US oil supplies are at a 36½ year low, Strategic Petroleum Reserve is at a 39 year low; oil + oil products supplies are at an 18½ year low; DUCs rose in November for the first time in 29 months
Oil prices finished higher for a second straight week and recovered all of the losses that followed the December 5th EU ban on seaborne imports of Russian crude and the G7 price cap on Russian oil, as China's Covid reopening continued, US oil inventories dropped, and Russia threatened to cut its crude output...after rising 4.6% to $74.29 a barrel last week after an oil leak shut down the Keystone pipeline supplying diluted Canadian bitumen, a replacement for Russian oil, to US refineries, the contract price for the benchmark US light sweet crude for January delivery rose more than 1% in Asian trading on Monday, as optimism for a recovery of the Chinese economy outweighed concern over a global recession, and settled Monday's weak New York trading session 90 cents or 1.2% higher at $75,19 a barrel, as oil traders saw President Xi Jinping’s pledge to focus on the economy as supporting energy demand, even as Chinese Covid cases surged...oil prices rose again in early trade on Tuesday, shored up by a weaker dollar and a U.S. plan to restock its Strategic Petroleum Reserve, and again settled 90 cents higher at $76.09 a barrel after paring earlier stronger gains, as a worsening outlook for a major U.S. winter storm sparked fears that millions of Americans might curb travel plans during the holidays, while the more-active US benchmark crude-oil contract for February delivery finished 85 cents or 1.1% higher at $76.23 a barrel, helped by a weaker dollar that made overseas purchases of dollar-denominated crude more attractive to foreign buyers...with trading in January oil closed, the price of February oil extended its gains in after hous trading Tuesday evening, after the American Petroleum Institute reported a surprise draw from US crude supplies, and then rose in early trading on Wednesday due to an uptick in demand, after EIA data had revealed that US crude stockpiles had fallen more than anticipated last week, and finished $2.06 or 2.7% higher at $78.29 a barrel, boosted by hopes that China would further relax Covid-19 curbs after no new COVID-19 deaths were reported....oil prices rose for a fourth straight day in early trading on Thursday, with U.S. crude, heating oil and jet fuel supplies all seen tight just as a chilly blast were hitting the US and travel was set to soar for the holidays, but then turned lower and fell by around $1 a barrel in volatile trade as the impact of tighter U.S. crude stocks due to the winter storm was outweighed by fears that Federal Reserve interest rate hikes and China's rising COVID-19 cases would dent demand. before settling the session 80 cents lower at $77.49 a barrel amid risk-off sentiment in broader markets as Wall Street stocks sold off and the U.S. dollar strengthened in afternoon trading....however, oil prices reversed and rose $1 in Asian trading Friday, in expectation of a fall in supply of Russian crude. which helped to assuage fears of a hit to demand in the US due to the Arctic storm, and then rallied in pre-holiday trade to settled $2.07 higher at $79.56 a barrel after Moscow said it might cut crude output in response to the G7 price cap on Russian exports...oil prices thus finished the week 7.1% higher, while the contract price for US light sweet crude for February delivery, which had finished last week at $74.46 a barrel, ended 6.8% higher...
On the other hand, natural gas prices finished lower for the third time in four weeks, as traders looked past the Christmas cold spell to forecasts for warming weather to start the new year...after rising 5.7% to $6.600 per mmBTU last week on the potential for much colder weather for the rest of December, the contract price of US natural gas for January delivery opened at $6.111/mmBTU, down more than 7% from Friday’s closing price, as weekend forecasts turned unseasonably warm after the Christmas holiday, and continued falling to settle 74.9 cents, of more than 11% lower at $5.851 per mmBTU, as the weather outlook for later this month and early next pointed to milder conditions and easing demand...natural gas prices continued to tumble on Tuesday, falling another 52.5 cents or 9% to a seven week low of $5.326 per mmBTU, as traders looked past bitter cold and blizzards this week and fixated on forecasts for unseasonably mild conditions to close out 2022 and to start the new year...natural gas prices eked out a tiny gain on Wednesday, amid worries that a fierce and widespread winter freeze could force production interruptions, and ended the three-day run of steep losses by rising six-tenths of a cent to $5.332 per mmBTU...natural gas prices turned lower again on Thursday after the EIA reported a smaller-than-expected draw from gas storage last week and settled down 33.3 cents at a two month low of $4.999 per mmBTU...natural gas prices finally turned higher on Friday, as extreme cold boosted spot prices to their highest level in years across much of the US, and cut gas output to a nine-month low by freezing oil and gas wells in Texas, Oklahoma, North Dakota, Pennsylvania and elsewhere, as prices finished 8.0 cents higher at $5.079 per mmBTU, but still ended 23.0% lower for the week...
