thermal units, after prices dropped nearly 7% to a session low of $6.80. "The forecast seems to suggest that even though we are going to see this polar vortex... (traders are) pulling back some of their positions on the anticipation, the cold blast might not be as far reaching as originally feared," However, the contract posted its second straight weekly gain of over 11%, having risen to a two-month peak on Wednesday. "The bullish price action stemmed from concerns over the potential U.S. railroad workers’ strike in early December, which was exacerbated by thin market participation as many traders are out of the market for a long holiday weekend," But some "bearish reality is setting in" with a near-term warm-up in temperatures, recent storage data coming in bearish relative to expectations, dry gas production now at parity with record highs and the options expiration for the December gas contract, the note said. The U.S. Energy Information Administration (EIA) said on Wednesday utilities pulled 80 billion cubic feet (bcf) of gas from storage during the week ended Nov. 18, which was slightly smaller-than-expected. Meanwhile, British and Dutch gas prices were mixed due to profit taking following recent bullishness and as EU energy ministers failed to agree on a gas price cap and cooler, less windy weather increased demand for heating. In addition, the market had questions about whether Freeport LNG will be able to restart its liquefied natural gas (LNG) export plant in Texas in mid-December as planned. Freeport LNG has not yet submitted a full request to the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA) to restart the export plant, according to sources familiar with the company's filings. That matters because once the 2.1-billion-cubic-feet-per-day (bcfd) plant restarts it will consume U.S. gas to turn it into LNG for export, boosting demand for gas at the same time that cold winter weather will boost heating demand.

Will The US Gulf Coast Soon Be Home To Floating LNG Export Capacity? RBN Energy -- The need for more LNG export capacity, driven both by Europe’s push to wean itself off Russian gas and long-term Asian demand growth, is resulting in a new wave of development. Two major U.S. projects have reached a positive final investment decision (FID) in the past six months and more are likely to do so soon, both in the U.S. and elsewhere. But conventional export terminals take time to build, leading at least some, like New Fortress Energy, to explore the potential for floating LNG (FLNG) facilities — basically, an LNG export terminal located on the topside of a large tanker — which can bring new capacity online faster, much like the floating storage and regasification units (FSRUs) that are now boosting European import capacity. In today’s RBN blog, we take a look at FLNGs, what’s already out there, and what could be coming to North America in the next few years.An FLNG terminal has everything that a conventional terminal has, from feedgas intake to liquefaction equipment to storage, housed right on the vessel. To date, FLNGs have only been used with offshore production as a feedgas source, docking near the gas source and tying into new or existing subsea infrastructure. In many ways, the current interest in floating export terminals — including FLNGs docked at onshore locations, not out at sea — would seem to be a natural extension of the interest in FSRUs (see Float On for a review of FSRUs). So far, though, there are just five FLNGs in operation (again, all of them at offshore production sites), compared to about 50 FSRUs currently in operation and more coming.The five FLNG vessels in operation are:

  • Shell’s Prelude LNG — the largest of the FLNG vessels already up and running, with a capacity of 3.6 million tons per annum (MMtpa; about 480 MMcf/d). It is located off the coast of Australia (blue-outlined ship in Figure 1).
  • Petronas’s PFLNG Satu and PFLNG Dua, which have a combined capacity of 2.7 MMtpa (~360 MMcf/d) and are both anchored off Malaysia (pink ships).
  • Golar LNG’s Hilli Episeyo, located off Cameroon (red ship). It has an export capacity of 2.4 MMtpa (~320 MMcf/d) but currently operates around 1.4 MMtpa (~185 MMcf/d) while drilling infrastructure in the area is being scaled up.
  • ENI’s brand-new Coral-SUL FLNG, which is anchored off Mozambique (yellow ship) and exported its first LNG cargo earlier this month. TheCoral-SUL has a capacity of 3.4 MMtpa (~450 MMcf/d).

Beyond these five, ENI’s Tango FLNG, a 0.6-MMtpa (~80 MMcf/d) terminal that previously operated in Argentina, is being moved to the Republic of Congo (green square). First LNG from the new location is expected next year as part of the Marine XII project. BP also has a project in Africa under construction, the Greater Tortue Ahmeyim FLNG project, located offshore at the border of Senegal and Mauritania (purple square), which is due online in 2023 after some construction delays. [While FSRUs have primarily seen smooth startups, FLNG vessels have often faced a bumpy road (see New Dawn Fades for more).] Reliability has also been a concern for the existing FLNGs. The unplanned downtime is much higher compared to land-based terminals as it’s harder to complete repairs and maintenance in such tight quarters.

Deepwater Oil And Gas Production To Rise 60pct By 2030 --Deepwater production is set to increase by over 60% between 2022 and 2030, growing from 6% to 8% of overall upstream production. Ultra-deepwater production – from depths of 5,000 feet and above is growing fastest – by 2024 it will account for more than half of all deepwater production. Deepwater is the fastest-growing upstream oil and gas resource theme. From just 300,000 barrels of oil equivalent per day (boe/d) in 1990, production is expected to hit 10.4 million boe/d in 2022. By the end of the decade, that figure should pass 17 million boe/d, Wood Mackenzie suggested. According to Woodmac, Brazil remains the leading deepwater producer, it accounts for around 30% of current global capacity and will continue to grow. Guyana, the most significant new entrant, will be producing one million boe/d within the next five years. In total 14 other countries will contribute to the deepwater supply mix in the coming years. Despite the diversification of sources, and corporate participants, control over major deepwater projects sits in the hands of relatively few companies. Just eight companies account for 65% of deepwater production and 67% of the remaining project value. Petrobras and the seven Majors dominate deepwater production, operating 22 of the top 25 deepwater assets. Petrobras’ deepwater portfolio is around twice as big as its nearest peer, Shell, which stands out among the majors for leading production and cash flow. ExxonMobil and TotalEnergies show the highest rates of growth this decade. Woodmac said that, typically, only the best subsurface plays become commercial in water this deep. Deepwater basins, therefore, tend to be hyperproductive, recovering huge volumes of oil and gas from each well. This translates into high economic returns and low Scope 1 and 2 emissions intensities relative to most other oil and gas resource themes. But there is still room for emissions improvement. The Majors are focused on cutting deepwater emissions by reducing flaring and methane leaks, optimizing operations at existing platforms, and, where possible, facility electrification. Brazil’s scale means it is the highest absolute emitter and its performance is contingent on Petrobras’ decarbonization aspirations.

Offshore oil and gas at risk of potentially catastrophic cyberattack: GAO - The nation’s offshore oil and gas industry faces a significant and growing risk of a malicious cyberattack that could result in a catastrophic incident rivaling the deadly Deepwater Horizon incident in 2010, according to a report from the U.S. Government Accountability Office.. The industry includes about 1,600 offshore oil and gas facilities that are highly dependent on remotely connected operational technology, the report said. Many of these systems rely on aging technology, which lack many of the built-in safeguards that protect facilities against modern cybersecurity risks. The Department of Interior, which oversees the industry, needs to urgently develop a plan to mitigate such a threat, the report warns. Department officials have been aware of such a risk for years, however multiple attempts to take corrective action have fallen short or failed to get off the ground. The 2021 Colonial Pipeline ransomware attack disrupted much of the nation’s supply of gasoline for nearly a week, causing runs on fuel, temporary price spikes and outages in stations across the Southeast and Mid-Atlantic states. Following that incident and the later ransomware attack on meatpacking firm JBS USA, the Biden administration highlighted the risk of cyberattacks or breaches across a core group of 16 critical infrastructure sectors. The offshore oil and gas industry is part of a larger risk to the U.S. energy sector, which has come under scrutiny in part due to Russia's invasion of Ukraine, which has led to even greater pressure on global oil and gas prices and attacks on energy facilities. The Bureau of Safety and Environmental Enforcement at the Interior Department previously launched efforts in 2015 and 2020 to address cybersecurity risks, but failed to take substantive action in both cases, according to the report. The BSEE launched another plan earlier this year to address cybersecurity and hired a specialist to lead the effort, but later put that plan on pause to offer more time for the official to get up to speed on the issues, the report stated. “Interior officials, specifically the [BSEE] leadership, has been aware of cyberthreats to offshore infrastructure, but have simply not acted on those threats in a sufficient or timely fashion,” Frank Rusco, director of national resources and environment at GAO, said via email. While Rusco said the agency cannot specifically rank what type of cybersecurity attack poses the biggest risk, he reiterated “environmental and worker safety damages are potentially very large” in light of the multi-billion dollar cost of the Deep Water Horizon disaster. The explosion and 87-day oil spill resulted in 11 deaths and 134 million gallons of oil leaked into the Gulf of Mexico. A federal judge in 2016 approved a record $20.8 billion settlement in the case. A spokesperson for the National Ocean Industries Association, which serves offshore oil, gas, wind and ocean minerals industries, said cybersecurity is a “critically important issue” for the group, but they were in the process of reviewing the report. A spokesperson for BSEE said the agency does not have any further comments beyond what was printed in the report.

Biden administration approves Gulf oil terminal opposed by Texas city --Federal regulators this week approved a new oil terminal in the Gulf of Mexico off Texas over the objections of local activists, who argued the move contravenes the Biden administration’s stated climate goals.The Transportation Department’s Maritime Administration formally granted the license Nov. 21, ending a process that began under the Trump administration three years ago. The Sea Port Oil Terminal would be located offshore of Freeport, Texas, with a capacity of 2 million barrels a day. The project would involve two pipelines running through the city of Surfside Beach, where the City Council unanimously voted in opposition to the project in March 2020.Greenpeace blasted the Biden administration’s approval of the terminal, pointing to an environmental impact statement published in July projecting the terminal would generate 83,000 tons of carbon emissions per year through the construction process alone, with a projected total of 219 million tons a year in downstream refining and combustion emissions.The environmentalist group also pointed to President Biden’s recent attendance at the COP27 United Nations climate conference in Sharm el-Sheikh, Egypt, and the Biden administration’s stated commitment to cutting carbon emissions by 50 percent by 2030.“When we say oil and gas companies are sacrificing communities to make a buck this is exactly what we’re talking about. We have less than a decade to cut emissions by half. Approving new oil and gas projects is not a bridge, it is an on-ramp to planetary collapse,” Destiny Watford, climate campaigner at Greenpeace US, said in a statement. “It is peak hypocrisy for President Biden and [Transportation] Secretary Pete Buttigieg to shorten the fuse on the world’s largest carbon bomb by greenlighting additional oil export terminals right after lecturing the world about increasing climate ambitions at COP27.”

Permian Gas Production Set to Rise 41% by 2030, Rystad Says —Gas production from the Permian Basin is expected to grow approximately 6.3 Bcf/d by 2030, up around 41% compared to current levels. The bulk of the Permian’s gas production will come from the Delaware sub-basin followed by the Midland sub-basin by the end of the decade, Rob Cordray, senior vice president of consulting at Rystad Energy, told attendees to the Hart Energy Executive Oil Conference. The U.S. Permian Basin as well as the other U.S. shale basins are key to anchoring U.S. LNG exports and projected rises in the future. Permian production of both oil and gas has already surpassed pre-pandemic highs, Cordray said. “Permian production grew at a rate of 15.3% per annum from January 2018 to June 2022, rich gas production led growth, while light oil volumes have maintained a greater share of production owing to higher baseline volumes,” he said, adding that “rich gas volumes have broken out above the share range bound 30%-35% share of production, reaching nearly 40% in the second quarter of 2022.” Volume growth in the Permian Basin has been led by gas production in both the Delaware and Midland basins with volumes doubling between first-half 2018 and first-half 2022 to 11.7 Bcf/d and 6.8 Bcf/d, respectively. However, the production mix in the Central Basin Platform and elsewhere in the Permian has seen little or no change, according to Rystad data. Despite the rising production profile in the Permian Basin, flaring intensity has declined by 70%, led by substantial improvements in key sub-basins. Expanded pipeline capacity has coincided with immediate flaring reductions, according to Cordray. It should also be noted that flared volumes in the Permian Basin rose between 2018-2019 owing to a lack of infrastructure as well as outages of gas processing facilities and pipelines, he added. Cordray said the top five U.S. shale plays—Permian Midland, Permian Delaware, Haynesville, Utica and Marcellus—are slated for continued growth and expected to assist gas production rise to around 110 Bcf/d in 2030. The five plays are set to account for 73% of all U.S. gas output by 2040. U.S. LNG piped-gas exports to Mexico are also set to rise anchored by much of the same gas production growth trends. Growth in U.S. LNG exports is expected to accelerate through the end of the decade and surpass 25 Bcf/d by 2030 amid strong demand for the low-carbon energy source and as Europe scrambles to buy up LNG to replace lost Russian piped gas-imports. Through the end of the decade, U.S. gross LNG exports for producing and sanctioned projects could reach around 25% of total U.S. LNG production by 2030 and around 31%-32% by 2040.

Texas Just Had Its Biggest Earthquake in Decades, and Fracking Is a Prime Suspect -The Railroad Commission Texas, which regulates the state’s oil and gas industry, is investigating a 5.4-magnitude earthquake that rocked communities in West Texas last Wednesday, The Texas Tribune reports.Hydraulic fracturing, or fracking, is a drilling technique common in the areathat is known to cause earthquakes.According to the U.S. Geological Survey, the earthquake occurred on November 16, just west of Pecos, Texas. This was the state’s largestearthquake since 1995 and was felt as far as El Paso. The oil and gas regulatory agency is trying to understand if this was a naturally occurring earthquake or if it was caused by waste water from fracking. Waste water disposal from fracking has dramatically increased the number of earthquakes in Texas. The seismic activity has especially become more common around the Permian Basin in West Texas, where oil and gas production is concentrated, according to the Texas Tribune.During the fracking process, oil companies inject a mix of water, sand, and chemicals into Earth’s crust. This fractures the rock formation, which then allows the companies to extract natural gas and oil from deep in the ground. Many oil and gas companies dispose of this polluted waste water in wells deep underground. The pressure from these wells can trigger nearby dormant fault lines, causing earthquakes. A lot of the recorded seismic activity around areas like Pecos and El Paso has been connected to these contaminated underwater wells, according to research from the U.S. Geological Survey.The Texas Tribune previously reported that the number of earthquakes in the state doubled in 2021. According to data from the Bureau of Economic Geology at the University of Texas at Austin, there were more than 200 earthquakes categorized as 3 magnitude and higher. There were only 95 earthquakes reported in Texas in 2020, according to the Bureau’s data. Communities near hydraulic fracturing sites are at risk from more than just rumbling ground. A study this past January connected fracking to premature deaths of people who live near the sites. Fracking is known to pose significant health risks: The sites contaminate nearby water sources, and fracking leakscarcinogenic pollutants into the air and water. Fracking can also release PFAS into the environment, chemicals linked to a variety of health issues.

'El Paso May Get Stronger Earthquakes,' Says Seismologist - Last week, a 5.4 earthquake centered near Pecos was felt by thousands of people over two hundred miles away in El Paso. And, according to a seismologist at UTEP, we could be in store for even bigger quakes in the future.Aaron Velasco says El Paso could get a 7-point earthquake AND it could be centered much closer than last week’s. Professor Velasco says the quake last week is the largest that has happened in Texas since modern times and definitely the biggest on record.El Paso sits on the East Franklin Mountain Fault and, Velasco says, if that fault were to experience a slip (which it WILL someday), the resulting quake could be as strong as 7.0 on the Richter Scale.The last time the EFM Fault slipped was 12,000 years ago. But, Mr. Velasco says, the next slip could be “a thousand years from now, or tomorrow”. Of course, he adds, the chances of it happening any time soon are “very low”.So, what’s causing EARTHQUAKES to happen in Texas? When I grew up, in Oklahoma, the idea of an earthquake in the Sooner state would have been far-fetched, like having a blizzard in Miami Beach.For the past decade or so seismological events have become fairly common. I always think, “those earthquakes only started when fracking started up”. I know correlation doesn’t always equal causation but many geologists have favored the theory of “induced earthquakes”.The US Geological Survey says that around 2% of these induced quakes might be the result of fracking, a technique of running salt water into the ground to “fracture” the subsurface and make hard-to-reach oil deposits accessible.The majority of induced earthquakes, the USGS says, are primarily caused by the disposal of wastewater which IS a byproduct of oil production. The largest earthquake KNOWN to be induced by fracking was a 4.0 quake, also in Texas, in 2018. Prof. Velasco speculates that waste disposal from fracking COULD be a factor in last week’s event. He also says that a 7.0 event could cause “significant structural damage” to buildings in El Paso and that planning and prepare for such an event would be wise. Here’s the video of the story that ran on KTSM news:

Diesel Shortage: World's most-crucial fuel heads for shortage touching everything - No fuel is more essential to the global economy than diesel. It powers trucks, buses, ships and trains. It drives machinery for construction, manufacturing and farming. It’s burned for heating homes. And with the high price of natural gas, in some places it’s also being used to generate power. Within the next few months, almost every region on the planet will face the danger of a diesel shortage at a time when supply crunches in nearly all the world’s energy markets have worsened inflation and stifled growth. The toll could be enormous, feeding through into everything from the price of a Thanksgiving turkey to consumer bills for heating homes this winter. In the US alone, the surging diesel cost will mean a $100 billion hit to the economy, according to Mark Finley, an energy fellow at Rice University's Baker Institute of Public Policy. “Anything and everything that gets moved in our economy, diesel is there,” Finley said. “Moving stuff around is one thing. People potentially freezing to death is another.” In the US, stockpiles of diesel and heating oil are at their lowest point ever for this time of year in data going back four decades. Northwest Europe is also facing a low buffer — inventories are forecast to hit a low this month and then tumble even more by March, shortly after sanctions come into play that will cut the region off from Russian seaborne supplies. Global export markets have gotten so tight that poorer countries like Pakistan are getting shut out, with suppliers failing to book enough cargoes to meet the nation’s domestic needs. Diesel in the spot market of New York harbor, a key benchmark, is up roughly 50% this year. The price reached $4.90 a gallon in early November, about double year-ago levels. Even more telling is the premium that diesel is commanding. Spreads for the fuel are widening both against crude oil, a sign of how tight refining capacity is, and in relation to supplies that are for later delivery, underscoring that traders are desperate to get their hands on the stuff now. In northwest Europe, diesel futures cost about $40 a barrel more than Brent, versus a five-year seasonal norm of just $12. New York diesel futures for December delivery are trading about 12 cents higher than those for January. That compares with a premium of less than a cent at this time last year. Supplies of crude oil are already fairly tight. But the bottleneck is much more acute when it comes to turning that raw commodity into fuels like diesel and gasoline. That’s partly a function of the pandemic, after lockdowns destroyed demand and forced refiners to close some of their least profitable plants. But the looming transition away from fossil fuels has also dented investments in the sector. Since 2020, US refining capacity has shrunk by more than 1 million barrels per day. Meanwhile in Europe, shipping disruptions and worker strikes have also eaten into refinery production. Things could get much more dramatic with the European Union’s looming pivot away from Russian supply. Europe relies more heavily on diesel than any other in the world. Roughly 500 million barrels a year get delivered by ship, with around half of that typically loaded at Russian ports, according to data from Vortexa Ltd. The US also has halted imports from Russia, which was a big supplier to the East Coast last winter. Also churning in the background is a market structure known as backwardation, when premiums are higher for supplies with prompt deliveries than for longer-term ones. Not only has that spread been unusually large, but the backwardation has lasted unusually long. This backwardated market structure incentivizes suppliers to sell now instead of holding onto the product to build inventories. In the US, shortages along the East Coast already had suppliers rationing and initiating emergency protocols, and winter hasn’t even begun. The Northeast, the most densely populated corner of the US where temperatures are often below freezing during a bitter winter, is also the most reliant on heating oil for keeping homes warm. (Diesel and heating oil are the same product in the US, just taxed differently.) Even in a best-case scenario, consumers there will be saddled with the highest energy bills in decades this winter. Already, the government has nearly doubled its estimate for the increase, projecting that families who rely on heating oil can expect to pay 45% more than last winter, up from an October estimate of 27%. To be sure, prolonged, diesel shortages throughout the US are improbable since the country is a net exporter of the fuel. But localized outages and price spikes are likely to become more frequent, especially on the East Coast, where a dearth of pipelines creates huge bottlenecks. The region is heavily reliant on the Colonial pipeline that’s often full. A century-old shipping law, known as the Jones Act, further complicates the movement of domestic fuel and encourages producers on the Gulf Coast to favor exports over supplying the domestic market. From early February, EU sanctions will ban Russian seaborne deliveries. Those Russian barrels must somehow be replaced if the region’s economy is to keep running as it is today. How and whether that will happen is, so far, unclear. Winter cold will also exacerbate problems in Europe. Across the northwest, inventories are expected to sink to 211.9 million barrels in March, the month after the EU sanctions kick in, according to consultancy Wood Mackenzie Ltd. That would be lowest level in records going back to 2011. As the sanctions deadline rapidly approaches, Europe is still importing a huge amount of diesel from Russia. It is also pulling in vast quantities from Saudi Arabia, India and others. As a result, October waterborne imports hit their highest since at least the start of 2016, according to data from Vortexa compiled by Bloomberg. Germany has already seen tightness, as low Rhine levels hampered deliveries and curbed production, while refineries in neighboring Hungary and Austria have also suffered significant disruption. French output was stifled by a spate of worker strikes over pay. “If Russia is not a supplier anymore, that puts a big, big dent into the system, which is going to be really difficult to fix,”

Lesser Prairie-Chicken Listed as Endangered or Threatened in Five States, Posing Oil and Natural Gas Hurdles - The lesser prairie-chicken, whose habitat is spread across five U.S. states, has been listed as endangered or threatened under the stringent Endangered Species Act (ESA), which may lead to issues for future oil and natural gas development. The U.S. Fish and Wildlife Service (USFWS) earlier this month listed two distinct population segments (DPS) of the species as endangered or threatened. The listings followed an extensive review of “past, present and future threats,” and by analyzing ongoing conservation efforts. The Southern DPS, which includes eastern New Mexico and the southwestern Texas Panhandle, “is in danger of extinction,” officials said. The Northern DPS, encompassing southeastern Colorado, south-central to western Kansas, western Oklahoma and the northeastern Texas Panhandle “is likely to become endangered in the foreseeable future.” A rule also is being finalized by USFWS to conserve the Northern DPS habitat for lesser prairie-chicken “while allowing greater flexibility for landowners and land managers.” Habitat in Southern DPS consists mostly of shinnery oak prairie. Habitat in the Northern DPS includes short-grass, mixed-grass and sand sagebrush ecoregions. “The lesser prairie-chicken’s decline is a sign our native grasslands and prairies are in peril,” said USFWS’s Amy Lueders, Southwest regional director. “These habitats support a diversity of wildlife and are valued for water quality, climate resilience, grazing, hunting and recreation. “The Service continues to work with stakeholders to develop voluntary conservation agreements that will protect the lesser prairie-chicken and the native grasslands on which it depends while assuring that oil and gas and renewable energy development, ranching, agriculture and other activities continue.”