The EIA's natural gas storage report for the week ending December 16th indicated that the amount of working natural gas held in underground storage in the US fell by 87 billion cubic feet to 3,325 billion cubic feet by the end of the week, which meant our gas supplies were 45 billion cubic feet, or 1.3% less than the 3,370 billion cubic feet that were in storage on December 16th of last year, but 22 billion cubic feet, or 0.7% more than the five-year average of 3,303 billion cubic feet of natural gas that were in storage as of the 16th of December over the most recent five years....the 87 billion cubic foot withdrawal from US natural gas working storage for the cited week was less than the average forecast for a 93 billion cubic feet withdrawal by a Reuters poll of analysts, but much more than the 60 billion cubic feet that were pulled from natural gas storage during the corresponding week of 2021, but still much less than the average 124 billion cubic feet of natural gas that have typically been withdrawn from our natural gas storage during the same winter 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 December 16th indicated that after a big drop in our oil imports and a big decrease in those mysterious oil supplies that could not be accounted for, we needed to pull oil out of our stored commercial crude supplies for the 5th time in 6 weeks, and for the 16th time in the past 35 weeks, despite another sizable release of oil from the SPR. Our imports of crude oil fell by an average of 1,048,000 barrels per day to average 5,819,000 barrels per day, after rising by an average of 855,000 barrels per day during the prior week, while our exports of crude oil rose by 44,000 barrels per day to average 4,360,000 barrels per day, which together meant that the net of our trade in oil worked out to an import average of 1,459,000 barrels of oil per day during the week ending December 16th, 1,092,000 fewer barrels per day than the net of our imports minus our exports during the prior week. Over the same period, production of crude from US wells was reportedly 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 13,559,000 barrels per day during the December 16th reporting week…
Meanwhile, US oil refineries reported they were processing an average of 15,976,000 barrels of crude per day during the week ending December 16th, an average of 150,000 fewer 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 1,363,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US. So, based on that reported & estimated data, the crude oil figures from the EIA for the week ending December 16th appears to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 1,054,000 barrels per day less than what our oil refineries reported they used during the week. To account for that obvious disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+1,054,000) 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. Moreover, since last week’s “unaccounted for crude oil” was at a record (+2,259,000) barrels per day, that means there was a 1,204,000 barrel per day difference between this week's balance sheet error and the EIA's crude oil balance sheet error from a week ago, and hence the changes to supply and demand from that week to this one that are indicated by this week's report are off by that much, thus rendering those comparisons virtually meaningless.... However, since most everyone treats these weekly EIA reports as gospel, and since these weekly 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 1,363,000 barrel per day decrease in our overall crude oil inventories left our oil supplies at 796,858,000 barrels at the end of the week, which was our lowest total oil inventory level since January 17th, 1986, and therefore at a new 36 1/2 year low....Our oil inventories decreased this week as an average of 842,000 barrels per day were being pulled out of our commercially available stocks of crude oil, while 521,000 more barrels per day of oil were being pulled out of our Strategic Petroleum Reserve. That draw on the SPR 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 began fluctuating during the summer because the administration had also 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. Friday of this past week the administration announced an initial token purchase of three million barrels under that plan, for oil to be delivered back to the SPR in February. 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 277,523,000 barrels of oil have now been removed from the Strategic Petroleum Reserve over the past 29 months, and as a result the 378,624,000 barrels of oil that still remain in our Strategic Petroleum Reserve is now the lowest since December 30th, 1983, or nearly at a 39 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 Biden release program, still scheduled to run through December, will have released almost a third of what remained in the SPR when the program started, and leave us with what is less than a 20 day supply of oil at the current consumption rate as we head into the new year.
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,184,000 barrels per day last week, which was 4.0% less than the 6,442,000 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 as 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 6,000 barrels per day lower at 450,000 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 90.2% of their capacity while using those 15,976,000 barrels of crude per day during the week ending December 16th, down from their 92.2% utilization rate during the prior week, a fairly normal utilization rate for mid December. The 15,976,000 barrels per day of oil that were refined this week were still 1.0% more than the 15,818,000 barrels of crude that were being processed daily during week ending December 17th of 2021, while 5.9% less than the 16,980,000 barrels that were being refined during the prepandemic week ending December 20th, 2019, when our refinery utilization was at 93.3%, as refinery utilization typically rises in late December ...
Even with the decrease in the amount of oil being refined this week, gasoline output from our refineries was quite a bit higher, increasing by 358,000 barrels per day to 9,552,000 barrels per day during the week ending December 16th, after our gasoline output had increased by 129,000 barrels per day during the prior week. This week’s gasoline production was still 3.9% less than the 9,942,000 barrels of gasoline that were being produced daily over the same week of last year, and 7.0% below the gasoline production of 10,269,000 barrels per day during the prepandemic week ending December 20th, 2019. On the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 66,000 barrels per day to 5,102,000 barrels per day, after our distillates output had decreased by 164,000 barrels per day during the prior week. But even with those decreases, our distillates output was still 5.2% more than the 4,852,000 barrels of distillates that were being produced daily during the week ending December 17th of 2021, while 6.3% less than the 5,444,000 barrels of distillates that were being produced daily during the week ending December 20th 2019...
With the increase in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the 6th week in a row and for the 9th time in 19 weeks, increasing by 2,530,000 barrels to 213,768,000 barrels during the week ending December 16th, after our gasoline inventories had increased by 4,496,000 barrels during the prior week. Our gasoline supplies rose by less this week because the amount of gasoline supplied to US users rose by 459,000 barrels per day to 8,714,000 barrels per day, while our exports of gasoline fell by 316,000 barrels per day to 887,000 barrels per day, and while our imports of gasoline fell by 239,000 barrels per day to 551,000 barrels per day. After 6 consecutive gasoline inventory increases, our gasoline supplies were 0.9% more than last December 17th's gasoline inventories of 224,118,000 barrels, but still about 2% below the five year average of our gasoline supplies for this time of the year…
With the decrease in our distillates production, our supplies of distillate fuels decreased for the 1st time in 6 weeks, and for the 27th time over the past year, falling by 242,000 barrels to 119,929,000 barrels during the week ending December 16th, after our distillates supplies had increased by 1,364,000 barrels during the prior week. Our distillates supplies also fell this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, increased by 247,000 barrels per day to 4,015,000 barrels per day, and because our imports of distillates fell by 99,000 barrels per day to 188,000 barrels per day, while our exports of distillates fell by 173,000 barrels per day to 1,310,000 barrels per day... After fifty-two inventory withdrawals over the past eighty-six weeks, our distillate supplies at the end of the week were were still 3.4% below the 124,154,000 barrels of distillates that we had in storage on December 17th of 2021, and about 7% below the five year average of distillates inventories for this time of the year...
Meanwhile, after a big drop in our oil imports and a big drop in our “unaccounted for crude oil”, our commercial supplies of crude oil in storage fell for the 12th time in 19 weeks and for the 31st time in the past year, decreasing by 5,895,000 barrels over the week, from 424,129,000 barrels on December 9th to 418,234,000 barrels on December 16th, after our commercial crude supplies had increased by 10,231,000 barrels over the prior week. After this week's decrease, our commercial crude oil inventories slipped to around 7% below the most recent five-year average of crude oil supplies for this time of year, but were still around 24% more than the average of our crude oil stocks as of the third weekend of December 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 December 16th were 1.3% less than the 423,571,000 barrels of oil we had in commercial storage on December 17th of 2021, and 16.3% less than the 499,534,000 barrels of oil that we had in storage on December 18th of 2020, and 5.2% less than the 441,359,000 barrels of oil we had in commercial storage on December 20th 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. After the big crude decreases we've already noted for this week, the total of our oil and oil product inventories, including those in the Strategic Petroleum Reserve and those held by the oil industry, and thus including everything from gasoline and jet fuel to propane/propylene and residual fuel oil, fell by 15,203,000 barrels this week, from 1,613,439,000 barrels on December 9th to 1,598,236,000 barrels on December 16th, after our total inventories had increased by 9,231,000 barrels during the prior week. This week's decrease left our total petroleum liquids inventories down by 190,197,000 barrels over the first 50 weeks of this year, and at the lowest since June 11th, 2004, or at a new 18 1/2 year low...