Oil, Natural Gas Permitting Tick Up in Rockies as Permian, Marcellus Dip - Oil and natural gas permitting in the Lower 48 slowed down sequentially in October, although the monthly permit count was up on both a year/year basis and when compared to pre-Covid October 2019 numbers, Evercore ISI data show. Operators filed a total of 3,308 permits last month, down 16% from September but up 25% versus October 2021, said Evercore researchers led by James West in the firm’s latest monthly tally. The permit count also was up 6% versus October 2019, researchers noted. The Permian Basin of West Texas and southeastern New Mexico led the month/month decline, with permits falling by 486 to 1,190. The Marcellus and Eagle Ford shales also saw drops of 149 and 87, respectively, versus September. These declines were partially offset by permitting increases in the Powder River (plus 87) and Denver-Julesburg/Niobrara (plya 70) basins, as well as “smaller shale plays (plus 203),” the Evercore team said. The Powder River Basin (PRB) of northeastern Wyoming and southeastern Montana features prominently in the portfolios of Lower 48 players such as EOG Resources Inc. and Devon Energy Corp. Devon reported average pre-hedge natural gas prices of $8.23/Mcf in the PRB during the third quarter. Pioneer Natural Resources Co. bucked the Permian permitting trend, filing 104 permits in October, up 82% month/month to record the highest monthly total of any operator in the basin. Pioneer also is the largest Permian producer. The Permian’s next four leading permit filers were Diamondback Energy Inc. (50), Chevron Corp. (27), Coterra Energy Inc. (27) and Occidental Petroleum Corp. (25). Broken down by state, month/month declines were seen in Texas (minus 537), New Mexico (minus 132), North Dakota (minus 21), Oklahoma (minus 56) and Pennsylvania (minus 122). These drops were partially offset by gains in California (up 164), Wyoming (up 105) and Colorado (up 66).

Oil, Natural Gas Lease Sales Proposed for Nevada and Utah - The Bureau of Land Management (BLM) has begun a one-month scoping process to take comments on potential oil and natural gas lease sales across parts of Nevada and Utah. The Interior Department agency is reviewing potential auctions for up to 35 parcels in Nevada totaling 63,604 acres and 18 parcels in Utah totaling 31,808 acres. The lease sales, if approved, would include updated fiscal provisions authorized by the Biden administration’s Inflation Reduction Act (IRA). The provisions require minimum bids of $10/acre for all offered parcels, an increase from the $2 minimum set in 1987. Royalty rates would increase to 16.67% from the previous minimum of 12.5%. In addition, rental rates would be $3/acre for the first two years, $5 for years three through eight, and $15 in years nine and 10. Prior to the IRA, rental rates originally set in 1987 were $1.50/acre for the first five years and $2/acre for each year thereafter. BLM also updated the policy guidance to implement the IRA provisions, which include the right to refuse anonymous nominations for land to be sold at auction and prioritizing leasing near existing drilling developments and away from protected lands. The update also tightens the rules that govern permit extensions to drill.

U.S. oil giants Exxon Mobil, Chevron and ConocoPhillips challenged over ‘secretive’ tax practices -- Oxfam on Monday filed shareholder resolutions against U.S. oil giants Exxon Mobil, Chevron and ConocoPhillips, saying a lack of transparency over their global tax practices poses a material risk for long-term investors. The international relief charity said the companies' tax practices undermine the public's interest in a fair tax system — especially in Global South countries "with the greatest tax revenue needs." "Exxon, Chevron, and ConocoPhillips's threadbare tax disclosures leave investors, watchdog groups, and the general public in the dark about the companies' secretive tax practices," Daniel Mulé, policy lead on extractive industries and tax at Oxfam America, said in a statement. ConocoPhillips confirmed it had received a shareholder proposal from Oxfam and would review it ahead of its annual general meeting in May next year. The company added that it "remains committed to following all applicable disclosure rules in the countries in which we operate." A spokesperson for Chevron said the company "complies with all applicable tax laws. Our approach to tax matches our efforts globally to conduct our business legally, responsibly, and with integrity." Exxon Mobil did not respond to a request for comment when contacted by CNBC. It comes amid a broader push for greater tax transparency from large corporations, particularly as people around the world feel the squeeze of a cost-of-living crisis. Oil majors have been repeatedly criticized for their global tax operations. And, in recent months, energy giants have faced growing calls for a windfall tax after raking in record-breaking profits thanks to a surge in the price of oil and gas following Russia's invasion of Ukraine. Speaking late last month, U.S. President Joe Biden threatened to pursue higher taxes on oil company profits if industry giants do not work to cut gas prices, accusing energy giants of "war profiteering." "Oil companies' record profits today are not because they're doing something new or innovative," Biden said on Oct. 31. "Their profits are a windfall of war — the windfall from the brutal conflict that's ravaging Ukraine and hurting tens of millions of people around the globe."

Environmental groups oppose pipeline expansion in Pacific NW - (AP) — The U.S. government has taken a step toward approving the expansion of a natural gas pipeline in the Pacific Northwest — a move opposed by environmentalists and the attorneys general of Oregon, California and Washington state. The Federal Energy Regulatory Commission, or FERC, announced Friday it has completed an environmental impact statement that concluded the project "would result in limited adverse impacts on the environment.”“Most adverse environmental impacts would be temporary or short-term,” the federal agency said.A grassroots coalition of environmental groups said the analysis conflicts with climate goals of Pacific Northwest states and fails "to address upstream methane emissions from the harmful practice of fracking.” The Gas Transmission Northwest pipeline belongs to TC Energy of Calgary, Canada - the same company behind the now-abandoned Keystone XL crude oil pipeline. Gas Transmission Northwest proposes to modify three existing compressor stations along the pipeline — in Kootenai County, Idaho; Walla Walla County, Washington; and Sherman County, Oregon — to boost capacity by about 150 million cubic feet per day of natural gas. The company says the project is necessary to meet consumer demand.The 1,377-mile (2,216-kilomter) pipeline runs from the Canadian border, through a corner of Idaho, and into Washington state and Oregon, connecting with a pipeline going into California.In August, the attorneys general of Oregon, Washington state and California asked the FERC to deny the proposal, saying the expansion is expected to result in more than 3.24 million metric tons of greenhouse gas emissions per year, including methane and carbon dioxide.“This project undermines Washington state’s efforts to fight climate change,” Washington state Attorney General Ferguson said back then. “This pipeline is bad for the environment and bad for consumers.”The grassroots coalition said the federal study didn’t adequately address harmful impacts on the climate caused by the project, including by fracking to obtain the natural gas. The energy industry uses the technique to extract oil and gas from rock by injecting high-pressure mixtures of water, sand or gravel and chemicals. But the technique increases emissions of methane, an extraordinarily potent greenhouse gas.“FERC’s approach will worsen the climate crisis, downplaying the impacts of a proposal that will pollute our communities, impact health and safety, and create millions of tons of climate-changing pollution each year,” said Lauren Goldberg, executive director of Columbia Riverkeeper, an environmental group based in Hood River, Oregon.The regulatory commission’s study noted that its staff was unable to assess the project’s contribution to greenhouse gases “through any objective analysis.”“Climate change is a global concern,” the federal study said. “However, for this analysis, we will focus on the existing and potential cumulative climate change impacts in the project area.”TC Energy said Saturday that it is reviewing the environmental impact statement, which recommended a few mitigation measures.

Enbridge Rations Pipeline Space -Enbridge Inc., the world’s largest oil export pipeline system operator, is rationing space on its key Canada line, adding yet another headwind for oil producers. Enbridge will apportion space on the heavy oil segment of its Mainline system -- known as Line 4/67/93 and running from Alberta to Wisconsin-- by the most since November last year. Apportionment is when shippers reduce volume when they see too much demand on a system, and has contributed to a glut of supply in the past as producers are left with the excess. Pipeline apportionment has previously led to large discounts for Canada’s crude oil and now threatens already-weak oil prices. The discount for Canadian heavy crude is almost $30 in Alberta, close to the widest since 2018, amid releases of high-sulfur oil from US strategic petroleum reserves and high natural gas prices making Canadian oil expensive to refine. The rise in apportionment signals that export lines may be filling up again amid record oil production in the province and rising demand for Canadian crude on the US Gulf Coast.

CFE Natural Gas Exports from U.S. to Mexico Surge in Second Quarter A U.S. subsidiary of Mexico’s state power company Comisión Federal de Electricidad (CFE) posted a 14% year/year increase in pipeline natural gas exports from the United States to Mexico during the second quarter, according to the U.S. Department of Energy. The subsidiary, CFE International LLC (CFEi), exported 298,963 MMcf or 3.3 Bcf/d under short-term contracts during the period, up from 262,844 MMcf (2.89 Bcf/d) in 2Q2021, according to DOE’s latest North American natural gas trade report. Amid stagnant production in Mexico, CFE sources gas from the United States in order to fuel the company’s growing fleet of gas-fired power plants. It also markets gas to third parties within Mexico. CFEi was the No. 12 marketer by volume in NGI’s latest quarterly survey of North American marketers and traders. Pemex Transformación Industrial, a subsidiary of state oil company Petróleos Mexicanos (Pemex) exported 60,829 MMcf or 668 MMcf/d from the United States during the period, down from 89,218 MMcf (980 MMcf/d) a year earlier, DOE data show. Exports of U.S. natural gas to Mexico by pipeline and truck rose 8.8% sequentially but fell by 5.5% year/year in 2Q2022 to 542.7 Bcf or 5.96 Bcf/d, according to the report. Mexico was the destination for 70.6% of U.S. pipeline exports, with the remaining 29.4% going to Canada. Prices of U.S. pipeline and trucked exports to Mexico averaged $7.22/MMBtu for the quarter, up from $3.06 in 2Q2021. The United States exported gas to Mexico via 19 exit points along the border during the second quarter. About 61% of exports transited from one of four Texas border cities: Rio Grande City and Brownsville in South Texas, and Presidio and San Elizario in West Texas. Rio Grande City was the winner, accounting for 127.6 Bcf or 1.4 Bcf/d. Brownsville is the starting point of the 2.6 Bcf/d Sur de Texas-Tuxpan offshore pipeline. Exports to Mexico via the Permian Basin in West Texas doubled from 0.6 Bcf/d in 2019 to 1.2 Bcf/d in 2021, driven by infrastructure coming online in Mexico, according to a recent note by the U.S. Energy Information Administration. CFEi CEO Miguel Reyes said at the recent LDC US-Mexico Natural Gas Forum in San Antonio, TX, earlier this month that CFE is working with private sector firms to optimize excess pipeline capacity to shore up supply for the Mexican market. Flagship projects include the 1.3 Bcf/d Southeast Gateway offshore pipeline planned with TC Energy Corp., as well as an offshore liquefied natural gas hub in partnership with New Fortress Energy Inc.

Mexico’s Gas-Rich Lakach, Once Thought Dead, Being Revived as Export Project - New Fortress Energy Inc. (NFE) is steaming ahead with another LNG export project in Mexico. On Tuesday, the company said it had finalized a deal with Mexican state oil firm Petróleos Mexicanos (Pemex) to develop and operate a natural gas field and a liquefaction project off the coast of Veracruz. The offshore liquefaction plant at the Lakach deepwater natural gas field would be in addition to at least two liquefied natural gas units planned offshore the port of Altamira. While those other projects will use U.S.-sourced gas, for this project NFE would invest in completing seven offshore wells at the gassy Lakach field over a two-year period. Plans are for NFE to deploy to the Lakach field its 1.4 mmty Sevan Driller floating liquefied natural gas (FLNG) unit, which is currently being readied in a shipyard in Singapore. NFE anticipates the all-in cost of producing LNG at Lakach will be among the lowest in the world. The news comes as European LNG imports are fetching record high prices. Given the Atlantic coast location, Europe would be the logical market for the exports. NFE has said it expects to bring online more than half of the world’s total expected LNG capacity additions during the 2023-2024 period. At Lakach, NFE said it will provide upstream services to Pemex. This would include producing natural gas and condensate in exchange for a fee for every unit of production delivered to Pemex. The fee would be based on a contractual formula based on industry-standard gross profit-sharing agreements. NFE would also have the right to purchase volumes for its FLNG unit, while Pemex plans to sell the remaining natural gas volumes and all of the produced condensate to its customers onshore.

Treasury Department releases guidelines for Russian oil transport ahead of planned price cap - The Treasury Department issued new guidance Tuesday about policies on the maritime transport of Russian oil ahead of a planned price cap in early December.The guidance, which complements the U.K.'s newly-released policies, outlines how U.S. service providers can continue carrying Russian seaborne oil that was loaded before Dec. 5, while complying with a strategic price capon that oil devised by the G7 countries, the E.U. and Australia. That so-called Price Gap Coalition is aiming to deprive Russia of a funding source to continue its war against Ukraine.A senior Treasury official told reporters Tuesday that the department expects other coalition countries to release similar guidance in the coming days in order to implement the price gap policy."We're taking these steps to make it as easy as possible for market participants to implement the price cap policy as of Dec. 5 consistent with the coalition's goals of allowing Russians to keep foreign oil (in) flow while lowering the Kremlin's revenues," the official said.Shipping and customs brokering are among several services covered under an executive order addressing the transport of Russian oil by sea. The guidance says service providers will not be financially penalized for the transport of crude oil of Russian origin loaded and shipped prior to 12:01 a.m. ET on Dec. 5 and unloaded at the destination port prior to 12:01 a.m. ET on Jan. 19.The guidance also outlines a "safe harbor" from enforcement for providers who follow a recordkeeping and attestation process showing the oil was purchased at or below the price cap.Russian oil imports are banned from the U.S. under the policy, which takes effect Dec. 5.Treasury officials said they have already seen evidence of the redirection of the product from U.S. and European markets, which are no longer in the market for Russian oil.

Biden Requests $500MM for Strategic Petroleum Reserve --In a letter outlining President Biden’s request for 2023 emergency supplemental funding “for critical assistance to Ukraine and critical response activities to address Covid-19”, a sum of $500 million has been earmarked for the U.S. Strategic Petroleum Reserve (SPR). “This request would provide the Department of Energy, Energy Security and Infrastructure Modernization Fund account $500 million for modernization activities of the four Strategic Petroleum Reserve sites,” the letter, which was sent from the Office of Management and Budget (OMB) to the Speaker of the United States House of Representatives Nancy Pelosi, stated. “The proposal would allow the SPR to both maintain operational readiness levels and also alleviate anticipated shortfalls due to supply chain issues, the Covid-19 pandemic, and related schedule delays,” the letter added. In the letter, which was sent last week, OMB Director Shalanda Young said the Biden administration looked forward to continued engagement with members of both parties to reach a comprehensive, bipartisan agreement to fund the government for the rest of the fiscal year and invest in critical national priorities before the December 16 funding deadline. “As part of that process, the Congress has an opportunity and obligation to address three additional and critical funding needs that should earn bipartisan support: protecting the American people from Covid-19 and saving lives globally; supporting the people of Ukraine; and helping communities across the Nation recover from devastating natural disasters,” Young stated in the letter. Earlier this month, the DOE announced that contracts had been awarded for the purchase of crude oil from the SPR following a notice of sale announced on October 18. These contract awards completed Biden’s announcement on March 31 to release 180 million barrels of crude oil “to address the significant global supply disruption caused by Putin’s war on Ukraine, act as a wartime bridge for domestic production to increase, and aid in lowering energy costs for American families”, the DOE noted.A total of 12 companies responded to the notice, submitting 110 bids. Contracts were awarded to the following companies:

  • Equinor Marketing & Trading 1.750 million barrels
  • Macquarie Commodities Trading US LLC 1.850 million barrels
  • Marathon Petroleum Supply and Trading LLC 2.950 million barrels
  • Phillips 66 Company 0.350 million barrels
  • Shell Trading (US) Company 0.700 million barrels
  • Valero Marketing and Supply Company 7.450 million barrels

Biden gives Chevron permit to restart Venezuelan oil sales - The Treasury Department granted permission Saturday for oil giant Chevron to produce and export oil from Venezuela following the South American country’s decision to restart talks with opposition groups. The move could add supply to the global oil market, which may ease fuel prices and speed the declines in U.S. gasoline prices that have been a political burden for President Joe Biden since Russia invaded Ukraine in February. But a senior administration official said the easing of sanctions was not driven by the oil market pressures and was instead a response the Venezuelan regime’s decision this week to participate in the negotiations with opposition groups. Those talks, which were originally launched in Mexico City in September 2021, are expected to focus on humanitarian programs and setting future elections. “This action is not being taken in response to energy prices, this is a limited license. As we have said in the past, this is about the regime taking the steps needed to support the restoration of democracy in Venezuela,” the official said. The oil supplies affected under the new license would have likely have gotten to customers via the black market, the official said. The decision to allow Chevron to resume shipments from the South American nation comes ahead of a Dec. 5 deadline for tightened sanctions on Russia that could roil the world’s oil markets. The G-7 and European Union are moving to restrict Russian petroleum exports and impose a price cap on petroleum sales. Under the expanded license issued by Treasury’s Office of Foreign Assets Control, the Venezuelan state oil company, PdVSA, is prohibited from receiving profits from the oil sales generated by its joint venture with Chevron. It keeps in place broader sanctions on PdVSA. The moves by Venezuela’s Maduro regime to restart talks with the opposition “are important steps in the right direction to restore democracy in the country,” Treasury said, which the U.S. welcomes “as part of our longstanding policy to support the peaceful restoration of democracy, free and fair elections, and respect for the rights and freedoms of Venezuelans.” Venezuela sits on some of the biggest oil reserves in the world, but mismanagement of the oil sector by the government and sanctions imposed by the U.S. has sharply cut its exports.