This Week's Rig Count
The number of drilling rigs active in the US increased for the 12th time in the past 21 weeks with this week's report, which only covers the six days ending Thursday, December 22nd, due to the Christmas holiday....But even with 93 weekly increases over the past 117 weeks, active rigs are still 1.8% below the prepandemic rig count....Baker Hughes reported that the total count of rotary rigs drilling in the US increased by 3 rigs to 779 rigs over the past week, which was still 193 more rigs than the 586 rigs that were in use as of the December 23rd report of 2021, but was 1,150 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 2 to 622 oil rigs during the past week, after the number of rigs targeting oil had decreased by 5 during the prior week, but there are still 142 more oil rigs active now than were running a year ago, even as they amount to just 38.7% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014, and as they are still down 8.9% from the prepandemic oil rig count….at the same time, the number of drilling rigs targeting natural gas bearing formations increased by 1 to 155 natural gas rigs, which was also up by 49 natural gas rigs from the 106 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 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 haven't seen any details on either of those wells, in the past we've identified various "miscellaneous" rig activity as being for exploration, for carbon dioxide storage, and for utility scale geothermal projects...a year ago, there were were no such "miscellaneous" rigs running...
The offshore rig count in the Gulf of Mexico was unchanged at 15 rigs this week, with 14 rigs still drilling in Louisiana's offshore waters, and only one rig still drilling for oil offshore from Texas....that Gulf rig count equals 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...since there are not any rigs drilling off our other coasts, the Gulf rig count equals the national offshore count..
In addition to rigs running offshore, there are still two water based rigs drilling through inland bodies of water this week; those include 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 was just one such rig drilling on inland waters...
The count of active horizontal drilling rigs was up by 3 to 710 horizontal rigs this week, which was also 182 more rigs than the 528 horizontal rigs that were in use in the US on December 23rd of last year, but just 51.7% of the record 1,374 horizontal rigs that were drilling on November 21st of 2014....in addition, the vertical rig count was up by one to 27 vertical rigs this week, which was unchanged from the 27 vertical rigs that were operating during the same week a year ago…on the other hand, the directional rig count was down by one to 42 directional rigs this week, while those were still up by 11 from the 31 directional rigs that were in use on December 23rd of 2021….
The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of December 22nd, the second column shows the change in the number of working rigs between last week’s count (December 16th) and this week’s (December 22nd ) count, the third column shows last week’s December 16th active rig count, the 4th column shows the change between the number of rigs running on Thursday and the number running on the Thursday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 23rd of December, 2021...
checking the Rigs by State file at Baker Hughes for the changes in the Texas Permian, we find that there were 5 rigs added in Texas Oil District 8, which overlies the core Permian Delaware, and that there was another rig added in Texas Oil District 7C, which covers the southernmost counties in the Permian Midland....since the Texas Permian count was thus up by six while the national Permian basin count was only up by two, we can thus conclude that the four rigs that were pulled out of New Mexico had been drilling in the far western Permian Delaware, in the southwest corner of that state....elsewhere in Texas, there was also a rig added in Texas Oil District 6, but since the rig count in the Haynesville shale was unchanged and there was also no change in adjacent Louisiana, we have to figure that rig was targeting a basin not tracked by Baker Hughes...
in other states, the two rigs added in North Dakota were targeting the Bakken shale of the Williston basin, but the Williston rig count is only up by one because a Bakken rig was removed from Montana at the same time...meanwhile, the rig pulled out of Wyoming most likely came from the DJ Niobrara chalk, because the Colorado rig count was unchanged....the rigs added in the Granite Wash and the Mississippian shale were most likely in Oklahoma, since rigs in corresponding regions of Texas and Kansas were unchanged, and since the the Oklahoma rig count was also unchanged, that means that two rigs were pulled out of Oklahoma that had been drilling in a basin or basins not tracked by Baker Hughes, in addition to the rig pulled out of the Cana Woodford...finally, since the natural gas rig addition was also in a basin not tracked by Baker Hughes, we'd have to figure that was the rig added in Texas District 6...
DUC well report for November
Monday of last week saw the release of the EIA's Drilling Productivity Report for December, which included the EIA's November data on drilled but uncompleted (DUC) oil and gas wells in the 7 most productive shale regions (click tab 3)....after revisions that left October DUCs lower, that data showed an increase in uncompleted wells nationally for the first time in 29 months, as completions slowed while drilling of new wells increased in November, 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 22 wells, rising from a revised 4,421 DUC wells in October to 4,443 DUC wells in November, which was still 13.9% fewer DUCs than the 5,163 wells that had been drilled but remained uncompleted as of the end of November of a year ago...this month's DUC increase occurred as 1005 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during November, up by 22 from the revised 983 wells that were drilled in October, while 983 wells were completed and brought into production by fracking them, down by 7 from the 990 well completions seen in October, but up by 193 from the 790 completions seen in November of last year....at the November completion rate, the 4,443 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 nearly 14% below 2019's pre-pandemic average...
Both oil producing DUCS and natural gas DUCs rose during November, even as only two basins saw DUCs increase....the number of uncompleted wells remaining in the Permian basin of west Texas and New Mexico decreased by 8, from 1,051 DUC wells at the end of October to 1,043 DUCs at the end of November, as 427 new wells were drilled into the Permian basin during November, while 435 already drilled wells in the region were being fracked...at the same time, the number of uncompleted wells remaining in Oklahoma's Anadarko basin decreased by 3, falling from 710 at the end of October to 707 DUC wells at the end of November, as 72 wells were drilled into the Anadarko basin during November, while 75 Anadarko wells were completed....in addition, DUCs in the Eagle Ford shale of south Texas also decreased by 3, from 561 DUC wells at the end of October to 558 DUCs at the end of November, as 109 wells were drilled in the Eagle Ford during November, while 112 already drilled Eagle Ford wells were fracked....meanwhile, DUC wells in the Bakken of North Dakota were down by 2 to 499 at the end of October, as 79 wells were drilled into the Bakken during November, while 81 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 31, rising from 443 at the end of October to 474 DUC wells at the end of November, as 143 wells were drilled into the Niobrara chalk during November, 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 597 DUCs at the end of October to 594 DUCs at the end of November, 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 10, from 558 DUCs in October to 568 DUCs by the end of November, as 75 wells were drilled into the Haynesville during November, while 65 of the already drilled Haynesville wells were fracked during the same period....thus, for the month of November, DUCs in the five major oil-producing basins tracked by this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) increased by fifteen to 3,281 wells, while the uncompleted well count in the major natural gas basins (the Marcellus, the Utica, and the Haynesville) was up by seven to 1,162 DUC wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas...
Ohio bill to spur fracking in state parks and forests heads to governor's office - - -- Ohio lawmakers passed a bill meant to accelerate oil and gas drilling in state parks and on other state-owned land. The original bill focused on food processing rules when it was passed by the Ohio House of Representatives last spring, but when Ohio Senators took it up this month, they added amendments, one of which would change the language around leasing state lands for oil and gas drilling. The Ohio House passed the bill with the new amendments on Tuesday, and it is now in front of Governor Mike DeWine. Since 2011, state agencies have been authorized to lease Ohio’s public lands for oil and gas drilling, including parks, forests, nature preserves and universities. The language of that law said agencies “may” lease state lands for oil and gas production. “The key part of the amendments goes from ‘may’ to ‘shall,’” said Senator Tim Schaffer, a Republican who represents parts of central and southeastern Ohio and sponsored the amendment. “It’s designed to encourage the state agencies to see that the state legislature, that the General Assembly in Ohio, really intends for them to negotiate in good faith with these oil and gas producers,” he said. According to Schaffer, even though state agencies have been allowed to lease state lands for drilling, including fracking, they haven’t been doing it. “I don’t know if it just wasn’t a high priority or what, but some of these deals have dragged on for years and years,” he said. Schaffer said lawmakers added the amendment to this unrelated bill in response to requests by the oil and gas industry. Environmentalists are concerned this will damage the state’s parks and other natural areas.“Most people in Ohio don’t want to see oil and gas rigs, don’t want to smell air pollution, don’t want to worry about water quality in their state parks or in the other public lands that they’re out hiking in with their families,” said Nathan Johnson, public lands director for the Ohio Environmental Council Action Fund.Pennsylvania currently has a moratorium on new oil and gas leasing on state forest and park lands. Johnson believes Ohio also needs to consider if these leases are a good idea.“There’s a big question, policy-wise, whether or not the best use of those public lands is to lease them to oil and gas development, to fracking, whether that’s on economic grounds, ecological grounds, outdoor recreation grounds in particular,” he said.Under this bill, the state is taking away its own authority to decide these leases, Johnson said. He worries that if the bill becomes law, state agencies will be required to approve oil and gas leases on state lands.“An oil and gas company could knock on the state’s door and say, ‘Hey, we want to drill in this park,’ and the state legally would have no real ability to say no,” he explained. “So that’s dramatically going to change the process.”
Columbia Gas seeks quick approval for Intel pipeline - Columbia Gas of Ohio is asking for expedited state approval to build a natural gas pipeline to the site in Licking County where Intel is constructing two factories.If approved, construction of the 4.2-mile, 12-inch diameter pipeline could begin as soon as April and be brought into service in 2024, according to the company."The project will allow Columbia to provide required natural gas for Intel’s planned operations as well as serve businesses that will serve or supply Intel," the company said in documents filed with the Ohio Power Siting Board, the state agency that reviews pipeline projects."We're excited to do our part to supply gas to Intel," said Ellen Macke, director of government and public affairs for Columbia Gas of Ohio. Intel announced in January its plans to invest $20 billion to build two semiconductor factories in New Albany. It is the largest economic development project in state history. Intel has said the factories, calls fabs, will be finished in 2025.
32 New Shale Well Permits Issued for PA-OH-WV Dec 12-18 | Marcellus Drilling News - Last week (Dec. 12-18), the number of permits issued to drill new shale wells in the Marcellus/Utica bumped up nicely to 32, up from the prior week’s 20. Both Pennsylvania and Ohio issued 16 new shale permits each. West Virginia got skunked and issued none. Ascent Resources, Belmont County, Butler County, Carroll County, CNX Resources, Encino Energy, Guernsey County, Gulfport Energy, Harrison County, Indiana County, INR, LOLA Energy, Range Resources Corp, Southwestern Energy, Susquehanna County, Utica Resource Operating, Washington County, Weekly Permits, Westmoreland County
Pennsylvania Cites Shell Cracker for Emissions Violations Tied to Flaring - The Pennsylvania Department of Environmental Protection (DEP) has issued a notice of violation to Shell Chemicals Appalachia LLC for exceeding its air pollutant limits after operations began at its ethane cracker near Pittsburgh. Shell started operations at the massive complex in November. DEP said emissions of volatile organic compounds (VOC) exceeded the limits of its air quality plan approval. The plan allows VOC emissions of less than 516.2 tons over a 12-month period. The agency said Shell submitted data showing that for the one-year period ending in September, VOC emissions reached 521.6 tons. The data also showed that VOCs reached 662.9 tons for the period ending in October. DEP noted that until September, the facility’s emissions were below its 12-month rolling limits, saying the violations “are associated with initial start-up of the facility.” The NOV is a first step in the state’s enforcement process as an investigation continues, but DEP said it could ultimately take further actions. The agency has asked Shell to submit a root cause analysis and to detail steps to minimize flaring. VOCs are emitted as gases from solids or liquids and can have adverse health effects, according to the U.S. Environmental Protection Agency. hell’s cracker is the first of its kind to be built in the United States outside the Gulf Coast in more than 20 years. It was sanctioned in 2016 to take advantage of Appalachian ethane supply from the Marcellus and Utica shales, along with a strong polyethylene market in the region. It is located in Beaver County on 384 acres along the Ohio River, about 30 miles northwest of Pittsburgh. The facility is designed to produce 1.5 million metric tons per year (mmty) of ethylene and 1.6 mmty of polyethylene, which are key building blocks for plastics. About 70% of the North American marketplace for polyethylene is within a 700-mile radius of the site, according to Shell. A two-leg pipeline system collects ethane from processing and fractionation facilities in Ohio, Pennsylvania and West Virginia. The system has the capacity to move 100,000 b/d of ethane to the cracker under supply deals with approximately 10 Appalachian oil and gas producers.