How the U.S. became a global leader in LNG – and why Canada has fallen behind - As Highway 27 winds around Calcasieu Lake in southwest Louisiana, massive storage tanks tower over the wetlands in what is shaping up to be a new global epicentre for exports of liquefied natural gas. Near the town of Hackberry, Cameron LNG is eyeing expansion of its already-huge terminal, which opened in 2019. Along the highway and down other roads, there are three new proposed export terminals fronting the lake, which is just south of the small city of Lake Charles. One, Driftwood LNG, has more than 200 people working on early-stage site preparation. Driving south toward the Gulf of Mexico, there are four proposed LNG sites near the mouth of the Calcasieu River. At least a dozen LNG proposals are now in the works statewide in Louisiana. Eight projects are near Lake Charles in the southwest, all vying to join the three export terminals already operating in the state. U.S. LNG production and exports were already rising when the invasion upended global energy markets. And activity has ramped up even faster as Europe scrambles to reduce its dependence on natural gas from Russia. The boom along the Gulf Coast stands in stark contrast to an LNG industry in Canada that finds itself stuck in a holding pattern. The Shell PLC-led LNG Canada project in Kitimat, B.C., is the only export terminal under construction in the country, even though Canada is the world’s sixth-largest producer of natural gas. The differences are particularly striking between Louisiana, where politicians enthusiastically back LNG, and British Columbia, where new NDP Premier David Eby is under political pressure to do more to fight climate change. In 2013, there were more than 20 LNG proposals in B.C., but at the start of 2016, there weren’t any terminals exporting LNG from either Canada or the U.S. By 2019, most of the B.C. proponents had dropped out, unable to make the economics work. LNG Canada’s $18-billion terminal is slated to begin shipping at a rate of 14 million tonnes of LNG a year to Asia in 2025, when it would become Canada’s first export terminal. But in the first half of this year, the U.S. became the world’s top LNG exporter, edging ahead of Qatar and Australia. The U.S.’s current LNG export capacity is about 90 million tonnes a year. When push comes to shove – and Gulf Coast LNG exporters have plenty of local opponents – the sector has prevailed. In just six years, the U.S. has become a global powerhouse in exporting the fuel, bolstered by the shale gas revolution. The global realities of Europe’s energy crisis have sparked a U.S. LNG renaissance. And federal, state and local politicians in Louisiana express unabashed support for LNG. Canada lags for several reasons, and one of the biggest is politics. Canadian leaders vow to keep climate goals top of mind. They already cite the need to eventually transition from LNG to hydrogen, and request that any new LNG projects rely on hydroelectricity in the liquefaction process instead of using traditional turbines fired by natural gas.

Why cheap US gas costs a fortune in Europe – The EU is under immense pressure to cap the price of imported natural gas to contain energy costs — but many of the companies making a fortune selling cheap U.S. gas to the Continent at eye-watering markups are European.The liquefied natural gas (LNG) loaded on to tankers at U.S. ports costs nearly four times more on the other side of the Atlantic, largely due to the market disruption caused by a near-total loss of Russian deliveries following the invasion of Ukraine. The European Commission has come under fierce pressure to sketch out a gas price cap plan, but some countries, led by Germany, worry such a measure could prompt shippers to send gas cargoes elsewhere. The Commission is also reluctant, and its proposal issued Tuesday sets such demanding requirements that they weren’t met even during this summer’s price emergency. Share on Twitter Share on Linkedin Share on WhatsApp Mail Print PRESS PLAY TO LISTEN TO THIS ARTICLE 0:00 Voiced by artificial intelligence. The EU is under immense pressure to cap the price of imported natural gas to contain energy costs — but many of the companies making a fortune selling cheap U.S. gas to the Continent at eye-watering markups are European. The liquefied natural gas (LNG) loaded on to tankers at U.S. ports costs nearly four times more on the other side of the Atlantic, largely due to the market disruption caused by a near-total loss of Russian deliveries following the invasion of Ukraine. The European Commission has come under fierce pressure to sketch out a gas price cap plan, but some countries, led by Germany, worry such a measure could prompt shippers to send gas cargoes elsewhere. The Commission is also reluctant, and its proposal issued Tuesday sets such demanding requirements that they weren’t met even during this summer’s price emergency. But a large part of the trade is in European hands, according to America's biggest LNG exporter. "Ninety percent of everything we produce is sold to third parties, and most of our customers are utilities — the Enels, the Endesas, the Naturgys, the Centricas and the Engies of the world," said Corey Grindal, executive vice president for worldwide trading at Cheniere Energy, rattling off the names of big-name European energy providers. Cheniere, which this year saw 70 percent of its exported LNG sail to Europe, sells its gas on a fix-priced scheme based on the American benchmark price, dubbed Henry Hub, which is currently at about $6 per million British thermal units. On average, the price across all Cheniere contracts is 115 percent of Henry Hub plus $3, Grindal said. That works out to about €33 per megawatt-hour. For comparison, the current EU benchmark rate, dubbed TTF, is €119 per MWh. It's a big markup for whoever is reselling those LNG cargoes into Europe's wholesale market, profiting from fears that there may not be enough gas to last the winter. Despite fears that any EU cap will send gas to higher bidders in Asia and result in bloc-wide shortages, Grindal gave a resounding "no" when asked if a cap would have any impact on how Cheniere does business with European companies.

Russia-Ukraine War, Fracking Turn America Into The World's 4th Largest Crude Oil Exporter -- The rise of the fracking industry and the persistence of the Russia-Ukraine war have helped the U.S. economy become the 4th largest exporter of crude oil in the world in 2022.That's according to Athens-based oil analyst and a Greek Chamber of Commerce member Theophanis Matsopoulos. "The total U.S. energy products exports in 2021 were 134 million tons," he told International Business Times in a phone interview. "In the first nine months of 2022 alone, exports skyrocketed to 120 million tons."Matsopoulos believes that the critical driver behind these export gains is the tension between the European Union (EU) and Russia regarding the war in Ukraine, which pushed the EU to find alternative fossil fuel suppliers to cut the long-lasting energy dependence on Russia."The war resulted in Europe becoming a significant energy importer of U.S. oil, accounting for 42% of the total U.S. exports, showing an increase of 52% on a y-o-y basis," Matsopoulos added. "In comparison, 45% of the exports went to the Asian markets."Matsopoulos thinks that this rapid expansion of America's exports could give the world's largest economy the title of the "global winner of the oil war," reaffirming its strategic leadership position since the Second World War. "The increased supply of oil to the global market combined with the provision of quantities to the EU has recharged the relationships of the superpower with many allies, especially those in Europe," he said.Kunal Sawhney, chief executive officer of Kalkine Group, provides further insight into the meteoric rise of U.S. energy exports. "After Russia invaded Ukraine, the U.S. oil industry sprang into action, pressuring the Biden administration to allow domestic drilling and relax certain regulations so that companies can extract more oil," he told IBT. "The sector is now trying to capitalize on and tap the market created by Russian isolation. As a result, more companies are asking the government to allow drilling on public land by easing regulations to expand the market."Still, the improvement in the U.S. trade balance that followed the surge of energy exports is a mixed blessing for the U.S. economy. On the positive side, the narrowing of the trade deficit helped the U.S. economic growth come out better than expected in the third quarter, preventing the world's largest economy from sliding into a recession. However, on the negative side, strong energy exports helped keep energy prices elevated, feeding into the surge of inflation that has been squeezing family budgets in the last year.

UK Oil And Gas Companies Face $24 Billion Well-Plugging Bill -UK oil and gas companies are facing a bill of some $24 billion, or 20 billion pounds, for plugging unused wells, Reuters has reported, citing figures from Offshore Energies UK, the industry body.There are more than 2,000 old wells and related facilities that would need to be put out of commission over the next ten years. What’s more, the bill will swell particularly fast in the next three to four years, OEUK said, as more and more wells will be shut down.The average cost of decommissioning a well is around 7.8 million pounds, according to the industry body, or more than $9.2 million.This will put an additional expense burden on North Sea producers who were just slapped with a 10-percent increase in their windfall profit tax, which will see them pay 35 percent in taxes on their earnings.According to Reuters, oil production in the UK’s North Sea shelf peaked at some 4.4 million barrels daily in the 1990s and has been in a steady decline since then, not least because of political pressure to reduce the country’s oil and gas production.Interestingly, an earlier report by the OEUK from this month said that the UK needs more oil and gas exploration to enhance its energy security and move the transition forward.“The waters off the coast of the UK still contain oil and gas reserves equivalent to 15 billion barrels of oil equivalent (boe), enough to fuel the UK for 30 years, but more investment in exploration is needed to slow down the decline in domestic production to safeguard the nation’s energy security,” the report said.The report’s authors added that more oil and gas production will also help move the transition along through the industry’s commitment to reducing emissions to net zero by 2050

North Sea Authority Launches Another Investigation --The North Sea Transition Authority (NSTA) has revealed that an investigation has been launched into an unnamed oil and gas company “for flaring and venting in the North Sea without consent”. The NSTA outlined that its probe could result in action being taken, including a fine for the company or even the relevant license “being taken away”. Compliance with consents is both an indicator of good management of fields by licensees and a vital pillar of a company’s social license to operate, the NSTA noted, adding that monitoring flaring and venting and reducing emissions are vital parts of the NSTA’s work to help the UK Government meet the net zero target. The NSTA introduced a net zero stewardship expectation in March 2021, which requires operators to show their commitment to reducing greenhouse gases throughout the project lifecycle. A tougher approach to flaring and venting was subsequently set out in updated guidance, the NSTA highlighted. This provided details of the NSTA’s intent to use its consenting regime to drive reductions and, where possible, eliminate both processes, the NSTA noted. “The NSTA is committed to holding industry to account on emissions to ensure progress continues and is prepared to take action where we suspect a company’s actions risk compromising efforts to meet and surpass agreed targets,” Jane de Lozey, the NSTA’s Interim Director of Regulation, said in an organization statement. Rigzone has asked industry body Offshore Energies UK (OEUK) for comment on the NSTA’s latest investigation. At the time of writing, the NSTA has not yet responded to Rigzone’s request. Venting is the discharging of gases into the atmosphere, while flaring is the burning of gases before they are discharged. These processes are required for safety and operational reasons, the NSTA said, but added that more can be done to reduce the amount. Earlier this month, the NSTA announced that it had opened an investigation into an operator “suspected of breaching one of its license conditions”. The organization also revealed recently that a separate investigation had been opened into whether a company, which was awarded a license in the 28th Licensing Round in 2014, had failed to comply with several obligations, including drilling an exploration well and shooting a 3D seismic survey. In April, the NSTA announced that it had fined Shell UK Limited $62,347 (GBP 50,000) and served it with a sanction notice for breaching five field production consents. In July last year, the NSTA, then named the Oil and Gas Authority, announced that it had fined BP $62,346 (GBP 50,000) and served it with a sanction notice for breaching a license condition by failing to report the progress and results of two extended well tests.

Norway’s oil & gas output slightly higher in October - Even though Norway saw a slight increase in oil and gas production in October compared to the figures from September 2022, these figures are still below the Norwegian Petroleum Directorate’s predictions. In addition, they are lower than the ones recorded last year. Preliminary production figures for October 2022 show an average daily production of 1 913 000 barrels of oil, NGL and condensate, based on the NPD’s report on Tuesday. Total gas sales were 9.8 billion Sm3 (GSm3), an increase of 0.7 (GSm3) from the previous month. Average daily liquids production in October was: 1 745 000 barrels of oil, 187 000 barrels of NGL and 19 000 barrels of condensate. Oil production in October is 7.3 per cent lower than the NPD’s forecast and 5.4 per cent lower than the forecast so far this year. The forecasts for gas and NGL have been updated in line with the government’s prognosis for production in the revised national budget.’BP Rotterdam Oil Refinery, Europe’s Second-Biggest, Suffers Serious Incident - The BP refinery in the port of Rotterdam, The Netherlands suffered a serious incident this week at its Rotterdam refinery, Europe’s second-biggest oil-processing plant, according to the Dutch union CNV. The complex in the heart of Europe’s oil-trading hub has all but stopped fuels production and employees at the plant who had started work-to-rule action this week have called it off for now.

Equinor and partners to invest $1.44 bln in Arctic gas field (Reuters) - Norway’s Equinor and its partners on Tuesday said they will invest 14.8 billion Norwegian crowns ($1.44 billion) to develop the Irpa gas discovery in the Norwegian Sea. The subsea project aims to produce about 20 billion cubic metres of natural gas for exports to Europe, sending it via the Aasta Hansteen platform some 80 kilometres (50 miles) east of Irpa, the partnership’s development plan showed. The water depth of around 1,300 metres (4,300 feet) makes Irpa, previously known as Asterix, one of the deepest finds to be developed offshore Norway and the country’s fourth producing petroleum field north of the Arctic circle. Production is expected to start in the final quarter of 2026 and last until 2039, the development plan showed. Equinor, the field’s operator, has a 51% stake in the Irpa license, with state-owned Petoro holding 20%, Wintershall Dea 19% and Shell 10%.

Sweden finds explosive traces at Nord Stream blast sites, confirms sabotage — The mysterious blasts in September that made the largest-capacity natural gas pipelines from Russia to Europe inoperable were caused by “gross sabotage,” Swedish authorities confirmed Friday, noting that traces of explosives have been found as part of the ongoing investigation.Prosecutor Mats Ljungqvist and the Swedish Security Service reported that their examination of the Nord Stream 1 and 2 pipelines in the Baltic Sea has documented “extensive damage” and revealed several “foreign items” — some with detectable “explosive residue.”But the statements did not address the key questions of the months-old mystery: Who is responsible? And how did they go about it?“The advanced analysis work is still in progress — the aim is to draw more definitive conclusions about the Nord Stream incidents,” the Security Service statement said. “The investigation is extensive and complex and will eventually show whether anyone can be suspected of, and later prosecuted for this.”The blasts occurred south of the Swedish mainland, east of the Danish island of Bornholm. Multiple investigations are underway, with Danish and German authorities also collecting evidence.European officials began using the term “sabotage” within hours of the simultaneous blasts in late September. Seismologists said the datapointed to explosions, not naturally occurring earthquakes or landslides.“These are deliberate actions, not an accident,” Danish Prime Minister Mette Frederiksen told reporters on Sept. 27. “The situation is as serious as it gets.”European leaders pointed to Russia as the only actor with the technical capability and motivation to damage the Nord Stream pipelines with underwater explosions.

Russian gas pipeline explodes near St. Petersburg, video shows - An explosion erupted in a gas pipeline outside St. Petersburg in Russia Saturday, according to a social media post by the governor of the Leningrad Region. "Firefighters and rescuers extinguish a fire caused by a gas pipeline depressurization between Berngardovka and Kovalevo," Gov. Alexander Drozdenko said on Telegram. "There is no threat to the population and the spread of fire to residential areas."The governor said the exact cause of the fireball that emerged in videos on social media was still being investigated. No suggestion of sabotage has been mentioned and Russia’s Ministry of Emergency Situations said the explosion was likely the result of "depressurization" in pipeline, which officials have further reduced to stop the fire, Russian media outlet RIA reported.Explosion on pipeline in Leningrad, Russia outside of St. Petersburg. (Reuters )Drozdenko said that emergency crew members allowed the gas to burn off and "are getting ready to start repairing the gas pipeline."The governor also looked to assure local residents and said despite the alarming footage circling social media – including videos that showed a substantial fireball and burn site following the loud explosion – the surrounding forest areas were likely not in danger from the fire spreading. Drozdenko said the Vsevolozhsk thermal power plant has been "switched" to supply oil instead of gas to "ensure uninterrupted heat supply."No casualties in the blast or ensuing fire have been reported, according to the local governor.

EU Leaders Unveil ‘Safety Ceiling’ to Protect Against Volatile Natural Gas Price Swings - The European Commission (EC) has proposed a bloc-wide ceiling on natural gas prices linked to Europe’s benchmark in an effort to stanch massive financial volatility, potentially sending ripple effects across global gas markets. In a proposal outlined by the European Union’s (EU) executive branch Tuesday, the Commission could institute a “safety price” mechanism by the beginning of the year that would allow regulators to order financial institutions not to accept prompt month gas purchases that exceed the emergency price ceiling. The mechanism would be triggered if the prompt Dutch Title Transfer Facility (TTF) price rises above 275 euros/MWh, or about $83/MMBtu, for more than two weeks. The mechanism would also be triggered if TTF prices are 58 euros or roughly $60 more than the LNG reference price for deliveries on the continent. European Energy Commissioner Kadri Simson said the policy was “carefully designed” to prevent extreme price volatility while securing the European Union’s ability to keep attracting natural gas supply. “Gas prices in the EU have fallen since August thanks to demand reduction, mandatory storage filling, diversification of supplies and other measures proposed by the Commission in recent months,” Simson said. “But we have been missing in our toolkit a way to prevent and address episodes of excessively high prices. Today, we propose to put a ceiling on the TTF gas price to protect our people and businesses from extreme price hikes.” TTF prices have remained well above historical averages since the end of last year, but they’re currently trading below the proposed threshold. Since Russia began curtailing pipeline flows to the continent and buyers have scrambled for supplies throughout the year, prices have at times surged above $100. At a previous emergency meeting in October, 15 of the 27 EU member countries including France, Italy, Poland and Spain supported some type of price cap. Other countries like Germany, Ireland and the Netherlands opposed the idea. German and Dutch officials have specifically questioned a price cap’s potential impacts on securing supplies and competing with other international buyers for LNG cargoes. To limit a potential freeze on Europe’s ability to secure cargoes, the EC said the policy was specially applied only to TTF futures and only when extreme prices were sustained over a period of time. The Commission also included proposals to deactivate the ceiling by an EC decision if the policies are deemed to impact financial stability or EU gas flows. Policymakers wrote that “market operators will still be able to meet demand requests and procure gas” while the ceiling mechanism is activated by going to the spot market and using over-the-counter (OTC) transactions. In a letter voicing opposition to a price cap, members of the Association of European Energy Exchanges, aka Europex, wrote the shift would cause even more instability during a time of crisis. “If the real price of gas exceeds the artificially capped price of the TTF front-month future, market participants will immediately move trading into the bilateral OTC space,” said Europex Secretary General Christian Baer. “Such a move would not only lead to a significant decrease in transparency, but also poses serious financial stability risks.”

Goldman Explains Why The Only Good Thing About EU's Proposed NatGas Cap Is That It's Unlikely To Ever Be Triggered - In a note to institutional clients Wednesday morning, Goldman Sachs analysts argued that the European Union's long-awaited natural gas price cap plan won't solve the continent's energy shortfall and could make things a whole lot worse. "We have argued that caps to retail gas (and electricity) prices without an associated cap to demand would not only not solve the gas deficit in Europe but would also risk making this deficit worse by incentivizing incremental gas consumption vs what we would observe without caps," analysts Samantha Dart, Daniel Moreno, Jeffrey Currie, and Annalisa Schiavon wrote in the note. They said the EU's proposed price cap for Dutch NatGas benchmark TTF of around 275 euros (~$272) per megawatt hour would spark even more market gyrations, something we noted yesterday. However, they were confident the cap wouldn't be triggered. Even though the EU might have put a lot of thought into its failsafe plan to shield households and businesses from soaring NatGas prices this winter, Goldman's top commodity analysts listed some of the top reasons the cap would likely perpetuate the crisis:

  • 1. Further reducing liquidity in an already liquidity-poor market. Triggering the cap would reduce the expected reliability of the price signal offered by the exchange, hence incentivizing trade flows to move away from the exchange and to over-the-counter (OTC) markets.
  • 2. Increased risk of a reduction in gas supply. The proposed price cap is supposed to be applied to prompt contracts. As a result, should the cap be triggered, gas suppliers would be incentivized to, at the margin, reduce volumes sold in the next month in favor of volumes further out in the forward curve, at non-capped gas prices. This can exacerbate near-term tightness in the market.
  • 3. Disruption of commercial settlements and risk management. A cap would potentially impact settlement prices for existing contracts and the value of existing hedges. This can interfere with the effectiveness of risk-management policies by market participants, either by de-valuing previously layered hedges (and hence, de-valuing the companies that acted to protect themselves against higher gas/electricity prices) or by discouraging future hedges.

The one positive component of this price cap proposal in our view is that we see the elevated threshold required to trigger it as unlikely to be met: both TTF reaching 275 EUR/MWh sustained for two weeks and the TTF Spot - LNG price spread reaching 58 EUR/MWh sustained for 10 days. Neither condition has been met this year, and neither is in our base case for 2023.Importantly, we note that, h owever unlikely, there are fundamental developments that could lend enough support to TTF gas prices to trigger the cap. As we discussed recently , a one-standard-deviation colder-than-average remainder of winter could take Sum23 TTF prices to 250 EUR/MWh. If any meaningful LNG supply disruption, like the ongoing 60 mcm/d Freeport outage, is added to such a scenario, the 275 EUR threshold could easily be reached. So with a price cap so high, the analysts noted, "the only good thing about the proposed TTF cap is it's unlikely to be triggered."