CNX fined $200K for spills of fracking fluids in Greene County - The Pennsylvania Department of Environmental Protection has fined the natural gas drilling company CNX for spilling natural gas production fluids at well sites in Greene County. The spills took place between 2019 and 2021, all in Richhill Township. The largest spill took place on September 18, 2019, in which approximately 40 barrels, or 1,680 gallons, of production fluid leaked out of a containment structure and spilled on the ground at CNX RHL 71 and RHL 87 well site. The DEP said the company tried to make repairs to the containment and remove fluids from the site. But CNX “postponed full remediation nearly 70 days due to its ongoing hydraulic fracturing activities,” according to a DEP press release. In total, the company had to remove nearly 1,400 tons of contaminated soil at the site. Another spill occurred at the site on January 23, 2021, in which 420 gallons of fluid discharged onto the ground due to an “equipment failure.” Another spill of 40 gallons occurred three months later. A smaller incident occurred in December 2019, in which 30 gallons of fluid leaked out of containment and into a sediment basin at the company’s RHL 4 well pad. According to the DEP, “CNX postponed removal of contaminated soil until hydraulic fracturing was completed, and the discharge continued for days.” The company ended up removing nearly 2,000 tons of contaminated soil from the site. “Delays like these are unacceptable. DEP expects, and the regulations require, prompt reporting and cleanup of spills and that operators will take measures to prevent future incidents,” said DEP southwest district oil and gas manager Dan Counahan, in a statement. Production fluids are a byproduct of the drilling and fracking process in oil and gas production. They can contain high levels of naturally-occurring metals, radioactive materials, and salts, but also can contain fracking chemicals. The fluid is too toxic for disposal in municipal wastewater facilities and is typically disposed of in deep injection wells. The company paid two fines, of $125,000 and $75,000, for the violations. The money will go toward the state’s fund to plug abandoned oil and gas wells. CNX didn’t immediately respond to requests for comment.
We can’t forget the health dangers of fracking - Although it’s taken far too long – and so much work lies ahead – confronting the climate crisis has become a defining policy goal of the U.S. government, and people are starting to notice. Whether that talk will lead to necessary action is still unclear, but people are recognizing the need to move away from fossil fuels, including fracked gas. Yet climate impacts are just one aspect of the threat posed by fossil fuels. A growing body of research is confirming a dangerous link between fracking and a wide range of health problems. It’s time Pennsylvania residents and regulators demand these health risks be addressed, including by establishing safer distances between fracking sites and people’s homes under state law. A recent Yale School of the Environment report details the established connection between fracking and health risks. Physicians for Social Responsibility and Concerned Health Professionals of New York report that 17.6 million people live within a mile of a fracked oil or gas well. That’s a public health crisis, according to the healthcare professionals and scientists in the group. Earlier this year, Yale researchers found that children living near Pennsylvania wells that use fracking to extract gas (aka methane) are two to three times more likely to contract a form of childhood leukemia than their peers who live farther away. Another study from Harvard found that elderly people living near or downwind from gas pads have a higher risk of premature death than seniors who don’t live in that proximity. Across thousands of peer-reviewed research papers, the health effects linked to exposure to fracking include respiratory conditions, heart disease, cancer, stress, and adverse effects on the developing fetus. For at-risk groups and all Pennsylvania residents, greater protections are needed. There are a few commonsense actions we can take now. The first is to require safer distances between these toxic fracking sites and the areas where people live and work. Known as setbacks or protective buffers, these limits on how close fracking infrastructure can be to buildings, schools, hospitals, and natural resources are established in Pennsylvania law. Currently, Pennsylvania only requires that well pads be 500 feet from residential buildings. Some well pads are 40 acres across – yet can be within 500 feet of a school or hospital. According to the Yale study and many others, a 500-foot barrier is woefully inadequate in protecting populations from the health hazards of fracking.Some states, such as New York, have banned fracking because of its negative impact on public health. Pennsylvania should do the same.
Fracking returns to burg with fiery taps - One of Pennsylvania's largest drillers will be allowed to extract natural gas from beneath a rural community where it has been banned for a dozen years per accusations the company polluted the village water supply, according to a settlement with state regulators. The state's Department of Environmental Protection lifted its long-term moratorium on gas production in Dimock, a small village in northeastern Pennsylvania that gained national notoriety when residents were filmed lighting their tap water on fire. The agency's agreement with Houston-based Coterra Energy Inc. is dated Nov. 29 -- the same day Coterra pleaded no contest in a high-profile criminal case accusing the company of allowing methane to leak uncontrolled into Dimock's aquifer. State officials denied that Coterra's plea to a misdemeanor charge was in exchange for being allowed to drill for potentially hundreds of millions of dollars worth of gas. Some of the residents, who have long accused the Department of Environmental Protection of negligence in its handling of the water pollution in Dimock, said they felt betrayed. "We got played," said Ray Kemble, the most outspoken of a small group of Dimock residents who have battled the drilling company and state regulators. Coterra will be permitted to drill horizontally beneath a 9-square-mile area of Dimock and frack the gas-bearing shale that lies thousands of feet down. That's been forbidden since 2010, when environmental regulators accused Coterra's corporate predecessor of failing to keep its promise to restore or replace Dimock's water. The Department of Environmental Protection said it began negotiations with Coterra in early 2022, shortly after the company formed from the merger of Cabot Oil & Gas Corp. -- the driller deemed responsible for fouling Dimock's water supply -- and Cimarex Energy Co. "When Coterra took over responsibility of the wells after the Cabot merger, they actively engaged with DEP to address the remaining issues in the area," said agency spokesperson Jamar Thrasher. "Coterra committed to strict controls, monitoring and evaluation, resulting in some of the most restricted conditions on any drilling in the commonwealth." Cabot, the predecessor company to Coterra, was charged in June 2020 with 15 criminal counts over allegations it drilled faulty gas wells that leaked flammable methane into residential water supplies in Dimock and surrounding communities. Coterra pleaded no contest to a misdemeanor violation of the state Clean Streams Law. The plea deal with the state attorney general's office requires Coterra to pay more than $16 million to fund construction of a new public water system for Dimock and to pay affected residents' water bills for 75 years. Attorney General Josh Shapiro, a Democrat who takes office as governor next month, held a celebratory news conference with Kemble and two other Dimock residents on the day Coterra entered its plea. At the news conference, Shapiro appeared to dodge a reporter's question on whether Coterra would be permitted to resume drilling in the moratorium area, pointing out the administration of Democratic Gov. Tom Wolf remained in charge. "That's obviously a question for the regulators, not for the attorney general's office," Shapiro said then. Shapiro's spokesperson said the plea deal was not contingent on the state department's lifting the moratorium. "Our office plays no role in DEP's regulatory decisions and we do not share confidential information about criminal investigations," Jacklin Rhoads said. In an interview Friday, Wolf said he was satisfied with his administration's decision to allow Coterra to go back into Dimock, "as long as they do what we need them to do with the new water supply and the pipes." He said the company had to abide by "some pretty stringent guidelines."