Europe's gas price cap leaves some nations dismayed, saying it's far too high - Several EU member states are not happy with the bloc's proposed cap on natural gas prices — at 275 euros per megawatt hour — which aims to prevent sky-high costs for consumers.Introducing a cap on gas prices has been one of the more controversial measures for Europe amid an acute energy crisis following Russia's invasion of Ukraine.The 27 EU leaders gave political backing to the idea in late October, after several months of discussions. But, a handful of nations are demanding concrete safeguards before greenlighting the proposal, while others say the cap is too high."A price cap at the levels that the commission is proposing is not in fact a price cap," Kostas Skrekas, Greece's environment and energy minister, told CNBC's Julianna Tatelbaum Tuesday, hours after the proposed level was set by the European Commission, the executive arm of the EU."So [a] price cap at 275 euro is not a price cap, nobody can, can stand buying gas at this expensive price for a long time. We surely believe that the price cap below 200 euro, between 150 and 200 euro would be more realistic," he added.EU energy ministers are due to meet Thursday to debate the price cap proposal.Poland, Greece, Belgium and Spain are among the nations supporting the cap. The Netherlands and Germany have been more skeptical about the benefits of the measure. Presenting a cap that looks tough to implement, in practice, could be a way for the European Commission to bring all the 27 nations together on the issue."It will be a meeting with grumpy people," an EU official, working for one of the member states and who preferred to remain anonymous due to the sensitive nature of the discussions, told CNBC regarding the upcoming meeting.The same official said the commission needs to present further guarantees on how the measure will not distort markets.Speaking at a press conference Tuesday, Kadri Simson, the European commissioner for energy, said the proposal is "balanced" and it will help the bloc avoid excessively high prices.

Did the Ukraine War kill 'Natural Gas?' Solar Power is 10 times Cheaper over the long Term --The independent energy research firm Rystad Energy, headquartered in Oslo, has found that it would be ten times less expensive over the long run to install solar farms than to continue to operate gas-fired electricity plants in Europe. Although the Ukraine War has been good for petroleum and fossil gas prices and sales in the short term, future historians may see it as the nail in the coffin of hydrocarbons. Countries such as Germany that grew dependent on Russian fossil gas are now deeply regretting it. They are trying to turn quickly to Liquefied Natural Gas, for which they are putting in terminals, since that can be shipped by sea.There is not, however, at the moment very much elasticity in the global supply of fossil gas, so that prices may remain high. Those high prices are one cause for the increasing relative affordability of new wind and solar plants. Geopolitical considerations now also play a role in making the move to solar more urgent. Germany cannot afford to depend on outside suppliers, whether Russia or Algeria, for so vital a sector of its economy, since the world of hydrocarbons is volatile and prone to wars and disruptions.The spike in fossil gas prices this summer and fall in Europe is unprecedented. At one point in August it was about $730 per megawatt hour. That is ten times more than the levelized cost of solar. Rystad estimates that the gas price will settle at $156 per MWh in the medium term, which is three times the levelized cost of solar. Unless you like wasting money, the conclusion is clear. You’d be crazy not to put in a lot of new solar.And Europeans clearly recognize this reality. Rystad says that 50 gigawatts of new wind and solar are planned to be commissioned in 2023.It is estimated that existing wind and solar installations, which are up 13% over 2021, saved Europe $11.46 billion this spring and summer over fossil gas.Rystad makes an interesting proposal. Divert money from fossil gas and invest it in solar farms instead. By 2028 your investment will have more than paid for itself, they conclude.

EUROPE GAS-Prices rise on concerns about imports from Norway, United States -(Reuters) - British prompt gas prices rose on Tuesday morning amid increased supply concerns as Norwegian flows dropped and markets embraced for further delays in the restart of Freeport LNG, one of the biggest U.S. export facilities for liquefied natural gas. The Dutch the benchmark front-month contract TRNLTTFMc1 traded up 2.20 euros at 116.80 euros/MWh by 0958 GMT, according to Refinitiv Eikon data. The British within-day contract TRGBNBWKD rose by 8 pence to 118 pence per therm, and the day-ahead contract TRGBNBPD1 was up by 0.50 pence at 112 p/therm, according to Refinitiv Eikon data. U.S. company Freeport LNG has not yet submitted a full request to the authorities to restart a Texas plant, a source said on Monday, raising questions about its ability to meet restart timeline. The company was targeting a mid-December restart for the exports plant which has been shut for six months after a fire. Refinitiv analysts said the gas prices were supported by "news of colder weather spiking U.S. gas prices to a two-week high and that Freeport LNG has not yet submitted a full request to restart a Texas plant could increase risk to EU LNG supplies." UK temperature was below seasonal normal on Tuesday, according to Refinitiv analysts, increasing demand for heating. Norwegian gas nominations to Britain also dropped from 74 millions of cubic metres (mcm) per day on Monday to 66 mcm per day on Tuesday, supporting the prices. Britain's gas system was around 26 mcm under-supplied on Tuesday, with supply forecast at around 278 mcm and demand at around 304 mcm, National Grid data showed. Peak wind generation in the UK is forecast at around 10 gigawatts (GW) on Tuesday, but was expected to increase to around 14 GW on Wednesday, Elexon data showed. Strong wind power output curbs demand from gas-fired power plants. The market was also keeping an eye on the European Commission's proposal for a gas price cap which will be debated by energy ministers from the bloc's 27 member countries on Thursday. "The market is clearly in a wait-and-see position ahead of announcements on EU energy measures on 24 November," Engie EnergyScan analysts said. Europe's gas stocks were 95% full, according to latest data from Gas Infrastructure Europe, down from a peak of 95.61% on Nov. 13. In the European carbon market, the benchmark contract CFI2Zc1 was down 1.07 euros at 73.54 euros a tonne.

Forecast warmer November to limit Asian spot LNG demand - Northeast Asian countries are facing higher than usual LNG inventories ahead of winter, resulting in expectations of limited incremental spot LNG demand throughout their typically high-demand winter season. Higher than usual temperatures at the onset of winter have likely curbed LNG consumption for power generation to meet heating needs during the month, limiting regional inventory drawdowns. South Korean LNG inventories for November are at an all-time high, much higher over the same period compared with the past three years, according to data from Korea Electricity Statistical Information System. Japan's main utilities had 2.52mn t of LNG stocks as of 13 November, which was higher by 16.7pc from 2.16mn t at the end of November 2021 and higher by 29.2pc against 1.95mn t, the average of end-November stocks during 2017-21. The latest update on Japan's inventories this week was unavailable with a public holiday on 23 November. South Korea's state-owned LNG importer Kogas has requested at least one Japanese utility for temporary storage space over 2-3 days to manage its high inventories, underscoring the extent of the surplus that the country is currently facing. A Chinese national oil company (NOC) is also currently considering delaying the arrival of some of its scheduled deliveries over the next few days, which will likely put off its purchasing plans for the rest of the winter. This may imply that the gas supply glut in China may be more severe than previously expected. High inventories in China have also seen several offers for domestic swaps between gas companies and utilities in the past 1-2 weeks as they attempted to manage higher than expected inventories. The need to keep inventories at at least 80pc full by the end of October, according to regulations laid out by China's main economic planning agency the NDRC, coupled with weaker than expected gas demand with continued small-scale rolling Covid-19 lockdowns has further exacerbated the supply glut in China.

Economy and finance ministers renew quarrel over gas fracking in Germany -Germany’s economy ministry has renewed its rejection of the controversial "fracking" method to produce natural gas, in response to a call by the finance ministry to allow using the technology in Germany. “This does not lead to a sensible answer,” Green Party economy minister Robert Habeck said at a conference in Berlin, according to a report in Süddeutsche Zeitung. He added the technology would lead to all sorts of problems, and pointed to the south of England, where it had led to earthquakes and a subsidence of the ground. Free Democrat (FDP) finance minister Christian Lindner said at the same conference he was in favour of using the technology because it could make a substantial contribution to the country’s future energy security and competitiveness. Habeck acknowledged that it was not fair in principle to buy fracked gas from the U.S., while rejecting the technology at home. But he added the debate was “not helpful” given the particular circumstances in Germany, which included high costs, necessary changes in the law and public resistance.The energy crisis has revived the debate over the controversial gas extraction method known as unconventional hydraulic fracturing – or simply fracking – as the country looks for alternatives to Russian supply. Hydraulic fracturing produces fractures in the rock formation to stimulate the flow of natural gas and increase the volumes that can be recovered. However, it does so by using chemicals and high amounts of pressure, which can lead to environmental damage.There is significant opposition to the technology in Germany. Federal and regional governments in key states have made it very unlikely that the country will allow it even in the current crisis. As a result, it would likely take years until fracked gas could make a meaningful contribution to the country’s energy mix - meaning it will be of little help in the current energy crisis. Habeck and Lindner led similar arguments for months over the future use of nuclear energy in Germany, with Lindner in favour and Habeck against. In the end, chancellor Olaf Scholz intervened to settle the dispute with a limited runtime extension for the remaining nuclear plants.

Moldova accuses Russia of energy blackmail, 'ready for any scenario' (Reuters) - Moldova said on Wednesday Russia had sent no signals that it would stop supplying it with gas next month but that it was ready for any scenario because Moscow was using energy resources as "a tool of blackmail". State-run Russian gas company Gazprom GAZP.MM accused Ukraine on Tuesday of keeping gas supplies destined for Moldova, and that it could from Nov. 28 start reducing gas supplies to Moldova that pass through Ukraine. Ukraine, which has been invaded by Russia, has denied withholding Russian gas meant for Moldova. Chisinau, which is dependent on Russia for its gas, said on Wednesday it would pay for any gas deliveries. "There are no signals that Russia will stop supplying gas to Moldova in December. But the government is ready for any scenario, as Russia continues to use energy resources as a tool of blackmail," Prime Minister Natalia Gavrilita told PRO-TV television. Dismissing Gazprom's accusations, Moldovan Deputy Prime Minister Andrei Spinu said on the Telegram messaging app: "Gazprom accuses Ukraine and Moldova of something that is not happening." Moldovan President Maia Sandu said on Monday her country could face a harsh winter because of an "acute" energy crisis that risked stoking popular discontent, with Russia's war in Ukraine threatening energy supplies and pushing up prices. Moldova, a former Soviet republic, has also taken in more re Ukrainian refugees per head than any other country. Although it has strong historical and linguistic ties to neighbouring European Union member Romania, Moldova relies exclusively on Gazprom for gas imports and is largely dependent on Russian energy. Spinu said Moldova had reserved more than 200 million cubic meters of gas in Ukrainian storage facilities for the winter.

Gazprom May Cut Supplies Via Ukraine This Month --Russia’s Gazprom has said it may cut supplies via Ukraine from November 28, Rystad Energy’s Senior Analyst Wei Xiong highlighted in a market note sent to Rigzone late Wednesday. Xiong outlined in the note that the threat comes in the wake of Russia alleging Ukraine is diverting gas supplies intended for Moldova. Ukraine denies this, Xiong pointed out. “After Russia halted all flow via the Nord Stream 1 pipeline in September, Europe has been receiving Russian gas through just two pipelines - the Ukraine transit route and via TurkStream, with flows at 42 million cubic meters per day (MMcmd) and 26 MMcmd, respectively,” Xiong said in the note. “Supplies to Europe would be further reduced if flows via Ukraine are halted. However, the impact on prices would likely be muted given that the market has largely factored in the risk that Russian flows to Europe could drop to zero,” Xiong added. In the note, Xiong highlighted that temperatures in Europe turned colder over the weekend but said they have since risen above average again. Despite this, there is an increasing possibility that winter temperatures will drop below average as December approaches, Xiong warned. “This means Europe’s high gas stocks may start to see withdrawals in the coming weeks, lending support to TTF forward prices with the rate of withdrawal impacting the trend for LNG prices,” Xiong said. “EU storage capacity is nearly 95 percent full, with Germany flat at 99 percent and UK inventories also flat at 100 percent of capacity,” Xiong added. To prepare for the winter season, Europe has continued importing high volumes of LNG through November, Xiong said, adding that the region’s regasification capacity now running at about 90 percent utilization.

Gazprom Threatens To Curb European Gas Flows Through Ukraine - Russia’s Gazprom said on Tuesday it could begin reducing natural gas supply to Europe via Ukraine as of next Monday after noticing that part of the volumes through Ukraine are not reaching Moldova. Russia still sends some gas via pipelines to Europe, via one transit route through Ukraine and via TurkStream. Additional reduction in volumes would come just as temperatures in Europe dipped to seasonal or below-seasonal levels after warm October and early November allowed the EU to fill up its natural gas storage.Now Gazprom says that it has noticed some of the gas intended for Moldova under a contract with the local gas firm is being diverted by Ukraine. If the imbalance in gas transit continues, Gazprom will start reducing gas flows via Ukraine on the morning of November 28, the Russian gas giant said today, as carried by Russian news agency TASS.Europe’s benchmark gas prices rose by 2% after Gazprom’s announcement on Tuesday.Europe is more or less prepared to face this winter with nearly full gas storage sites and a steady flow of LNG imports. Still, lower Russian gas supply – although Europe is preparing for this possibility – would deplete gas in storage levels more this winter.The real concern about gas supply in Europe is for the winter after that, the top executives of Europe’s biggest oil and gas majors said just before the heating season began. Ahead of the 2023/2024 winter, the gap in gas supply in Europe will be much wider without Russian gas. Europe will not be importing much Russian gas - or none at all if Russia cuts off deliveries via the one link left operational via Ukraine and via TurkStream - compared to relatively stable imports from Russia in the first half of this year before Moscow started gradually cutting volumes via Nord Stream in June until shutting down the pipeline in early September.

Russia Threatens To Slash Gas Exports Over Ukraine Theft Of Moldova Supplies - Russia’s energy giant Gazprom on Tuesday accused Ukraine of stealing natural gas supplies intended for Moldova by siphoning it off during transit. Gazprom is now threatening to halt deliveries via the key the Sudzha route. "The volume of gas supplied by Gazprom to the ‘Sudzha’ gas measuring station (GMS) for transit to Moldova via Ukraine exceeds the physical volume transmitted at the border of Ukraine with Moldova," Gazprom’s statement said.The allegation further specified that the Ukrainian government stole 52.52 million cubic meters of gas which was intended for Moldova. Gazprom said that amount of gas never left Ukraine's territory while in transit.According to the fresh statement as presented in state media: The Russian energy company further warned that if the transit imbalance persists then it would begin slashing gas supply to the Sudzha GMS for transit via Ukraine from 10 am (7am GMT) on November 28, "in the amount of the daily underderlivery."Ukraine has a sprawling network of natgas transmission pipelines from Russia that feed into Europe, which now ironically enough remain the only key supply route to western and central European countries following the Nord Stream sabotage blasts. Despite the raging war which has been on for nine months, some 42 million cubic metres (mcm) per day still transits through Ukraine via the Sudzha route.Moldova is very heavily dependent on Russia for its energy supplies, and has been suffering rolling blackouts of late. On Monday donor countries gathered in Paris where they pledged hundreds of millions of dollars in aid to help salvage Moldova's energy infrastructure, and to prevent political destabilization at such a sensitive time. Moldova has recently applied for EU membership.Western officials have long accused Russia of seeking to takeover Moldova amid its "special operation" in Ukraine. International media has tended to blame tiny Moldova's energy woes on Moscow and its 'weaponizing' energy.

European refiners oversupplied as oil shortage fears subside --European refiners have found themselves oversupplied with crude as an expected shortage owing to the looming EU ban on Russian oil has yet to materialise. The front-month Brent crude futures spread narrowed sharply this week, reflecting better supply in the physical oil market as fears over the EU embargo on Russian crude begin to subside. Premiums on prompt prices to future prices – known as a backwardated market structure – usually indicate supply tightness. Traders cited Europe’s ability to replace Russian oil with grades from the Middle East, the United States and Latin America while Asia is asking for less crude because of an economic slowdown and increased use of Russian barrels. Brent futures prices have also slumped by about 7% this week, weakening for a second week in a row. “There’s too much oil around,” one European crude trader said. “(European] refiners seem to have overbought in November and December, probably because of fears around Urals,” he said, adding that French strikes and refinery maintenance also contributed to a crude overhang. Russian Urals crude prices jumped in August as traders and refiners rushed to buy as many barrels as possible, fearing the EU ban on Russian oil would lead to shortages. The EU will ban Russian crude imports from Dec. 5 and oil products from Feb. 5. A G7 price cap on Russian crude also comes into effect on Dec. 5. “The expectation of a tight market has not been realised,” a second European trader said, adding that oil from Brazil, Guyana, Canada and the U.S. Midland region was heading to Europe to improve the supply picture. However, he cautioned that supply is likely to tighten again in the new year.

European Refiners Now Have Too Much Oil - European refiners now seem to have more crude oil than they need - with the early panic about Russia’s dwindling oil exports - and the world’s subsequent oil shortage - proving to be overblown. Crude oil traders have pointed to Europe’s ability to source crude oil from Latin America, the Middle East, and the United States as the main cause for European refiners breathing a sigh of relief. Asia, too, has scooped up less crude oil than analysts were predicting, thanks to China’s never-ending battle to obtain the elusive zero-covid goal.Europe’s imports of Latin American crude have averaged 313,000 bpd so far this year, up from 132,000 Refinitiv Eikon data shows. In July, the average was well above that, at 600,000 bpd. From the United States, Europe has taken 1.1 million bpd on average this year, compared with just 800,000 bpd last year. Europe’s Iraqi oil imports are 20% higher from July-November compared to the same period last year.The supply overages are weighing on prices. Brent prices have slumped nearly $9 per barrel since this time last week. One European crude oil trader told Reuters that European refiners “seem to have overbought in November and December, probably because of fears around Urals.” In addition to these fears causing panic purchases, weeks-long strikes at French refineries and a rash of refinery maintenance also curbed the call for crude oil in Europe as runs slowed.Traders and refiners increased their purchases over this summer, anticipating shortages stemming from Europe’s ban on imports of Russian crude oil.That ban is set to go into effect on December 5. Until then, Europe will likely have no issues with obtaining enough crude oil.Post-December 5, however, could be a different story.

Employees Start Strike at Biggest European BP Oil Refinery -Dutch unions started a partial strike at BP Plc’s refinery in Rotterdam, with workers now limiting their efforts to resolving the fault that brought fuels production to a total standstill last week. BP employees won’t cooperate on restarting production units after the fault has been fixed, a representative for the CNV Vakmensen union told Bloomberg by phone. BP has said it was planning to restart the refinery early this week and didn’t immediately respond to an email Tuesday asking about the strike. BP’s Rotterdam refinery is among the biggest in Europe and is located in the heart of the region’s main oil-trading hub. It suffered an uncontrolled outage last week on the supply of steam, which the plant needs to operate. Refinery outages are closely watched currently after a wave of strike action in France this autumn prompted severe tightening in the diesel market. Russian supply is also a key concern. BP employees had started work-to-rule action at the beginning of last week but called it off following the incident. The unions previously gave a deadline of Nov. 23 for resolving a pay dispute with BP. Part of the refinery, BP’s biggest in the region, had been undergoing planned maintenance since September and the restart of at least one of those units also hadn’t gone to plan earlier this month.

U.S., Allies Eye $60 Price Cap For Russian Crude -The United States and its allies are hoping to establish the price level at which Russian crude oil will be capped, people familiar with the talks told the Wall Street Journal on Tuesday. Officials are talking about setting the price at which Russia’s crude oil will be capped at $60 per barrel. The group will meet on Wednesday to try to come to some agreement on prices. The G7 plan to cap the price of Russian crude oil goes into effect on December 5, and the EU will ban Russian crude oil imports from the same date. The US-led price capping mechanism of the G7 and the outright ban from the EU has the potential to disrupt 2.5 million bpd or more of seaborne crude oil to Europe. Russia reaffirmed its threat this week that it would not supply any crude oil to nations that operate under this price cap, redirecting its crude oil to “market-oriented partners”. According to Russian Deputy Prime Minister Alexander Novak, Russia could even reduce production in reaction to the price-capping strategy. Last week, the G7 was scrambling ahead of the December 5 deadline that is approaching fast. The EU regulations necessary to navigate the post-December 5 oil markets still hadn’t been drafted or finalized, pending the determination of the actual price level. The price cap plan will hold all buyers within the group to purchase crude oil from Russia only if it can be purchased below a set minimum. The plan looks to restrict Russia’s oil revenues while still allowing crude oil customers to source their oil from Russia. A $60 price cap would be nearly $30 per barrel under the current Brent barrel price, translating into a fine discount for any crude buyer.