Pennsylvania Lets Polluter Resume Drilling in Protected Zone, Outraging Residents in Fracking’s ‘Ground Zero’ -- On the same day that the Pennsylvania Attorney General’s Office reached a plea agreement with an energy company on charges of environmental crimes dating back more than a decade in the town of Dimock, state regulators quietly signed a consent order allowing the company to drill beneath an area that had been subject to a 12-year moratorium on such activity. The decision has outraged residents who’ve lived with the pollution tied to Coterra Energy’s previous fracking activity and endured over a decade in which they’ve lacked access to clean water for their homes. “We’re just goddamn puppets,” said Ray Kemble, 30-year Dimock resident of the 9-square-mile moratorium zone and water pollution victim, who stood next to Attorney General and Gov.-elect Josh Shapiro the day he applauded his office for reaching a conclusion to the years-long battle for clean water in the area. On Nov. 29, Coterra Energy and the Pennsylvania Department of Environmental Protection (DEP) signed a consent order allowing the operator, one of the largest natural gas producers in the state, to drill laterally beneath an area that has been mostly fracking-free since 19 households found methane in their water in 2008 and 2009. On November 4, 2009, the DEP signed a consent order tying drilling by Coterra — then called Cabot Oil and Gas, prior to a merger with Cimarex Energy Co. in 2021 — to household water pollution, banning the company from drilling new natural gas wells in the area entirely. Following the new consent order, Coterra will now be allowed to drill horizontally underneath the 9-square-mile protected zone, as long as the top hole of a well is drilled outside of it. (Fracking involves drilling vertically for thousands of feet underground, then horizontally, carving an L-shaped path.) The consent order was not announced to residents nor mentioned during a Nov. 29 plea hearing at which many celebrated a long-sought victory: Coterra agreed to pay $16.29 million for clean water wells and a water line to provide clean water to residents who have been deprived of such for over a decade, as well as $58,000 to each affected household to cover its water bills for the next 75 years. The new order allowing lateral drilling represents the fulfillment of a request Coterra has made to regulators numerous times over the last 13 years. “Based upon the remedial work of Cabot … Coterra is requesting that the Department allow new drilling and hydraulic fracturing of wells with surface locations outside the Dimock/Carter Road Area and laterals that traverse under and produce the Dimock/Carter Road Area,” the consent order reads. “New drilling or hydraulic fracturing is currently restricted by the 2010 COSA.”
Residents Fear New Methane Contamination as Pennsylvania Lifts Its Gas-Drilling Ban in the Township of Dimock - Residents of a Pennsylvania town famous for its flammable tap water fear another round of methane contamination after state officials lifted a 12-year ban on drilling for natural gas beneath their feet. The state’s Department of Environmental Protection signed an agreement with Coterra Energy, allowing it to restart harvesting natural gas from a nine-square-mile “box” beneath Dimock in northeastern Pennsylvania, where the company’s predecessor, Cabot Oil and Gas, was ejected in 2010 after contaminating numerous private water wells with methane. Victoria Switzer, a long-time Dimock resident and an outspoken opponent of the gas industry, said she was “depressed and disappointed” by the new consent agreement because it will end the DEP’s testing of her water every three months, and replace that with testing by Coterra. She’s also worried that plugging more than a dozen old wells in the township will result in the renewed migration of methane into people’s water wells. She argued that DEP should not have allowed a resumption of drilling in a gas-rich area of Pennsylvania’s Marcellus Shale field until residents were connected to the promised public water system.“The opening of the box should not occur until water is flowing into the homes of the impacted residents and any other family that wants peace of mind when it comes to their life source: their water,” she said. The new DEP agreement with Coterra places many new restrictions on the company’s gas-harvesting plans, including monitoring new wells for any methane escape, evaluating drinking water wells near its operations and plugging old gas wells that were the source of water contamination. The company will not be allowed to drill vertical wells within the “box” as it did before, but can sink those wells outside the area, and then extend horizontal “laterals” beneath the town, according to the agreement. Coterra is also required within six months to install, as an interim solution, water-treatment systems to all affected residents who agree to the offer. If the new system is unable to be built for “any reason,” the company must apply to the DEP for permission to operate the interim systems for 30 years, the agreement says. The document, signed on Nov. 29, also requires the company to pay $16.29 million to install within five years a public water system that would remove the risk of future contamination from nearby gas drilling. That requirement was also part of a plea agreement with Coterra that was reached by Pennsylvania Attorney General Josh Shapiro on the same day, in which the company pleaded no-contest to criminal charges stemming from violation of the state’s Clean Streams Law, and agreed to pay the water bills of affected residents for 75 years.