Oil Freight at $100,000 Piles Pressure on Crude Markets --Soaring shipping costs are piling pressure onto physical oil markets that are already being hit by uncertainty surrounding a cap on Russian crude prices and weak Chinese buying. Earnings on the industry’s benchmark trade route breached $100,000 a day on Monday, the highest since early 2020 when Covid-19 caused a surge in tankers storing cargoes. With sanctions on Russia now forcing ships to take longer routes -- drying up the pool of available vessels -- oil companies and traders are having to pay ever-higher prices to transport cargoes. That’s adding to the cost of crude. “Shipping has become a tangible drain” on the price of oil where it’s loaded, compounding weak buying from China, said Viktor Katona, lead crude analyst at Kpler, a data and analytics firm. In addition, there’s “trepidation” from buyers about the market impact of a cap on Russian oil prices, according to Katona. From Dec. 5, a cap will be imposed on Russian oil prices for companies wanting to access ships and services including insurance provided by businesses in Group of Seven nations. The actual cap level hasn’t yet been set, making it hard for buyers to plan how much they might want to purchase from Moscow. The high freight rates that owners are earning are also reflected in high per-barrel transportation costs for traders. US Gulf shipments to China, one of the industry’s longest-distance mainstream routes, now cost about $6.60 a barrel, Baltic Exchange forward freight data compiled by Bloomberg show. That’s almost three times where it was in February. Several Mediterranean crudes, which trade at differentials to the North Sea oil grade Dated Brent, have slipped by at least $1.50 a barrel from a month ago, while more than 20 West African cargoes continue to struggle to find homes even after offer prices were cut multiple times. An overhang of crude cargoes in Europe stemming from labor strikes across the continent “is depressing prompt pricing just as markets are sourcing barrels from further afield in switching out Urals,” Russia’s main export crude, said Kit Haines, an analyst at Energy Aspects Ltd. “This means anytime you have an unplanned outage your prompt crude gets backed up pretty fast, and with China out of the market at the moment, there’s not really anywhere to clear,” he said.

Russian Oct oil supplies to China up 16% on yr, just behind Saudi's (Reuters) - China's oil imports from Russia jumped 16% in October from the same month last year to just behind top supplier Saudi Arabia, as state-run firms stocked up before a European embargo over Russia's invasion of Ukraine kicked in. Supplies from Russia, including oil pumped through the East Siberia Pacific Ocean pipeline and seaborne shipments from Russia's European and Far Eastern ports, totalled 7.72 million tonnes, data from the Chinese General Administration of Customs showed on Sunday. That amount, equivalent to 1.82 million barrels per day (bpd), was steady from September but off May's record of nearly 2 million bpd. State-run traders including Unipec, Zhenhua Oil and Chinaoil ramped up imports of Russian Urals, loaded mostly from European ports, before winding down purchases in recent weeks in the face of imminent European Union sanctions and uncertainty surrounding a Group of Seven plan to cap Russian oil prices. Saudi shipments rose 12% from a year earlier to 7.93 million tonnes, or 1.87 million bpd, versus September's 1.83 million bpd. Year-to-date, Saudi Arabia remained China's top supplier with volumes of 73.76 million tonnes, similar to the same period last year. January-October Russian supplies rose 9.5% on year to 71.97 million tonnes, helped by refiners' consistent appetite for the discounted oil. Arrivals of crude oil from the United States jumped more than fivefold in October from a year earlier, as refiners took advantage of lower prices amid a surge in U.S. exports from rising output and stockpile releases. Malaysia, which for the past over two years has been a transfer point for shipments originating from Iran and Venezuela, almost doubled on year to 3.52 million tonnes. No imports were recorded from Venezuela or Iran. The table below shows imports by country, with volumes in metric tonnes and the percentage change calculated by Reuters.

China Pauses Purchases Of Some Russian Oils Ahead Of Price Cap --While we wait for the US and EU to unveil details of the Russian oil price caps which will be implemented in two weeks (we may have a lot to to wait after John Kirby said that “It’s not just about the dollar figure. It’s about the implementation, of course, making sure as many countries as possible can sign on to that,” he tells reporters, clearly stalling as nobody in the west knows just how badly such a price cap could backfire and send prices soaring), China is not taking any risks as its crude buyers - who have emerged as the biggest buyers of Russian oil in 2022 taking advantage of western sanctions and buying up Russian oil with discounts as large as $30 below spot - have paused purchases of some Russian oil as they too wait for details of a US-led cap to see if it presents a better price. As Bloomberg reports citing "traders with knowledge of the matter", several cargoes of Russian ESPO crude for December-loading remain unsold and there’s hesitation among sellers and Chinese buyers to close deals before more clarity on the exact price cap level is known, according to traders with knowledge of the matter. The Russian oil price cap is set to be implemented alongside European Union sanctions on Russian crude on Dec. 5, with those adhering to the measure gaining access to insurance, banking and shipping services from the bloc. The cap is designed to keep crude flowing from the OPEC+ producer to prevent a global supply shock but crimp the Kremlin’s revenues as it wages war in Ukraine. However, Russia has reiterated that it won’t sell to nations that implement the cap, potentially sending oil sharply higher (back in July JPMorgan said that "Oil Price Could Hit "Stratospheric" $380 If Russia Retaliates To G7 Oil Price Cap"). Instead, Moscow will redirect supply to “market-oriented partners” or reduce production, according to Deputy Prime Minister Alexander Novak. In other words, the status quo will continue, since to this day Russian oil makes its way to European markets, only instead of being bought directly from Russia, it comes by way of China or India instead, with Europe paying a substantial premium to where oil would trade if all these artificial trade barriers did not exist. ESPO, or Eastern Siberia-Pacific Ocean oil is popular with China’s independent refiners due to the high diesel yield and short shipping distance. Traders said many market participants appear open to referencing the price cap -- even if they don’t officially support it -- provided the level isn’t too dislocated from current prices. Should the level be set too low, however, the party responsible for shipping and insurance coverage -- which can be the seller or buyer, depending on contract terms -- may need to seek services from non-EU providers, thereby complicating the process and drastically changing the economics of the deal. At the same time, and as Zoltan Pozsar explained back in March, adding to buyers' concerns is that banks that finance crude purchases are wary of the looming sanctions and soaring freight rates. Service providers are weighing their possible exposure to the EU penalties and how best to navigate restrictions when they take effect in less than two weeks. Ahead of the price cap, Russian seaborne fuel exports soared to the highest since at least 2017 as the nation’s refiners rushed to do deals before EU restrictions on imports and shipping come into force. The nation’s average daily exports of oil products from Nov. 1 to 10 jumped 22% from the prior month to around 3.17 million barrels, according to estimates from data and analytics firm Kpler.

Russian Crude Oil: China and India easing away from Russian crude oil may be temporary: Russell - There are signs that China and India are pulling back from buying Russian crude oil ahead of the Group of Seven nations' proposed price cap and a European Union ban on imports. However, the more important question for the market is whether any slowing by China and India of purchases from Russia is a temporary factor that will be reversed once participants figure out how to work with, or around, the price cap. China, the world's largest crude oil importer, and India, the third-biggest, have increasingly turned to Russian crude this year, buying cargoes at steep discounts as Moscow sought to keep up export volumes after Western countries shunned its oil. The G7 price cap and the EU ban on imports are aimed at cutting the revenue Russia receives from its exports of crude oil and products and are part of efforts to punish Moscow for its Feb. 24 invasion of Ukraine. Russia calls its actions there "a special operation". Chinese refiners have begun slowing their purchases of Russian crude for December arrivals, according to traders and industry players in China. The reduced volumes from Russia for December come after several months of strong imports. China is forecast to bring in 1.80 million barrels per day (bpd) of Russian crude in November, up from October's 1.69 million bpd and in line with September's 1.82 million bpd, according to data compiled by Refinitiv Oil Research. It is also likely that Russia will overtake Saudi Arabia as China's biggest supplier of crude in November, with the two leading members of the OPEC+ group having swapped the top spot several times so far this year. Indian refiners are also wary of buying Russian crude beyond the Dec. 5 date of the EU import ban and the proposed price cap. Leading refiners Reliance Industries and state-controlled Bharat Petroleum are pulling back from placing orders, according to two sources familiar with the purchasing plans. The lower volumes for December follow strong imports by India of Russian crude in recent months. Refinitiv estimates November arrivals at 1.0 million bpd, which would make Russia the top supplier for the month, ahead of Iraq's 960,000 bpd. The question is whether China and India will once again turn to Russian oil in the new year, or whether the uncertainty created by the price cap and EU ban will linger. It's likely that both countries will be keen to buy Russian crude, especially if it comes at a steep discount compared to grades from the Middle East and Africa. But there are several issues that refiners in both countries will have to work around. Payment and transportation issues such as insurance may become more complex, though it's likely that refiners and traders are smart enough to work out ways to keep doing business. In fact, the main difficulty may be in sourcing enough vessels to move crude from Russia's western ports through to Asia. Currently, much of the crude China buys from Russia comes from the eastern ports. Refinitiv data shows that of the 3.42 million tonnes of seaborne oil arriving in November, all but 705,000 tonnes came from Pacific and Arctic ports. China is expected to import 705,000 tonnes of Russian Urals grade, which was the main grade supplied to European refiners from the country's western ports. Prior to the attack on Ukraine, China bought only small volumes of Urals crude, but this started to pick up in May, reaching a peak of 739,860 tonnes in June. The question is whether Russia and China have sufficient tankers in order to increase shipments of Urals crude. These would have to come through the Suez Canal, which limits the size of vessels, or take the long route around the Cape of Good Hope in South Africa. India, which is closer to Russia's western ports than China, had stepped up its purchases of Urals after the start of the war in Ukraine. It's expected to import 3.13 million tonnes of Urals crude in November, down from the record high of 3.54 million in October, but well above the 135,000 tonnes from November last year. If Russia wants to boost shipments to China and India, or other potential buyers in Asia, it will have to secure more vessels, or strike deals with importers to use their tanker fleets. It's this constraint that may limit Russia's exports to Asia, rather than the G7 price cap.

Rosneft Gets Super-Icebreaker For Vostok Project --- Russia’s Rosneft has inaugurated a new, nuclear-powered icebreaker to be used at its Vostok Oil project in eastern Siberia.The 173-meter Ural recently completed its tests, the Barents Observer reports, and will soon head to Murmansk and the nuclear icebreaker base there. It will be used exclusively by Rosneft, according to a Rosatom executive.There is a deficit of icebreakers for the Northern Sea Route, the same executive, Vladimir Arutiunian, told Russian media last month. He added that this year will see the launch of one new icebreaker—the Ural—with two more scheduled to be ready in 2024 and in 2026.Vostok Oil, a mega-project in the Taymyr province in Russia’s Far North, comprisesseveral groups of oil fields holding an estimated 44 billion barrels of oil. Initial work on the project began in January 2021. The resources are located close to the Northern Sea Route, which climate change has made navigable for a longer period every year.The total cost of the Vostok Oil development has been estimated at $170 billion over the lifetime of the fields. The main market for the oil extracted from the fields there will be shipped to Asia, hence the focus on developing the Northern Sea Route.Rosneft still has to line up the finance for the mega-project after Western partners pulled out after the invasion of Ukraine. Previously, commodity major Trafigura had bought a 10-percent stake in the project, and there were reports that Rosneft was in talks with Vitol, Gunvor, and Glencore, too.Investors from India and China are now the alternative after talks with them stalled following the oil price collapse in 2020. Originally, first oil was scheduled to flow from Vostok in 2024, but Western sanctions will likely delay that as they feature bans on the export of oil technology and equipment to Russia.

Bulgaria to let Russian oil refinery export despite EU ban - Bulgaria will allow a Black Sea refinery owned by a Russian oil company to keep operating and exporting oil products to the European Union until the end of 2024 despite warnings by Brussels that it is against the bloc's sanctions. The deal between Bulgaria and Russian-owned Lukoil will give an additional 350 million-euro (dollar) boost to Bulgaria's budget, according to estimates by the government in Sofia. "We achieved something very important: from January 1, 2023, Lukoil will transfer all production, revenues and taxes to be paid in Bulgaria, and not, as it was before, in the Netherlands or Switzerland," Bulgarian Deputy Prime Minister Hristo Alexiev said after talks with managers of the Russian oil company. The deal also benefits Lukoil, allowing its Bulgarian facility to partially avoid an upcoming EU embargo on most Russian oil products. "The refinery cannot work if exports are curtailed," CEO Ilshat Sharafutdinov warned. The Balkan country's sole refinery is the main source of gasoline and diesel fuel sold on the Bulgarian market, but half of the production is for export. It contributes some 9 per cent of the country's economic output and employs several thousand people. A shutdown would cause serious troubles to the labour market in addition to the loss of refining capacity. In June, the EU banned the purchase, import or transfer of Russian crude oil starting December 5 and other refined petroleum products from Russia starting February 5. Bulgaria received an exemption and can continue to import crude oil and petroleum products via maritime transport until the end of 2024. It cannot, however, export petroleum products produced from Russian oil in Bulgaria. Officials from the EU country assert that the oil products it exports will be Bulgarian. "The oil products derived from Urals oil will originate from Bulgaria and can be exported," Deputy Finance Minister Lyudmila Petkova said Monday, referencing Russia's export grade of crude. Bulgaria's government argues that the export ban would harm the country's economy as it will accumulate a deficit in its domestic market after Lukoil's refinery stops production.

Bangladesh to increase LNG import by 25% in December -Industries in Bangladesh are all set to get increased gas supply in the days to come after the Government has decided to increase liquefied natural gas (LNG) imports by 25 per cent in December. This is as per media reports, which maintained to feed growing demand for natural gas in industries, the Government has planned to increase LNG import by around 25 per cent in December compared to its November and October imports respectively and went on to underline that there are plans to import a total of five LNG cargoes from long-term suppliers during December against its import of four LNG cargoes each during October and November, citing a senior official of the state-run Petrobangla. Speaking to the media, the official concerned reportedly expressed hopes the increased LNG imports will boost Bangladesh’s overall natural gas output and satisfy the industries’ requirements, grappling currently with severe gas crisis, which has hit the productivity hard.

Major shale gas field sees record-high output - China’s largest shale gas field, had seen a record-high output of natural gas this year as of Sunday, said its developer Sinopec. The field in southwest China’s Chongqing has produced around 6.4 billion cubic meters of natural gas in 2022 to date, up 0.5 percent year on year, said the company. Over ten production and construction projects are helping increase the daily gas supply to around 20 million cubic meters, according to the company. The field has also taken various steps to offset the impact of COVID-19 and speed up drilling efficiency, despite the complicated geological conditions of new wells. As China’s first large-scale shale gas field to enter commercial development in 2014, Fuling has become a clean energy source for more than 70 cities along the Yangtze River Economic Belt in China.

China's natural gas output up 12.3 pct in October- (Xinhua) -- China's natural gas output logged robust growth last month, data from the National Bureau of Statistics showed. The country produced 18.5 billion cubic meters of natural gas in October, up 12.3 percent from a year ago and the growth pace was 7.7 percentage points faster than that in September. In the first 10 months of this year, China's natural gas output rose 6 percent year on year to 178.5 billion cubic meters. The country imported 88.74 million tonnes of natural gas in the same period, down 10.4 percent year on year. China can generally guarantee natural gas supply for winter heating demands this year despite a complex international market situation, a spokesperson from the National Development and Reform Commission told a press conference on Wednesday. The commission will urge localities to stay true to related price policies to maintain relatively stable natural gas prices for households, the spokesperson added.

Eddie Mabo’s lawyer says NT fracking plans could go against native title - The high-profile lawyer who represented Torres Strait Islander man Eddie Koiki Mabo in his historic land rights victory says proposed Northern Territory laws that would allow gas companies to use or sell fracked gas found during exploration could contravene native title laws.Aboriginal and environmental groups have criticised the territory government’s proposed bill as allowing “production by stealth”. They say the gas industry would be able to use or sell methane obtained during “appraisal” activities without needing to secure a production licence or negotiate with traditional owners and pastoralists. The government says the law change would allow companies to use appraisal-phase gas to power local communities, rather than having it vented or burnt at the point of extraction.Barrister Greg McIntyre, who represented Mabo in the historic High Court win that overturned the doctrine of “terra nullius” and recognised land rights of First Nations people, said the approval being sought under the proposed legislation would be a “future act” within the meaning of the Native Title Act.This means traditional owners should have a right to negotiate, and if these provisions were ignored then any application to mine for gas would be invalid.“I suspect that the lightbulb hasn’t turned on and … the government hasn’t obtained advice about whether it might impact on the Native Title Act,” McIntyre said.

Brazil breaks new oil and gas output record - Brazil broke a new oil and gas output record in October, with a total of 4.18Mboe/d (million barrels of oil equivalent per day), according to watchdog ANP. The amount is 3.2% higher than the previous record, set in September – when Brazil produced 4.05Mboe/d – and 16% up from a year earlier. The volume included 3.2Mb/d of oil, surpassing the previous record in January 2020 of 3.17Mb/d, and 149Mm3/d of natural gas, up from 143Mm3/d in September. Production in the pre-salt increased 4.75% compared to September to 3.14Mboe/d, representing 75.2% of the total. Output from production-sharing contracts rose 18% to 995,200boe/d, accounting for 23.8% of the total. The increase was driven by production from the P-77, in the Búzios field, and the Guanabara and Pioneiro de Libra FPSOs, in Mero. The two fields are operated by federal company Petrobras, which produced 2.7Mboe/d in October or 65% of the total. The state-run firm plans to put a new FPSO into operation next month, the P-71, in the Itapu field.

OPEC says Libya topped list of African oil producers in October 2022 | The Libya Observer - The monthly oil market report issued by the Organization of Petroleum Exporting Countries "OPEC" said that Libya had topped the list of African oil producers in last October with 1.163 million barrels per day (bpd), while its production increased by 6000 bpd. Libya is followed by Angola: 1.067 million bpd, Algeria with 1.060 million bpd, while Nigeria's oil production amounted to 1.024 million bpd. According to the report, Libya has taken Nigeria's place, which is far from its average of 1.493 million bpd in 2020 and 1.323 million bpd in 2021. OPEC oil production decreased by 210,000 bpd in October 2022 to drop for the first time in 5 months, following the decline in supplies from Saudi Arabia and Angola, according to the OPEC+ alliance agreement. The report says the total crude production in the 13 member countries of OPEC decreased to 29.494 million bpd last October, compared to 29.704 million bpd in the previous month. The decline in OPEC oil production comes as a result of the OPEC+ alliance’s announcement to reduce supplies by 100,000 bpd in October, as the alliance announced a new policy, early last month, aimed at reducing oil production by two million bpd at the beginning of November 2022, until December 2023.

Nigeria drops to seventh on OPEC production list - Nigeria now ranks seventh on Organisation of the Petroleum Exporting Countries’ crude oil production list, according to the organisation’s Monthly Oil Market Report for November, which examined oil production performance in October. Nigeria’s output was a mere 1.014 million barrels per day in October, ranking seventh after Saudi Arabia, United Arab Emirates, Kuwait, Iraq, Angola and Algeria. While Nigeria’s production was 1. 014mb/d in October, Angola produced 1. 051mb/d; Algeria, 1.060mb/d; Kuwait 2.811mb/d; UAE, 3.188mb/d; Iraq, 4.651mb/d; and Saudi Arabia, 10. 957mb/d. While Venezuela’s production was 711b/d, Equatorial Guinea’s was 57b/d. The likes of Gabon, Libya and Iran did not produce a barrel in the month. Nigeria used to rank fifth, with countries such as Angola and Algeria behind it in terms of crude oil production.