Groups Blast Dimock Fracking Decision, Demand Action from Shapiro - Following reports that the Department of Environmental Protection (DEP) will allow fracking giant Coterra (formerly Cabot Oil and Gas) to resume drilling operations in Dimock, over 50 groups delivered a letter to Governor-elect Josh Shapiro today decrying the decision to once again put the people of Dimock in harm’s way. The letter – signed by Food & Water Watch, Earthworks, Better Path Coalition, Delaware Riverkeeper Network, Friends of the Earth and others – specifically calls for Governor-elect Shapiro to undo the decision when he takes office next month. “The people of Dimock have suffered long enough, and no one knows better than Governor-elect Shapiro that the Pennsylvania Department of Environmental Protection (DEP) cannot be trusted to make the practice safe. He has prosecuted several cases involving the DEP’s complete inability to regulate the fracking industry,” said Food & Water Watch organizer Ginny Marcille-Kerslake. “The simple truth is that no amount of regulation can make fracking safe, and subjecting the people of Dimock to the dangers of the oil and gas industry again is an outrageous betrayal. It’s up to Shapiro to set this right.” Pennsylvanians are up in arms about the decision to re-open Dimock to fracking, with close to 2,000 quickly signing on to a petition this week from the Better Path Coalition demanding that Shapiro reverse the decision.“Josh Shapiro promised to go after the polluters as Attorney General. His job is about to change; as Governor, his job is to prevent pollution, an outcome all but guaranteed if Coterra is allowed to drill anywhere near Dimock. Governor-Elect Shapiro must reinstate the ban on day one as governor,” said Karen Feridun, Co-founder of the Better Path Coalition.“Just as we saw with Mariner East, the situation in Dimock shows how our regulatory agencies have been captured by oil and gas interests. In addition to reinstating the fracking moratorium in Dimock on his first day as governor, Shapiro should prioritize putting in people who will actually take seriously the missions of the DEP and PUC, as well as enforcing the green amendment to Pennsylvania’s constitution, which guarantees us clean air and water,”
Mountain Valley Pipeline in West Virginia hits another roadblock — A controversial natural gas pipeline in West Virginia appears dead for now after it failed to make next year’s spending bill from Congress. There certainly could be renewed efforts with a new Congress coming next year, but the Mountain Valley Pipeline has hit a dead end for now. The Mountain Valley Pipeline was designed to take natural gas from northern West Virginia to all the way southeast of Roanoke, Virginia, and then eventually into North Carolina. Supporters say it would have given the United States a huge power source and energy independence, and other natural gas could be sold to our European allies. But the U.S. Senate has been unable to shorten the permitting process. “It’s a ten-year commitment to support fossil industry, cleaner in the United States. But a ten year path for fossil in the United States so that we would be energy independent and have the horsepower it takes to run our country,” said Manchin. Senator Manchin says 2,500 jobs will be lost, and that West Virginia will lose out on $40 million a year in severance tax revenue. He says landowners will lose out on $300 million in royalties from the sale of natural gas from their properties. Manchin also said the decision to strip out the permitting item from the budget bill was purely political, because Senate Minority Leader Mitch McConnell and many other Republicans did not want to give Democrat Manchin a big victory.
US oil, gas rig count falls by nine as gas-focused drilling slows The US oil and gas drilling rig count fell nine to 863 in the week ended Dec. 21, S&P Global Commodity Insights data showed Dec. 22. An eight-rig slide in the number of gas-focused drilling rigs to 184 comprised the bulk of the weekly decline, while the number of rigs chasing primarily oil dipped one to 679. Most of these idled gas rigs were found outside the major plays, however. Rig counts in the eastern Marcellus and Utica shale play declined by two and one, respectively, to 33 and 14, but the number of rigs active in the southern Haynesville basin was steady at 81. In contrast, Permian basin rig counts climbed to 354, testing the top of its recent range, and Bakken drillers added three rigs for a total of 44—a six-week high. Despite the increase in Bakken rigs, severe weather in the region has blunted output. Sub-zero temperatures and heavy snow in the past week have seen gas production in the Bakken fall to 1.46 Bcf/d Dec. 19, the lowest level recorded since late April of this year and the lowest mark recorded in December since 2017, according to S&P Global Commodity Insights data. Meanwhile, around 300,000-400,000 b/d of oil production was shut-in in North Dakota by the recent storm, with the bulk of that output not expected to be restored until 2023, according to North Dakota Department of Mineral Resources director Lynn Helms. In a move designed to support prices and provide forward certainty for producers, the US Department of Energy Dec. 16 announced plans for its first repurchase of oil to begin replenishing the Strategic Petroleum Reserve. The move comes after an unprecedented 180 million barrel release over several months to combat energy price hikes that Russia's invasion of Ukraine spurred. The DOE issued a solicitation for up to 3 million barrels of sour crude for delivery in February to the Big Hill SPR site in Texas. Analysts at ClearView Energy Partners said the relatively small volume of the buyback was likely a test of the DOE's new fixed-price contracting authorities. "Further buybacks could follow if the department judges the test to have been successful," they said in a Dec. 16 research note. "We think that could potentially happen as soon as [first or second quarter] 2023, even if delivery does not occur until FY 2024 or beyond. The timing could reflect several considerations, however."
With Warmer Air Coming, January Natural Gas Futures Flop - Natural gas futures flopped a second consecutive trading day as the weather outlook for later this month and early next pointed to milder conditions and easing demand. The January Nymex gas futures contract settled at $5.851/MMBtu on Monday, down 74.9 cents day/day. February fell 59.3 cents to $5.710. NGI’s Spot Gas National Avg., in contrast, pushed ahead 7.5 cents to $11.405 amid strong near-term consumption. Forecasts to start the trading week showed Arctic cold advancing from the northern reaches of the country further south later this week and into the weekend, driving robust demand and supporting cash prices. Sub-zero highs are expected in northern markets and freezing temperatures could invade areas as far south as Houston. However, data trended warmer for the Dec. 27-Jan. 1 period, according to NatGasWeather. The “frigid cold pool retreats into Canada” during this stretch, allowing warmer-than-normal conditions to spread over the Lower 48 to close out the year and to start 2023. “With highs of 60s and 70s over the southern U.S. Dec. 27-Jan. 1 and highs of 20s to 50s over the northern U.S., national demand will drop to light levels,” the firm said. “How long this warmer-than-normal pattern extends into January will be of great interest, since the longer it holds, the more likely it’s going to disappoint.” EBW Analytics Group said demand could “collapse” well into the first week of January. The outlook weighed on prices to start this week as forecasts did to finish the prior week – the prompt month shed 37.0 cents on Friday. Still, EBW analysts said, pressure on prices could ease this week amid intense cold that, in addition to bolstering heating demand, could cause wellhead freeze-offs and curb production from the Rockies across North Dakota to the Midcontinent and into the Northeast. Impacts from the cold could potentially reach Texas as well. “If producers are forced to divert capital expenditures and labor to manage existing production, it could further detract from the ability to bring new supply online in coming weeks,” said EBW’s Eli Rubin, senior analyst.