Nigeria’s oil production to increase by 225,000 bpd as SNEPCo completes 2022 TAM – Nigeria’s oil production output to the global market could increase by 225,000 barrels per day, following the completion of the 2022 Turnaround Maintenance (TAM) of the Bonga floating production storage and offloading vessel (FPSO) by Shell Nigeria Exploration and Production Company Limited (SNEPCo). The expected increase in production will boost Nigeria’s foreign exchange earnings as the country is grappling with the paucity of funds, scarcity of forex and fluctuating value of the naira. SNEPCo’s Media Relations Manager, Mrs Abimbola Essien-Nelson, confirmed the completion of the TAM in a statement. The statement was titled: ‘SNEPCo’s Bonga FPSO completes 2022 Turnaround Maintenance (TAM).’ She said: “Shell Nigeria Exploration and Production Company Limited (SNEPCo) is pleased to announce that the 2022 Turn-around Maintenance (TAM) of the Bonga floating production storage and offloading vessel (FPSO) has been completed. “The 225kbopd capacity FPSO was shut down on October 18, 2022, to carry out statutory inspections, recertifications and other critical asset integrity restoration activities. “The 2022 TAM, which was originally planned for 30 days was completed in 22 days on November 9, 2022, thanks to excellent front-end planning and flawless execution. “Commissioning and start-up activities are in progress and will culminate in the ramp-up of oil and gas production in the coming days.”

PTTEP to pay $129 million compensation for 2009 Montara oil spill - Thailand’s national upstream company PTTEP has reached an out-of-court settlement with Indonesian seaweed farmers, agreeing to pay US$129 million in compensation for the oil spill that followed the 2009 Montara blowout offshore Australia. The oil spill and subsequent slick occurred when the Montara wellhead platform, located in the Timor Sea in Australian territorial waters, had a blowout on 21 August 2009. The leak off the northern coast of Western Australia could only be plugged on 3 November that year, resulting in one of Australia’s worst oil spill disasters. Some 13,000 Indonesian seaweed farmers in 2019 filed a class-action lawsuit against subsidiary PTTEP Australasia (PTTEPA) demanding A$200 million (US$132.3 million) in compensation, claiming the oil had damaged the crops and impacted their livelihoods. “Our experts contend that approximately 6000 barrels per day of oil contaminated the sea,” said Ben Slade of Maurice Blackburn, the law firm that represented the seaweed farmers at the initial hearing. PTTEPA initially claimed that the oil leaked from Montara never reached Indonesian waters, but it subsequently conceded that contamination of this kind was inflicted. An Australian court ruled in favour of the Indonesian plaintiffs in hearings on 19 March and 25 October last year. PTTEPA Ashmore (PTTEPAA) on 13 December 2021 appealed against the verdicts, prompting the Federal Court of Australia to urge both parties to settle their differences in out of court negotiations, in line with Australian judicial practice for class action cases. During mediation, the then Montara operator reached a preliminary agreement with the group of Indonesian seaweed farmers to would pay A$192.5 million, in full and final settlement of the class action, but with no admission of liability under the settlement.

Indonesia to sue Thai oil firm over 2009 Montara oil spill - The Indonesian Government plans to sue PTT Exploration & Production (PTTEP) company next year for at least $1.7bn in damages over the Montara oil spill. Last year, an Australian court ruled in favour of Indonesian seaweed farmers whose livelihoods were affected by the oil spill. However, PTTEP, an oil and gas subsidiary of the Petroleum Authority of Thailand, filed an appeal against the verdict. This would have resulted in it having to pay more than $262m in compensation. In 2019, around 13,000 Indonesian seaweed farmers sued PTTEP Australasia , stating the oil spill had harmed their crops and negatively impacted their livelihoods. They sought $132.3m in damages. PTTEP had then agreed to pay approximately $129m to a group of Indonesian seaweed farmers to settle a class action lawsuit brought by them. According to Indonesia’s environment and forestry deputy minister Alue Dohong, the government is demanding a larger settlement from PTTEP for the harm it caused to coral reefs, mangroves, and marine life, including $281.3m to fund restoration efforts, Bloomberg News reported. An explosion on 21 August 2009 caused the oil spill off the northern coast of Western Australia in the Timor Sea. The Montara rig continued to spew oil for 74 days before a relief well was drilled. PTTEP operated the Montara field when the accident occurred, 250 kilometres southeast of Rote Island in Indonesia. It is known as one of Australia’s worst oil disasters. At the time, Australia’s PTTEP chief executive Ken Fitzpatrick said: “Mistakes were made that should never be repeated. The conclusion of the court proceedings draws a line under the Montara incident, allowing the company to focus on producing safe and clean operations now and into the future.” Australia’s PTTEP had initially stated that the oil discharged from Montara never reached Indonesian waterways. It later admitted that this contamination did take place.

UAE denies it is engaging in discussion with other OPEC+ members to change their latest agreement - minister (Reuters) - United Arab Emirates' energy minister said on Monday that the Gulf state denied that it is engaging in any discussion with other OPEC+ members to change their latest agreement, adding that it is valid until the end of 2023. "We remain committed to OPEC+ aim to balance the oil market and will support any decision to achieve that goal," Suhail Mohamed Al Mazrouei said in a Twitter post. The Wall Street Journal earlier on Monday reported an output increase of 500,000 barrels per day was under discussion for the next meeting of OPEC and its allies, known as OPEC+, on Dec. 4. The report cited unidentified OPEC delegates.

Kuwait officials discuss OPEC+ oil output decrease with senior US Senator | Arab News --Kuwait’s Foreign Minister Sheikh Salem Abdullah Al-Jaber Al-Sabah and Parliament Speaker Ahmad Al-Saadoun received senior New Jersey Senator Bob Menendez, state news agency (KUNA) reported.During the meeting, Kuwait’s foreign minister reiterated that politics did not interfere with the latest OPEC+ decision to reduce oil output. “The decision was based on technical study of the global oil market,” read KUNA statement.He renewed Kuwait’s contribution to efforts to maintain stability in oil markets.During the meeting, Menendez reiterated the US government’s commitment to achieving safety and security in the Gulf region.Kuwaiti officials and Menendez also reviewed the historical ties between both countries, pledging further effort to advance cooperation to serve common interests. Recently, Saudi Arabia, UAE and Kuwait denied reports that there have been discussions to increase oil production at the next OPEC+ meeting.The decision to cut production by 2 million barrels a day will stand till the end of 2023, they affirmed.

Aramco Signs 59 Deals Worth $11B -Saudi Aramco revealed Tuesday that it has signed 59 corporate procurement agreements (CPAs), worth $11 billion, with 51 local and global manufacturers. The deals have the potential to create 5,000 new jobs in the Kingdom of Saudi Arabia over the next decade and are expected to reinforce Aramco’s supply chain and result in the development of materials manufacturing facilities in the Kingdom, Aramco outlined. The 59 CPAs cover multiple strategic commodities, such as drilling chemicals, wellheads, switchgears, vibration monitoring systems, pipes, compressors, structure steel, fittings and flanges, and air-cooled heat exchangers, Aramco noted. Although Aramco did not publish a full list of the companies it made the CPAs with, it highlighted that it had struck deals with Baker Hughes, Cameron Al Rushaid, Halliburton, SLB, and TechnipFMC. Aramco outlined that the CPAs were signed under the In-Kingdom Total Value Add (iktva) program, which it launched in 2015 with the goal of establishing a world-class supply chain in Saudi Arabia. Since its launch, the iktva program has contributed more than $130 billion to the Kingdom’s gross domestic product, while creating more than 100,000 supply chain jobs for Saudis, according to Aramco. “Our significant investments in a network of accomplished local suppliers strengthens Aramco’s resilience, ensuring that we remain the world’s most reliable energy company,” Ahmad A. Al-Sa’adi, Aramco’s Senior Vice President of Technical Services, said in a company statement. “We are also extensively building commercial ecosystems globally by partnering with some of the world’s top energy, logistics, and manufacturing companies,” he added. Mohammad A. Al-Shammary, Aramco’s Vice President of Procurement and Supply Chain Management, said, “the CPA holders will be our future strategic manufacturing partners for these commodities, and the agreements further broaden our localization infrastructure across the Aramco network”. Back in January, Aramco announced the signing of 50 Memoranda of Understanding (MoUs) at the iktva forum and exhibition. Although a full list of deals was, again, not revealed by Aramco, the company highlighted that major signings included Schlumberger, Cameron/TechnipFMC/Baker Hughes, and Honeywell. During the same month, Aramco revealed that it had signed 10 agreements during the Saudi-Korean Investment Forum. The deals spanned the areas of technology, manufacturing and finance and included Korea Electric Power Corporation, S-Oil, and the Export-Import Bank of Korea, Aramco highlighted.

Sabic plans project to convert crude oil into petrochemicals - Saudi Basic Industries Corporation is planning to set up a plant to convert crude oil into petrochemicals, capitalising on growing demand. The crude-to-chemicals complex in Ras Al Khair, in the east of Saudi Arabia, is expected to convert 400,000 barrels per day of oil into chemicals, the company said in a statement on Thursday to the Tadawul stock exchange, where its shares are traded.Sabic is the Middle East's biggest petrochemicals producer.The latest project, part of its strategic growth plans, will help to expand the manufacturing of petrochemicals in the kingdom, the company said.Top crude exporter Saudi Aramco, which owns a 70 per cent stake in Sabic, has been investing billions of dollars in downstream projects to extract more value from its crude oil output.Last week, Aramco said it would build a $7 billion refinery-integrated petrochemical steam cracker in South Korea through its S-Oil unit.The steam cracker, which will convert crude oil into petrochemical feedstock, is expected to produce up to 3.2 million tonnes of petrochemicals annually and include capacity to produce high-value polymers.The petrochemicals industry is expected to be a major driver of crude oil demand in the next few decades as consumers increasingly switch to electric vehicles. Globally, the sector is projected to be worth roughly $800 billion by 2030, up from about $475 billion in 2020, according to Precedence Research.Petrochemicals are set to account for more than a third of the growth in oil demand to 2030, and nearly half to 2050, ahead of lorries, aviation and shipping, according to the International Energy Agency.Their production is also poised to consume an additional 56 billion cubic metres of natural gas by 2030, equivalent to about half of Canada’s total gas consumption today, the energy agency said.“Sabic affirms its commitment to continue developing crude oil to chemicals technologies, which contributes to increasing cost efficiencies and value creation opportunities in the energy and chemical industry on a larger scale,” the company said on Thursday.

Inside the Saudi Strategy to Keep the World Hooked on Oil - The New York Times - Shimmering in the desert is a futuristic research center with an urgent mission: Make Saudi Arabia’s oil-based economy greener, and quickly. The goal is to rapidly build more solar panels and expand electric-car use so the kingdom eventually burns far less oil.But Saudi Arabia has a far different vision for the rest of the world. A major reason it wants to burn less oil at home is to free up even more to sell abroad. It’s just one aspect of the kingdom’s aggressive long-term strategy to keep the world hooked on oil for decades to come and remain the biggest supplier as rivals slip away.In recent days, Saudi representatives pushed at the United Nations global climate summit in Egypt to block a call for the world to burn less oil, according to two people present at the meeting, saying that the summit’s final statement “should not mention fossil fuels.” The effort prevailed: After objections from Saudi Arabia and a few other oil producers, the statement failed to include a call for nations to phase out fossil fuels.The kingdom’s plan for keeping oil at the center of the global economy is playing out around the world in Saudi financial and diplomatic activities, as well as in the realms of research, technology and even education. It is a strategy at odds with the scientific consensus that the world must swiftly move away from fossil fuels, including oil and gas, to avoid the worst consequences of global warming.The dissonance cuts to the heart of the Saudi kingdom. The government-controlled oil company, Saudi Aramco, already produces one out of every 10 of the world’s barrels of oil and envisions a world where it will be selling even more. Yet climate change and rising temperatures are already threatening life in the desert kingdom like few other places in the world.Saudi Aramco has become a prolific funder of research into critical energy issues, financing almost 500 studies over the past five years, including research aimed at keeping gasoline cars competitive or casting doubt on electric vehicles, according to the Crossref database, which tracks academic publications. Aramco has collaborated with the United States Department of Energy on high-profile research projects including a six-year effort to develop more efficient gasoline and engines, as well as studies on enhanced oil recovery and other methods to bolster oil production.Aramco also runs a global network of research centers including a lab near Detroit where it is developing a mobile “carbon capture” device — equipment designed to be attached to a gasoline-burning car, trapping greenhouse gases before they escape the tailpipe. More widely, Saudi Arabia has poured $2.5 billion into American universities over the past decade, making the kingdom one of the nation’s top contributors to higher education. Saudi interests have spent close to $140 million since 2016 on lobbyists and others to influence American policy and public opinion, making it one of the top countries spending on U.S. lobbying, according to disclosures to the Department of Justice tallied by the Center for Responsive Politics. Much of that has focused on bolstering the kingdom’s overall image, particularly after the murder of the journalist Jamal Khashoggi in 2018 by Saudi operatives. But the Saudi effort has also extended to building alliances in American Corn Belt states that produce ethanol — a product also threatened by electric cars

Oil prices retreat as investor sentiment darkens: Kemp (Reuters) - Oil prices were hit by an abrupt reversal of sentiment last week, with investors selling at the fastest rate for four months, as the economic outlook worsened and fears eased that the G7 price cap on Russian crude would disrupt its exports. Hedge funds and other money managers sold the equivalent of 59 million barrels of the six most important petroleum futures and options contracts in the week to Nov. 15, the fastest rate since the week ended July 5. The selling came after fund managers had been buyers in five of the previous six weeks, purchasing a total of 169 million barrels, according to exchange and regulatory position records. The most recent week saw sales concentrated in Brent (-30 million barrels) and NYMEX and ICE WTI (-19 million) with lighter sales in European gas oil (-5 million), U.S. gasoline (-4 million) and U.S. diesel (-4 million). Investors had been steadily accumulating bullish long positions in petroleum, especially crude, expecting OPEC⁺ output cuts and the price cap to reduce supplies more than the economic slowdown reduces demand. But that confidence was dented last week as the economic outlook across Europe and Asia worsened while traders became convinced the cap would have little impact on oil supplies owing to widespread avoidance and evasion. At the same time, China grappled with the largest outbreak of coronavirus cases for six months, with no sign of an early exit from the cycle of lockdowns, which will continue to depress oil consumption. As a result, Brent futures prices and calendar spreads retreated as traders prepared for a relatively hard landing for the global economy which will likely cut oil consumption absolutely or at least relative to the previous trend.

Oil prices ease to trade near 2-month lows on China demand fears - Oil prices dropped to trade near two-month lows on Monday, having earlier slid by around $1 a barrel, as supply fears receded while concerns over fuel demand from China and U.S. dollar strength weighed on prices. Brent crude futures for January had slipped 65 cents, or 0.7%, to $86.97 a barrel by 1000 GMT. U.S. West Texas Intermediate (WTI) crude futures for December were at $79.71 a barrel, down 37 cents or 0.5%, ahead of the contract's expiry later on Monday. The more active January contract was down 50 cents or 0.6% to $79.61 a barrel. Both benchmarks closed Friday at their lowest since Sept. 27, extending losses for a second week, with Brent down 9% and WTI 10% lower. "Apart from the weakened demand outlook due to China's COVID curbs, a rebound in the U.S. dollar today is also a bearish factor for oil prices," said CMC Markets analyst Tina Teng. "Risk sentiment becomes fragile as all the recent major countries' economic data point to a recessionary scenario, especially in the UK and euro zone," she said, adding that hawkish comments from the U.S. Federal Reserve last week also sparked concerns over the U.S. economic outlook. New COVID case numbers in China remained close to April peaks as the country battles outbreaks nationwide and in major cities. Schools in some districts in the capital Beijing switched to online classes on Monday after officials asked residents to stay home, while the southern city of Guangzhou ordered a five-day lockdown for its most populous district. The front-month Brent crude futures spread narrowed sharply last week while WTI flipped into contango, reflecting dwindling supply concerns. Meanwhile expectations of further interest rate rises elsewhere have elevated the greenback, making dollar-denominated commodities more expensive for investors.

Oil prices waffle on conflicting OPEC+ output reports - Oil prices were down on Monday, but reversed some losses after hitting their lowest since early January on conflicting reports about whether Saudi Arabia and other OPEC oil producers are considering a half-million barrel daily output increase.Brent crude futures for January fell $1.41, or 1.6%, to $86.21 a barrel by 12:16 p.m. EST (1716 GMT). U.S. West Texas Intermediate (WTI) crude futures for December were down $1.69, or 2.1%, at $78.39 ahead of the contract’s expiry later on Monday. Both benchmarks had plunged by more than $5 a barrel earlier in the session after the Wall Street Journal reported an increase of up to 500,000 barrels per day will be considered at the OPEC+ meeting on Dec. 4. Oil pared some losses following a Saudi state news agency report that the kingdom was not discussing such a boost. “It’s hard to believe they’re going into a market that is basically trading in contango,” said Bob Yawger, director of energy futures at Mizuho in New York, referring to the effect of current oil futures trading at a discount to later dated contracts. “That’s playing with fire.” The Organization of the Petroleum Exporting Countries (OPEC) and its allies, together known as OPEC+, recently cut production targets and de facto leader Saudi Arabia’s energy minister was quoted this month as saying the group will remain cautious.

Oil Rebounds After Saudis Deny WSJ Report On OPEC Production Hike - The first question that comes to mind (as oil already tests multi-month lows) is - why would they do this? The Wall Street Journal reports that Saudi Arabia and other OPEC oil producers are discussing an output increase, the group’s delegates said... An increase of up to 500,000 barrels a day is now under discussion for OPEC+’s Dec. 4 meeting, delegates said. The move would come a day before the European Union has said it would impose an embargo on Russian oil and the Group of Seven wealthy nations’ plans to launch a price cap on Russian crude sales, potentially taking petroleum supplies off the market. Any output increase would mark a partial reversal of a controversial decision last month to cut production by 2 million barrels a day at the most recent meeting.The reaction was swift and obvious as WTI tumbled $2 back to a %77 handle... We are sure it just a coincidence that this report hits days after the Biden administration grants immunity to MbS over the brutal assassination of reporter Jamal Khashoggi. Even WSJ admits it is an unusual time for OPEC+ to consider a production increase, with global oil prices falling more than 10% since the first week of November. Update (1205ET): Well that actually took a little longer than we expected......but sure enough, the Saudis have come out with a statement denying the report of discussions about an OPEC+ oil output hike.WTI immediately soared on the headline... Additionally, the Saudi oil minister reiterated that the current OPEC+ deal will continue until the end of 2023 and that it is ready to intervene in the market if necessary (i.e. cut production further should prices plummet).“OPEC+ does not discuss any decisions ahead of its meetings,” Saudi Energy Minister Prince Abdulaziz bin Salman said in a statement. “The current cut of 2 million barrels per day by OPEC+ continues until the end of 2023 and if there is a need to take further measures by reducing production to balance supply and demand, we always remain ready to intervene.”

Oil price collapse: Saudis, Russians rush to market’s rescue, 2 weeks early -- There are another two weeks to go for the OPEC+ meeting, but the Saudis and Russians have decided not to sit back and let the market collapse continue. In an urgent response to a Wall Street Journal story on Monday, Saudi Energy Minister Abdulaziz bin Salman denied that the 23-nation oil producing alliance under his charge was working on a production hike of 500,000 barrels per day to announce at OPEC+’s Dec. 4 meeting. If the WSJ report had been true, it would have been a pivot to the 2-million-barrel per day cut that OPEC+ had announced for November. It would have been a hike small in barrels, yet huge in goodwill, doing wonders for Saudi-U.S. relations but, unfortunately, further hammering already free-falling crude prices. Both New York-traded West Texas Intermediate crude, or WTI, the benchmark for U.S. crude, and London's Brent, the global gauge for oil, hit their lowest since the beginning of the year in Monday’s early trading, partly based on the WSJ story. But the report wasn’t true, Saudi energy minister Abdulaziz said in a statement issued by state news agency SPA. “It is well-known that OPEC+ does not discuss any decisions ahead of the meeting," Abdulaziz said, referring to the Dec. 4 meeting. He added: “The current cut of 2M barrels per day by OPEC+ continues until the end of 2023 and if there is a need to take further measures by reducing production to balance supply and demand we always remain ready to intervene.” And just like on cue, Russian Deputy Prime Minister Alexander Novak, Abdulaziz’s closest non-Gulf ally in OPEC+, came in with his own responses to the upcoming Dec. 5 decision by Western nations on a prospective import ban and price cap on Russian oil. Novak reiterated Russia’s stand of not selling its oil to nations that would participate in the price-cap, a plan devised by the West to limit the funding that Moscow could put in its war against Ukraine. The Russian deputy premier also said something else that helped crude prices go back into the positive for the day: in the event of an oil price cap, Russia may also reduce oil production. “Lower supply will be the result from a price cap on Russian oil,” Novak added. WTI, which hit a session low of $75.30 on Monday, marking a bottom since January, recovered most of their losses by midday, responding to the remarks by Abdulaziz and Novak. The U.S. crude benchmark settled at $79.73 a barrel, down 35 cents, 0.4%. Global crude benchmark Brent sank to $82.36 earlier, its lowest since February, before recovering to settle at $87.45, down 17 cents, or 0.2%, on the day. “It’s interesting the coordinated response we’ve got from the Saudis and the Russians in denying the WSJ report and putting a floor under the oil selloff,” “There’s another two weeks to the OPEC+ meeting and they’ve decided there's too much at risk on the price front if they keep mum till then.” Crude prices also entered briefly on Friday into a “contango” mode — a market structure that defines weakness — for the first time since 2021. Under this dynamic, the front-month oil contract in the futures market trades at a discount to the nearby month. While the difference itself might be small, it forces buyers wishing to hold a position in oil at the time of contract expiry to pay more to switch to a new front-month contract. With such negativity in crude now, all eyes are on what the OPEC+ alliance of oil producers will do when it meets on Dec. 4. OPEC+ — the alliance that bands OPEC, or the 13-member Saudi-led Organization of the Petroleum Exporting Countries, with 10 other oil producers steered by Russia — agreed at its prior meeting to slash production by 2M barrels per day in order to boost Brent and U.S. crude prices that had fallen sharply from March highs. Right after that OPEC+ decision, Brent went from a low of around $82 a barrel to almost $100 within days (it had hit almost $140 earlier in March). WTI rose from $76 to $96 (WTI was at just over $130 in March). Both benchmarks have lost all those gains in the past two weeks, raising questions on whether OPEC+ will go for even more cuts to prop the market up again. Abdulaziz’s remarks on Monday signaled the likelihood of further cuts, especially when he said the alliance will be “ready to intervene” if there’s a need to “take further measures by reducing production to balance supply and demand”. OPEC+’s 2M-barrel cut itself has not sat well with the United States. Saudi-U.S. relations have hit a low point over oil-production disagreements this year, though WSJ reported on Monday that U.S. officials had been looking to the Dec. 4 OPEC+ meeting with some hope. Talk of a production increase emerged after the Biden administration told a federal court judge that Saudi Crown Prince Mohammed bin Salman should have sovereign immunity from a U.S. federal lawsuit related to the brutal killing of Saudi journalist Jamal Khashoggi. The immunity decision amounted to a concession to Mohammed, bolstering his standing as the kingdom’s de facto ruler after the Biden administration tried for months to isolate him. The WSJ acknowledged in its report that it would be an unusual time for OPEC+ to consider a production increase, with global oil prices falling more than 10% since the first week of November itself on a rash of Covid headlines out of China. Rising coronavirus cases in China invited new lockdown measures in some of the country’s biggest cities, drumming up concerns over slowing crude demand in the world’s largest oil importer. The country is currently struggling with its worst COVID outbreak since April, which had seen several cities placed under lockdown.

Oil Futures Experienced a Volatile Trading Session on Monday - Oil futures experienced a volatile trading session on Monday, opening slightly higher then falling to their lowest level since early January, only to recoup some of the session losses. This activity followed reports that OPEC and its allies were considering a production increase of up to a half-million barrels per day at their December meeting, followed by conflicting reports about whether the group were actually considering such a move. Trader positions were whipsawed by the reports, as they reacted to the initial report and then as they had to chore up positions. WTI for December delivery lost 35 cents per barrel, or 0.44% to $79.73, while January Brent lost 17 cents, or 0.19%, to settle at $87.45 a barrel. RBOB Gasoline for December delivery gained 1.63 cents per gallon, or 0.67% to $2.4371 and ULSD for December delivery lost 2.08 cents per gallon, or 0.59% to $3.4973. The Wall Street Journal reported that Saudi Arabia and other OPEC oil producers are discussing an output increase. It stated that an increase of up to 500,000 bpd is now under discussion for OPEC+’s December 4th meeting. The Wall Street Journal said talk of a production increase has emerged after U.S. President Joe Biden’s administration told a federal court judge that Saudi Crown Prince Mohammed bin Salman should have sovereign immunity from a U.S. federal lawsuit related to the killing of Saudi journalist Jamal Khashoggi. Later, Saudi Arabia’s Energy Minister, Prince Abdulaziz bin Salman, said the country is not discussing a potential oil output increase with other OPEC oil producers. He said “The current cut of 2 million bpd by OPEC+ continues until the end of 2023 and if there is need to take further measures by reducing production to balance supply and demand we always remain ready to intervene.”Genscape reported that crude oil stocks held in Cushing, Oklahoma in the week ending Friday, November 18th fell by 859,875 barrels on the week and by 471,120 barrels from Tuesday, November 15th.According to Refinitiv data, gasoline exports on the northwest Europe to U.S. route have reached 560,000 tons so far this month, already surpassing October’s volumes. November flows to West Africa stand at above 445,000 tons after October closed at just above 445,000 tons after October closed at an eight-month high of 1.65 million tons.IIR Energy reported that U.S. oil refiners are expected to shut in about 305,000 bpd of capacity in the week ending November 25th, increasing available refining capacity by 219,000 bpd. It also stated that offline capacity is expected to fall to 275,000 bpd in the week ending December 2nd.

Oil rises as OPEC+ focus on supply cuts outweighs recession concerns - Oil rose on Tuesday after top exporter Saudi Arabia said OPEC+ was sticking with output cuts and could take further steps to balance the market, outweighing global recession worries and concern about China’s rising COVID-19 case numbers. Saudi Arabian Energy Minister Prince Abdulaziz bin Salman on Monday was also quoted by state news agency SPA as denying a Wall Street Journal report that said OPEC was considering boosting output and sent prices plunging by more than 5%. Brent crude rose $1.45, or 1.7%, to $88.90 by 1302 GMT. U.S. West Texas Intermediate (WTI) crude was up $1.16, or 1.5%, at $81.20. “Crude oil prices are trying to recover their losses,”“That Saudi Arabia has denied there was any discussion about an increase in oil supply with OPEC and its allies has supported the market today.” The United Arab Emirates, another big OPEC producer, denied it was holding talks on changing the latest OPEC+ agreement, while Kuwait said there were no talks on an output hike. Oil prices waffle on conflicting OPEC+ output reports OPEC, Russia and other allies, known as OPEC+, meet on Dec. 4, a day before the start of European and G7 measures in retaliation for Russia’s invasion of Ukraine, which could support the market. On Dec. 5. a European Union ban on Russian crude imports is set to start, as is a G7 plan that will allow shipping services providers to help to export Russian oil, but only at enforced low prices. “The critical risk to a price cap policy is the potential for Russian retaliation, which would turn this into an additional bullish shock for the oil market,” Concerns over oil demand in the face of the U.S. Federal Reserve’s interest rate hikes and China’s strict COVID lockdown policies limited the upside. Beijing shut parks, shopping malls and museums on Tuesday and more Chinese cities resumed mass COVID testing. The Chinese capital on Monday warned that it is facing its most severe challenge of the pandemic and tightened rules for entering the city.

Oil Futures Rise as Traders Monitor Price Cap Negotiations -- Following Monday's volatile session, oil futures nearest delivery advanced on Tuesday. The gains came after Saudi Arabia's energy minister suggested OPEC+ could in fact cut oil production next month, dismissing reports of a surprise output increase, while markets await an expected announcement of a G7 price cap on Russian oil shipments that could potentially disrupt oil flows from Russian ports. European Union and G7 nations are set to announce on Wednesday a long-expected price cap on Russian oil exports, according to a Wall Street Journal report. Early indications suggest EU leaders proposed adding a new transition period for loadings of Russian crude before an embargo kicks in on Dec. 5, ensuring no short-term supply interruptions. The exact level of a price cap is yet to be decided by G7 leaders but most likely will be a fixed price between $60 and $65 per barrel (bbl). The price of Urals, the Russian crude benchmark, is currently trading in roughly the same price range. Russian Energy Minister Alexander Novak reiterated Moscow's official position that it will cut oil exports to any country that participates in the price cap mechanism. The cap would ban companies from providing shipping and other maritime services, such as insurance, brokering and financial assistance, needed to transport Russian oil anywhere in the world unless the oil is sold below the agreed price level. At the same time, some analysts claim Moscow might have amassed enough ships to keep its oil exports at current levels. Independent industry data showed Russia has secured 18 very large crude carriers, 32 Aframax and 19 smaller tankers in what is known as a "shadow fleet" of older vessels that were acquired over the past several months. Earlier in the session, oil futures got a leg up from comments by Saudi Energy Minister Prince Abdulaziz bin Salman Al Saud, who denied reports suggesting the kingdom was considering a 500,000-barrel-per-day (bpd) production increase in December, which would have partially reversed a 2 million-bpd production cut introduced in October that took effect this month. The representative from the United Arab Emirates also said it has not discussed changing the bloc's last agreement. OPEC+ meets next on Dec. 4. Despite Tuesday's higher settlements, sentiment in the oil market remains overwhelmingly bearish due to China's surging COVID-19 caseload and new quarantine measures in the country's largest cities. Beginning Thursday, Nov. 24, Beijing will require negative COVID testing results within 48 hours for entering public places including shopping malls, hotels, government buildings and factories. In addition to deaths caused by the virus, the city reported 154 symptomatic new locally transmitted COVID-19 infections and 808 asymptomatic cases, local government authorities said Monday. At settlement, West Texas Intermediate futures for January delivery added $0.91 to $80.95 per bbl, with January Brent futures on ICE gained $0.91 to $88.36 per bbl. December RBOB futures on NYMEX rallied $0.1034 to $2.5405 per gallon, with December ULSD futures declining $0.0260 to $3.4713 per gallon.

Goldman cuts oil forecast on 'lack of clarity' over G-7 Russia oil price cap, China Covid outbreaks - Goldman Sachs lowered its oil price forecast by $10 to $100 per barrel for the fourth quarter of 2022, citing rising Covid concerns in China and lack of clarity over the Group of Seven nations' plan to cap Russian oil prices."The market is right to be anxious about forward fundamentals, due to significant Covid cases in China and a lack of clarity on the implementation of the G7's price cap," Goldman economists including Jeffrey Currie said in a note, adding that more lockdowns in China would be equivalent to the deep production cuts imposed by OPEC+ of 2 million barrels a day.China recorded recorded three Covid deaths over the weekend, the country's first deaths from the virus since May this year.China's capital Beijing tightened Covid measures in the last three days as the local case count climbed to several hundred per day.The economists added that the possibility of more lockdowns in the world's top importer of oil will dent demand from it even further.

Crude oil prices climb on Russia supply uncertainty; Brent hits $88.61/bbl - Oil prices rose in early trade on Wednesday after industry data showed US crude stockpiles fell more sharply than expected last week, highlighting supply tightness ahead of a looming European Union ban and G7 price cap on Russian oil. Brent crude LCOc1 futures gained 25 cents, or 0.3%, to $88.61 a barrel at 0101 GMT, while US West Texas Intermediate (WTI) crude CLc1 futures rose 35 cents, or 0.4%, to $81.30 a barrel. Both benchmark contracts rose about 1% in the previous session as the United Arab Emirates, Kuwait, Iraq, and Algeria reinforced comments from Saudi Arabia's energy minister that the Organization of the Petroleum Exporting Countries (OPEC) and allies, together called OPEC+, were not considering boosting oil output. OPEC+ next meets to review output on Dec. 4. Uncertainty over how Russia will respond to plans by the Group of Seven (G7) nations to cap Russian oil prices further supported the market, analysts said. The price cap, yet to be announced but due to be in place from Dec. 5, will probably be adjusted a few times a year, a senior US Treasury official said on Tuesday. "Traders closely monitor Russia's exports and will look for how much they might trim the nation's foreign sales in retaliation, which could be a bullish fillip for oil prices," SPI Asset Management managing partner Stephen Innes said in a note to clients. Buoying prices on Wednesday, US crude inventories fell by about 4.8 million barrels for the week ended Nov. 18, data from the American Petroleum Institute showed, according to market sources. Analysts polled by Reuters on average had expected a 1.1 million barrel drawdown in crude inventories. However, on a bearish note, API data showed distillate stocks, which include heating oil and jet fuel, rose by about 1.1 million barrels compared with analysts' expectations for a drop of 600,000 barrels.

Oil Falls 2% on Signs EU Softening Russian Oil Sanctions - - Oil futures fell more than 2% early Wednesday on indications European Union and G7 nations are softening the language dictating looming price cap regulations on Russian oil exports in an apparent effort to cause minimal disruption to Russian oil trade this winter. Ambassadors from the 27 European countries, G7 nations and the United States are currently discussing a maritime ban on providing shipping and other services for Russian oil shipments unless they fall under a certain price level. The aim of this measure is to take advantage of Western control of the world's maritime insurance, financing, and shipping services to starve Vladimir Putin's regime of revenues to conduct the war in Ukraine. However, that price level could be as high as $75 barrel (bbl), according to media reports published Wednesday morning, which is well above the current price of $60 bbl for Urals, the Russian crude benchmark, now trading on the global market. Russians were forced to offer steep discounts against the global Brent crude benchmark to sell oil even to their loyal customers in Asia amid a backlash for dealing with Putin's regime. Additionally, EU leaders have reportedly proposed adding a new transition period for loadings of Russian crude before an embargo kicks in on Dec. 5, ensuring no short-term supply interruptions. The softening of the language for the price cap comes after several threats were made by the Russian government that Moscow would cut all oil exports to any country that participates in the measure, which could further stoke price volatility and inflation in the West. Additionally, Russian energy giant Gazprom threatened to cut all gas shipments sent via Ukraine as early as next week just as cold winter weather descends upon the region that could see Europeans start tapping storage. At the same time, some analysts claim Moscow might have amassed enough ships to keep its oil exports at current levels even if it rebuffs the G7 price cap. Independent industry data show Russia has secured 18 very large crude carriers, 32 Aframax and 19 smaller tankers in what is known as a "shadow fleet" of older vessels that were acquired over the past several months. This week's volatility in the oil market also follows comments by Saudi Energy Minister Prince Abdulaziz bin Salman Al Saud, who denied reports suggesting the kingdom was considering a 500,000 barrels per day (bpd) production increase in December, which would have partially reversed a 2 million bpd production cut introduced in October. The representative from the United Arab Emirates also said it has not discussed changing the bloc's last agreement. OPEC+ meets next on Dec. 4. Wednesday's move lower came despite the American Petroleum Institute reporting late Tuesday U.S. crude oil stockpiles tumbled 4.8 million bbl last week, nearly six times above consensus for an 800,000 bbl drawdown. If confirmed by official data, this would follow a 5.4 million bbl fall in domestic crude oil inventories for the second week of November. Near 7:15 a.m. EST, WTI futures for January delivery dropped $1.66 to $79.30 bbl, with January Brent futures on ICE falling $2.07 to $86.32 bbl. December RBOB futures on NYMEX declined $0.0696 to $2.4709 gallon, with December ULSD futures falling $0.0213 to $3.4500 gallon.

WTI Extends Losses After Big Product Inventory Builds - Oil prices are tumbling this morning amid Europe's Russian Oil Price Cap scheme discussions about a price cap between $65 and $70 and rapidly spreading lockdowns across China impacting demand.“At current price levels, the plan seems ineffective,” “It will be crucial to see the details of the proposed cap to evaluate the price impact.”Beijing asked residents not to leave the city unless necessary, to stem the spread of the virus. API

  • Crude -4.8mm (-2.20mm exp)
  • Cushing -1.40mm
  • Gasoline -400k
  • Distillates +1.1mm


  • Crude -3.69mm (-2.20mm exp)
  • Cushing -887k
  • Gasoline +3.058mm - biggest build since July
  • Distillates +1.718mm - biggest build since September

While the crude draw was bigger than expected (and smaller than API), the surge in product stocks is perhaps more worrisome from a demand perspective... Graphics Source: Bloomberg With the Midterms behind them, the Biden admin drew only 1.6mm barrels (the smallest draw since February) from the SPR (now at the lowest level since March 1984)... Crude imports from Saudi Arabia jumped to their highest since June. Inflows from Iraq were also up, recouping most of the previous week’s loss and pushing total imports from the Middle East back above 1 million barrels a day. US Crude production was unchanged last week despite rising rig counts... WTI was sliding to around $77.50 ahead of the official data and dropped to a $76 handle after the big product builds...

Oil Slides Over 3% on Russian Price Cap Talks, U.S. Gasoline Build (Reuters) - Oil prices fell more than 3% on Wednesday, continuing a streak of volatile trading, as the Group of Seven (G7) nations considered a price cap on Russian oil above the current market level and as gasoline inventories in the United States built by more than analysts' expected. Brent futures for January delivery fell $2.95, or 3.3%, to settle at $85.41 a barrel. U.S. crude fell $3.01, or 3.7%, to $77.94 per barrel. In early trade, both contracts had risen by over $1 a barrel. U.S. gasoline stocks rose by 3.1 million barrels, according to the Energy Information Administration, far exceeding the 383,000 barrel build that analysts had forecast. "The increase in gasoline supplies suggests that maybe we're seeing demand weakening or that gasoline is going on the rack ahead of the holidays." EIA data also showed a 3.7 million barrel draw in crude inventories, compared with analysts' expectations in a Reuters poll for a 1.1 million-barrel drop. Prices were hit further by reports that the G7 price cap on Russian oil could be above the level it is trading. G7 nations are looking at a price cap on Russian seaborne oil in the range of $65-70/bbl, according to a European official on Wednesday. Meanwhile, Urals crude delivered to northwest Europe is trading around $62-$63/bbl, although it is higher in the Mediterranean at around $67-$68/bbl, Refinitiv data shows. Because production costs are estimated at around $20 per barrel, the cap would still make it profitable for Russia to sell its oil and in this way prevent a supply shortage on the global market. A senior U.S. Treasury official said on Tuesday that the price cap will probably be adjusted a few times a year. The news added to concerns about demand from top crude oil importer China, which has been grappling with a surge in COVID-19 cases, with Shanghai tightening rules late on Tuesday. Further pressure came from an OECD economic outlook anticipating a deceleration in global economic expansion next year. "On the bright side, the OECD does not envisage a global recession and maybe this helped oil prices and stocks strengthen further," said analyst Tamas Varga at PVM Oil Associates. Price found some support after minutes from the Federal Reserve's November meeting showed most policymakers agreed it would soon be appropriate to slow interest rate hikes.

Oil Extends Losses As Supply-disruption Fears Ease - Oil prices fell on Thursday to extend steep overnight losses on easing fears of a supply disruption. Benchmark Brent crude futures slipped 0.3 percent to $85.15 a barrel, while WTI crude futures were down 0.2 percent at $77.80. Both contracts fell more than 3 percent on Wednesday as data showed a larger-than-expected build-up in U.S. gasoline inventories. Data released by U.S. Energy Information Administration (EIA) showed crude inventories dropped by 3.7 million barrels in the week ended November 18th, larger than an expected drop of about 1.1 million barrels. Gasoline inventories increased by 3.1 million barrels last week versus forecasts for an increase of just 383,000 barrels, while distillate stockpiles saw an increase of 1.7 million barrels in the week. Meanwhile, supply-disruption fears eased in the wake of reports suggesting that the Group of Seven nations are seeking a price cap for Russian seaborne exports in the range of $65-70 a barrel, well above the former Soviet Union's cost of production. European Union governments have not yet agreed on a price and more talks are scheduled for today.

Oil steady as Russian price-cap talks drag on and demand lags - Oil was little changed as the European Union considered a higher-than-expected price cap on Russian crude and evidence mounted of challenges to demand. West Texas Intermediate rose 3 cents Thursday after trading in a narrow range and with volumes thin due to the U.S. Thanksgiving holiday. EU diplomats are locked in negotiations over how strict the Russian mechanism should be, after discussing capping the country’s seaborne exports at US$65 to US$70 a barrel. The resumption of talks to finalize the cap was delayed beyond Thursday as more time was needed to overcome the differences, according to people familiar with the matter. Goldman Sachs Group Inc. said the higher price cap being considered may reduce the risk of Moscow retaliating, though it expressed doubt that the mechanism could be enforced. Mounting headwinds in the two largest economies threaten energy demand. In the U.S., Federal Reserve economists briefed policymakers that the chance of a recession in the next year had risen to almost 50 per cent as interest rates climb. In China, officials are pressing on with aggressive efforts to check the spread of Covid-19, ordering lockdowns and movement curbs as daily virus cases swelled to near 30,000 -- the most during the pandemic. “A static price in general just doesn’t work,” “They’re trying to have the best of both worlds. Either you depress Russian oil to zero, which global oil markets do not want, or you let Russian oil flow.” WTI for January delivery rose 3 cents to US$77.97 a barrel as of 2:16 p.m. in New York after falling 3.7 per cent on Wednesday. Price didn’t settle Thursday due to Thanksgiving holiday in the U.S. Brent for January settlement was down 7 cents at US$85.34 a barrel. Crude has tumbled this month, unraveling the gains made in October after the Organization of Petroleum Exporting Countries and its allies decided to reduce production. While the price-cap plan had been seen as potentially supportive of oil should it result in lower output, a high cap may end up having a minimal impact on trading. Key metrics are signaling a weaker market, with WTI’s prompt spread is in contango, a pattern that points to ample near-term supply. Physical differentials have fallen sharply in recent weeks, with Kazakhstan’s CPC crude the latest to plunge on a combination of weak demand and robust supply.

Oil prices fall 2% as Chinese demand worries linger (Reuters) -Oil prices fell 2% on Friday in thin market liquidity, closing a week marked by worries about Chinese demand and haggling over a Western price cap on Russian oil. Brent crude futures settled down $1.71, or 2%, to trade at $83.63 a barrel, having retraced some earlier gains. U.S. West Texas Intermediate (WTI) crude futures were down $1.66, or 2.1%, at $76.28 a barrel. There was no WTI settlement on Thursday due to the U.S. Thanksgiving holiday and trading volumes remained low. Both contracts posted their third consecutive weekly declines after hitting 10-month lows this week. Brent ended the week down 4.6%, while WTI fell 4.7%. Brent and WTI's market structure implies current demand is softening, with backwardation, defined by front-month prices trading above contracts for later delivery, having weakened markedly in recent sessions. For two-month spreads, Brent and WTI's structures even dipped into contango this week, implying oversupply with near-term delivery contracts priced below later deliveries. China, the world's top oil importer, on Friday reported a new daily record for COVID-19 infections, as cities across the country continued to enforce mobility measures and other curbs to control outbreaks. This is starting to hit fuel demand, with traffic drifting down and implied oil demand around 1 million barrels per day lower than average, an ANZ note showed. Meanwhile, G7 and European Union diplomats have been discussing a Russian oil price cap between $65 and $70 a barrel, but an agreement has still not been reached. A meeting of European Union government representatives, scheduled for Friday evening to discuss the proposal, was cancelled, EU diplomats said. The aim is to limit revenue to fund Moscow's military offensive in Ukraine without disrupting global oil markets, but the proposed level is broadly in line with what Asian buyers are already paying. Poland is seeking German support to slap EU sanctions on the Polish-German section of the Druzhba crude pipeline so Warsaw can abandon a deal to buy Russian oil next year without paying penalties, two sources familiar with the talks said. Trading is expected to remain cautious ahead of an agreement on the price cap, due to come into effect on Dec. 5 when an EU ban on Russian crude kicks off, and ahead of the next meeting of the Organization of the Petroleum Exporting Countries and allies on Dec. 4.

Oil Declines for Third Consecutive Week | Rigzone --Oil posted a third weekly loss as the European Union suspended talks over a Russian oil price cap amid disagreements between member states. West Texas Intermediate futures fell 2.1% to settle at $76.28 a barrel after trading in a more than $3 range on Friday. European diplomats remain locked in talks over how strict the cap should be, having previously proposed a range of $65-$70. Poland and the Baltics felt the cap was too generous to Russia and now diplomats have postponed discussions until Monday. The cap talks come before an OPEC+ meeting early next month. Iraq and Saudi Arabia’s oil ministers met on Thursday and said the group could take further measures if required to achieve stability in the market. Crude has declined in November, overturning the gains made in October after the Organization of Petroleum Exporting Countries and allies agreed to reduce production. Mounting headwinds to crude demand have stemmed from China’s tighter economic lockdowns and fears of a US recession. “Our balances point to slight oversupply until the end of 1Q,” Morgan Stanley analysts including Martijn Rats and Amy Sergeant said in a note to clients. “For now, the oil market is faced with macroeconomic headwinds.” WTI for January delivery fell $1.66 to settle at $76.28 in New York. There was no settlement on Thursday due to Thanksgiving holiday in the US. Brent for January settlement fell $1.71 to settle at $83.63. The price-cap plan forms part of the efforts by the EU and the Group of Seven to punish President Vladimir Putin for the invasion of Ukraine by reducing Moscow’s revenue, while at the same time allowing other states to continue imports. The introduction of a cap by western countries will “with high probability” have a negative effect on the energy market, Putin said..

Taliban in Afghanistan received $7.1 billion in U.S. weapons - The Taliban in Afghanistan received $7.1 billion in US weapons after the American withdrawal in 2021. A new US DoD report reveals that the military aid for Afghanistan has never been properly categorized by the Pentagon, meaning the U.S. military has no idea how many weapons it “inadvertently” left to the Taliban when they left the country last year.According to a new report by the Inspector General for the Reconstruction of Afghanistan (SIGAR), the U.S. military provided only “limited, inaccurate and untimely information about the weapons it left behind.”The report estimates that $7.1 billion worth of military equipment was left in Afghanistan which was previously supplied to the Government of Afghanistan and to the Afghan National Defense and Security Force (ANDSF). Since 2009, SIGAR and the Office of the Inspector General have warned about accountability gaps and tracking problems in Afghanistan.The report states that the Pentagon “did not meet its own requirements for overseeing sensitive equipment and did not inventory 60 % of defense items with enhanced monitoring requirements — those containing sensitive technology — between May 2019 and April 2020 due to security restrictions and travel restrictions.” In other words, the U.S. government doesn’t really know which equipment or how much of it was left in Afghanistan, but it cost at least $7.1 billion.An August DoD report says that at the time the Taliban took power, ANDSF had in its stockpile about 316,000 small arms supplied by the United States since 2005.This report also notes longstanding and well-known issues with the invertarization management system used to catalog stocks at bases in Afghanistan, including a chaotic Microsoft Excel spreadsheet system and even handwritten inventories used to circumvent the problem. Many of the bases either did not have access to the Internet or electricity.SIGAR noted that at least 70 tactical vehicles (MRAP) and 80 aircraft were left behind at Hamid Karzai International Airport in August 2021 in the final weeks of the withdrawal.The U.S. withdrawal was chaotic and catastrophic, as the U.S.-backed Afghan government failed to hold on to power against the Taliban attack long enough for U.S. forces to complete their withdrawal from the country.After the Taliban seized power, the United States and much of the world cut ties with Afghanistan and refused to recognize the new government, leading to a complete collapse of Afghanistan’s already fragile economy and to humanitarian crisis.

The Pentagon Has No Idea How Much Military Equipment It Actually Left Behind In Afghanistan --It’s been more than a year since the U.S. military’s chaotic withdrawal from Kabul, and the Defense Department actually has no clear idea how much U.S.-funded military equipment fell into the Taliban’s hands in Afghanistan, according to a new report from a top government watchdog. While a previous Pentagon inspector general report in August estimated that roughly $7.12 billion in U.S.-funded military equipment was still in the inventory of the Afghan National Defense and Security Forces (ANDSF) when the central government in Kabul collapsed, a new assessment from the Special Inspector General for Afghanistan Reconstruction (SIGAR) revealed last week that the Pentagon “has struggled for years with accurately accounting for the equipment it provided to the ANDSF.”The lack of accurate accounting stemmed from using the Core Inventory Management System (Core IMS) despite “limitations with the utility and accuracy of that system” reported by SIGAR since at least 2008. Indeed, a 2020 DoD IG audit revealed that Core IMS was never utilized at more than half of the Afghan-maintained weapons storage sites across the country simply because they lacked consistent access to electricity or the internet.In addition, U.S. military officials concluded since at least 2014 that ANDSF personnel were “not entering information correctly into the system,” and maintained inventory records using “hard copy documents, handwritten records, and some Microsoft Excel spreadsheets,” according to the SIGAR report — the same system that created the conditions for ‘ghost soldiers,” or nonexistent personnel created solely to funnel money and equipment to (often-illicit) sources.“As a result of the issues with the Core Inventory Management System and the regularly documented issues with DoD’s ability to account for equipment provided to the Afghan government, it remains unclear whether the $7.1 billion figure reported to Congress is accurate,” according to the SIGAR assessment.Translation: the U.S. has no clear picture of how much military equipment it accidentally funneled into Taliban arsenals as the militant group swept across the country.As Task & Purpose previously reported, that $7.12 billion amount originally reported to Congress represents roughly 38% of the $18.6 billion allocated for the procurement of military equipment for the ANDSF between 2005 and 2021, according to the August DoD IG report, a total that included military aircraft, aircraft munitions, small arms, and ground vehicles including Humvees, MRAPs, and other tactical vehicles.

Russian troops block US military convoy in oil-rich Syria’s Hasakah region (VIDEO) -- Russian troops have blocked a US military convoy in northeastern Syria, the latest in a series ofstandoffs between American troops and local residents. Russian and American forces have faced off in Syria’s Hasakah region, an area rich in oil fields, several times in the past month. Both countries maintain bases in northeastern Syria.A video published on Twitter shows Russian troops confronting US convoy and forcing them to take another route as the road is blocked by Russian armored vehicles. Few days ago a US military convoy was again forced to retreat from a village near Hasaqa after local residents blocked the road throwing stones at the foreign vehicles. The incident was reported on 16 November near Al-Buladia in north-eastern Syria.A video published on Twitter shows the American convoy being attacked with stones by local residents forcing them to retreat.Stand-offs between US troops and local residents in Qamishli were also reported last month after an American military helicopter landed in a village near Qamishli and US forces reportedly killed a local citizen in an air-drop operation. Local media reports identified the victim as Rakan Abu Hayel from Tuwaimin village in the eastern countryside of Qamishli. According to the reports, he was assassinated and his family was detained. The US Army justifies its presence in Syria, with the Pentagon claiming that the deployment is aimed at preventing the oilfields in the area from falling into the hands of ISIS. However, the Syrian government claims US troops are in Hasakah only to safeguard oil tankers which have been smuggling oil to Iraq. Former US president Donald Trump admitted on several occasions that American troops were in Syria “for the oil”.

Turkey bombs Kurdish forces in Syria and Iraq - The Turkish Defense Ministry announced early Sunday morning the start of “Air Operation Claw-Sword” targeting Kurdish nationalist militias in northern Iraq and northern Syria. According to the statement, Qandil, Asos and Hakurk in northern Iraq and Kobane, Tel Rifaat, Cizire and Derik in northern Syria were hit. Mass protests were reportedly organized in many places in northern Syria against the air strikes. People inspect a site damaged by Turkish airstrikes that hit an electricity station in the village of Taql Baql, in Hasakeh province, Syria, Sunday, November 20, 2022. [AP Photo/Baderkhan Ahmad] The ministry said the airstrikes “were carried out in line with the right of self-defense under Article 51 of the United Nations Charter.” Turkish warplanes are reportedly using Syrian airspace, which is controlled by Russia, whose government is therefore tacitly allowing the bombings to take place. This operation against the US-backed People’s Protection Units (YPG), the armed wing of the Democratic Union Party (PYD), and the Kurdistan Workers’ Party (PKK) comes amid NATO war against Russia in Ukraine. According to the Turkish Defense Ministry statement, the bombardment targeted “shelters, bunkers, caves, tunnels, ammunition depots and so-called headquarters and training camps” belonging to the PKK and YPG, claiming that civilians were not harmed. However, according to ANHA (Hawar News Agency), 11 civilians, including ANHA reporter İsam Ebdullah, were killed and 6 people, including another journalist, were wounded in the bombardments. The report claimed that 14 Syrian soldiers were also killed. Syria’s state-owned Sana news agency confirmed the deaths of Syrian soldiers but did not state how many were killed. Turkish Interior Ministry blamed the PKK and YPG for a rocket attack on the Öncüpınar Border Gate in Kilis yesterday, which injured 8 security personnel. Anadolu Agency also reported that four rockets were fired at Karkamış district of Gaziantep province from northern Syria yesterday evening, and that the rockets landed in empty areas. The YPG was held responsible for the rockets in the report. Farhad Shami, head the media center of the Syrian Democratic Forces (SDF), of which the YPG is the backbone, reported that airstrikes destroyed the COVID-19 Hospital in Kobane, the power plant in Derik and grain stores in Dahir al Arab. SDF General Commander Mazlum Ebdi warned in a statement that the conflict could escalate. He said, “We don’t want a big war to break out. But if the Turkish state insists on war against us, we are ready for a great resistance. The war is not only limited to here, it spreads everywhere and everyone is affected by this war.” The PYD added, “Russia and the International Coalition led by the United States are responsible for the atrocities committed by the Turkish state against our people.”

'A Nightmare': Iran Intensifies Deadly Crackdown In Kurdistan Region As Protests Rage - Iranian authorities have intensified their deadly crackdown in the country’s western Kurdistan region, which has been the epicenter of the anti-establishment protests that have raged for months. Human rights groups say government forces have killed more than a dozen people in predominately Kurdish cities in the past 24 hours. The bloodshed comes amid reports of heavily armed troops being deployed in the region. Activists say the violence is an attempt by the authorities to create fear among protesters and quell the nationwide protests that have rocked the country for the past two months. The rallies erupted following the September 16 death of Mahsa Amini, a 22-year-old Iranian Kurd who died shortly after she was arrested by Iran’s morality police for allegedly violating the country’s hijab law. What began as protests against the brutal enforcement of the mandatory head scarf has snowballed into one of the biggest threats to Iran’s clerical establishment, which has ruled since the Islamic Revolution in 1979. “The Islamic republic is using such intense violence in Kurdistan to silence the protests all over Iran,” Zhila Mostajar from Hengaw, a rights group registered in Norway that reports on Iran’s Kurdish region, told RFE/RL. “The authorities think that by suppressing the protests in Kurdistan they will send a warning to people in other parts of the country,” added Mostajar, who is based in neighboring Iraq’s semiautonomous Kurdish region.Hengaw said that at least 13 people have been killed in mainly Kurdish cities since November 20, including seven in Javanrud, four in Piranshahr, and one each in Dehgolan and Bukan. At least 378 people, including 47 children, have been killed by government forces across the country, according to the Oslo-based Iran Human Rights (IHR). At least 83 people have been killed in Kurdistan, Kermanshah, and West Azerbaijan, three provinces with significant Kurdish populations, IHR said. There were “intense confrontations” between protesters and security forces in Javanrud, a city in Kermanshah Province, according to Hengaw. Videos uploaded on social media on November 21 purportedly showed several wounded protesters lying on the streets amid the sound of heavy gunfire.

Israel gives ultimatum to Russia over Iranian weapons supplies - Israel could supply Ukraine with high-precision ballistic missiles if Russia did not stop cooperation with Iran, according to Israeli media. Israeli Ambassador to Russia Alexander Ben Zvi held a series of meetings with deputy head of the Russian diplomatic department Mikhail Bogdanov, during which the situation in Ukraine was discussed, the Israeli TV channel “Kan-11” reported.Ben Zvi conveyed Israel’s ultimatum over the supply of Iranian drones and ballistic missiles to Moscow.According to a source in the Israeli Foreign Ministry, the head of the National Security Council of Israel, Eyal Hulata, warned Russia against using Iranian weapons – otherwise Tel Aviv could supply Kiev with high-precision ballistic missiles that will be used against Russian units.The foreign minister of Iran, Hossein Amir Abdollahian, stated that Tehran had transferred “a certain number of unmanned aerial vehicles” to Russia before the war in Ukraine.Russia has purchased even more powerful Iranian Arash-2 drones, according to a statement by the Ukrainian armed forces. So far there has been no official confirmation of this information.However, a number of video evidence show Iranian Sahed-136 drones (the Russian modification Geran-2) being massively used in the last months against Ukrainian major cities destroying critical infrastructure.Iran has supplied Russia not only with attack drones but also with powerful surface-to-surface missiles, according to intelligence sources quoted by The Washington Post. These are Iran’s Fateh-110 and Zolfaghar – short-range ballistic missiles capable of striking targets at distances of 300 and 700 kilometers.

Israeli armored vehicles supplied to Ukraine via intermediary - Even though Israel has not officially supplied weapons to Ukraine, Israeli armored vehicles have appeared on the front line in Kherson. Israel has already transferred armored vehicles to Ukraine – GAIA Amir armored vehicles, according to photos and videos published on Telegram.According to Avia Pro, Israel has delivered at least 10 GAIA Amir armored vehicles to Ukraine. To bypass the official position of Israel to not deliver military aid to Ukraine, the exports were carried out through an intermediary country, Germany, according to Avia pro sources. One of these armored vehicles was recently destroyed by a Russian Lancet attack drone.Earlier, Israel stated that the supply of Israeli weapons to Ukraine through any other country in the world does not mean that the weapons were provided by the Israeli side, hinting at the readiness to transfer much more serious weapons to Ukraine if such agreements are reached with Kyiv.Experts say that Israel may soon consider the possibility of transferring other weapons to Ukraine, as the Israeli Prime Minister Benjamin Netanyahu has already stated.Before the parliamentary elections Netanyahu said that if he was re-elected and became a prime-minister Israel would supply weapons to Ukraine. Netanyahu stressed in an interview with USA Today that “we all have sympathy for Ukraine” when asked about possible weapons supplies to Kiev.The Ukrainian army uses the GAIA Amir multifunctional armored vehicles manufactured by the Israeli company Gaia Automotive Industries. Officially, Israel does not supply weapons to Ukraine, and it is not known how the Amir armored vehicles ended up in the Kherson region, as their manufacturer prohibits re-export.The GAIA Amir armored vehicle was first introduced in 2018 and is used for patrolling, personnel transfer and evacuation of wounded troops. The multipurpose 4×4 armored vehicle has protection against mines with a mass of charge up to 6 kg and protection against bullets of 7.62 mm caliber. It is capable of carrying up to 12 soldiers and 3 tons of cargo, with a maximum speed of 122 km / h.

Israel: Ultra-Far-Right Ben-Gvir Given Nat'l Security Ministry - As though KKK took over Homeland Security in US -- The Israeli newspaper Arab 48 reports that the Likud Party of Prime Minister Binyamin Netanyahu signed a deal on Friday with what the paper calls the “fascist” Jewish Power party of Itamar Ben-Gvir giving the latter the post of minister of national security. Jewish Power will also get the ministry of heritage, which oversees religious sites, including, potentially, Palestinian ones or those shared with Palestinians. It was also given the ministry of the Negev and Galilee, which, according to BBC Monitoring, “regulates settlement expansion” in the West Bank.There had previously been a minister of public security overseeing the police, but the post will now be expanded. Arab 48 says that the agreement gives Ben-Gvir and his party centralized control of several law enforcement agencies that had previously been distributed among several ministries. It also creates a new “national guard” force with a wide mandate, which sounds pretty ominous. Ben-Gvir will have authority over Israeli border police, including those in the Palestinian West Bank. He had earlier called for relaxed rules of engagement under which Israeli security forces could use lethal force against Palestinians without let or hindrance.The paper quotes an Israeli official in law enforcement as saying in response, “This matter will turn the border patrol in the West Bank into Ben-Gvir’s private police force in the (Occupied) Territories.”The Palestinian West Bank, under the Israeli jackboot, is already a seething cauldron and is experiencing a low-intensity civil war. Some Palestinians among youth in Jenin have turned to guerrilla violence, while Israeli squatters on Palestinian land are launching increasing numbers of attacks on Palestinians, as the Israeli army either looks on or actively helps. This situation will worsen considerably under Ben-Gvir. Al Jazeera English: “Far-right Ben-Gvir to be police minister in Israeli gov’t”The Ministry of the Negev and Galilee will, moreover, gain control of wells in the Palestinian West Bank. Palestinians’ wells often go dry because Israeli squatters dig deep and lower the level of the aquifer. This step is surreal, since the antecedents of Jewish Power have at times been on the US State Department list of terrorist organizations. Ben-Gvir has been convicted of hate speech and incitement to violence. It is as though Trump had appointed a Grand Wizard of the Ku Klux Klan as the head of Homeland Security or of Customs and Border Protection.