U.S. natgas drops 9% with less cold weather coming in January - (Reuters) - U.S. natural gas futures dropped about 9% to a seven-week low on Tuesday on forecasts for the weather to turn warmer than normal in late December and early January. That price drop came despite forecasts for colder weather and higher heating demand over the next week than previously expected. U.S. gas futures remained on track for their most volatile year ever. Both implied and historic volatility were expected to hit record highs in 2022 as soaring global gas prices this year feed demand for U.S. liquefied natural gas (LNG) exports due to supply disruptions and sanctions linked to Russia's war in Ukraine. Traders said the biggest uncertainty for the market remains when Freeport LNG will restart its LNG export plant in Texas. Gas started to flow to Freeport on Tuesday for the first time since August, according to data provider Refinitiv. Traders said Freeport is likely using the gas to fuel a power plant at the site, but it could also be a sign that the facility is getting closer to restarting. After several delays - from October to November to December - the company has said several times this month that the plant is on track to restart by the end of the year. Many analysts, however, do not expect Freeport to return until the first quarter of 2023 because the company still has a lot of work to do to satisfy federal regulators before the plant is ready to restart. Whenever Freeport returns, U.S. demand for gas will jump. The plant can turn about 2.1 billion cubic feet per day (bcfd) of gas into LNG for export, which is about 2% of U.S. daily production. Freeport shut on June 8 after a pipe failure caused an explosion due to inadequate operating and testing procedures, human error and fatigue, according to a report by consultants hired to review the incident and suggest action. A couple of vessels - Prism Diversity and Prism Courage - have been waiting in the Gulf of Mexico to pick up LNG from Freeport since at least early November. Several other ships were also sailing toward the plant, including Elisa Larus, which is expected to arrive in late December, Point Fortin and Prism Agility (early January), Kmarin Diamond (mid-January) and Wilforce (late-January). Even without Freeport, the amount of gas flowing to U.S. LNG export plants hit 13.0 bcfd last week, the most since May 29 - 10 days before Freeport shut. That is because the nation's six other big export plants were operating near full capacity. In what has already been an extremely volatile couple of weeks for the front-month, gas futures fell 52.5 cents, or 9.0%, to settle at $5.326 per million British thermal units (mmBtu), their lowest close since Oct. 27. Gas futures have climbed or dropped more than 5% every day since Dec. 12, rising as much as 8% on Dec. 15 and falling as much as 11% on Dec. 19.
Strength in Cash Prices Pushes Natural Gas Futures - Natural gas futures eked out a gain Wednesday amid worries that a fierce and widespread winter freeze could force production interruptions, ending a three-day run of steep losses. The January Nymex gas futures contract settled at $5.332/MMBtu, up six-tenths of a cent day/day. February rose 2.2 cents to $5.238. NGI’s Spot Gas National Avg. surged $6.960 to $16.065, as bitter cold enveloped the West and the nation’s midsection. Natural gas production on Wednesday held around 99 Bcf/d. But with subzero temperatures in the Midwest expected to also canvas the East Thursday and Friday, and with freezing temperatures projected for as far South as Texas late in the week, analysts said wellhead freeze-offs and production cuts were likely. The final days of this week will bring “one of the coldest outbreaks of the winter” to date, with a “dangerous Arctic blast” delivering frigid temperatures to the Rockies and Plains and down into Texas, according to NatGasWeather. “With a hard freeze over production areas, flows are expected to drop by several Bcf to near 95 Bcf/d, if not lower.” In addition to blizzard conditions in the Midwest and freezing rains in parts of the Northeast, “subfreezing air is also expected into the South and Southeast, as well as the potential for rare snowfall,” the firm added. Futures markets had faltered the three prior days on forecasts for mild weather near the end of December and to start 2023. But the intensity and breadth of this week’s winter weather tilted markets in bulls’ favor for at least one day. The “looming” demand collapse to start 2023 suggests another leg lower could occur after near-term cold fades and February becomes the front-month contract next week,” said EBW Analytics Group’s Eli Rubin, senior analyst. In the immediate term, however, “freeze-off risks over Christmas weekend – with January options expiration and final settlement early next week – could help reinforce support for Nymex gas prices.” Weather in Texas, in particular, could wreak havoc this week, though analysts said it is not likely to rival February 2021’s Winter Storm Uri.
U.S. natgas drops 6% to 2-month low on less cold, small storage draw (Reuters) - U.S. natural gas futures dropped about 6% to a two-month low on Thursday on forecasts for warmer weather in late December and early January than previously expected and a smaller-than-expected storage draw last week. Futures dropped despite forecasts for extreme cold over the next week that have boosted spot power and gas prices to their highest levels in years across parts of the country and put gas output on track to drop to a seven-month low due to freezing oil and gas wells in Texas, Oklahoma, North Dakota, Pennsylvania and elsewhere. Gas output was down about 4.7 billion cubic feet per day (bcfd) over the past three days to a preliminary seven-month low of 94.3 bcfd on Thursday. That would be the biggest drop in daily output since the February freeze of 2021 when a winter storm froze gas supplies in Texas and forced that state's electric grid operator to impose rolling power outages. The futures price decline also occurred after a federal report showed last week's storage withdrawal was smaller than expected because mild weather kept heating demand low and lots of wind power reduced the amount of gas generators needed to burn to produce electricity. The U.S. Energy Information Administration (EIA) said utilities pulled 87 billion cubic feet (bcf) of gas from storage during the week ended Dec. 16. That was less than the 93-bcf decline analysts forecast in a Reuters poll and compares with a decrease of 60 bcf in the same week last year and a five-year (2017-2021) average decline of 124 bcf. Last week's decrease cut stockpiles to 3.325 trillion cubic feet (tcf), or 0.7% over the five-year average of 3.303 tcf for this time of year. That is the first time the amount of gas in storage was higher than the five-year average since mid-January. After weeks of extreme volatility, front-month gas futures fell 33.3 cents, or 6.2%, to settle at $4.999 per million British thermal units (mmBtu). That was the contract's lowest close since it settled at a seven-month low of $4.959 on Oct. 21. Traders said the biggest uncertainty for the market remains when Freeport LNG will restart its LNG export plant in Texas. After several delays - from October to November to December - the company has said several times this month that the plant is on track to restart by the end of the year, pending regulatory approval. Whenever the plant returns, U.S. demand for gas will jump. It can turn about 2.1 bcfd of gas into LNG for export, which is about 2% of U.S. daily production.
U.S. natgas up 2% as extreme cold cuts output, demand set to break record (Reuters) - U.S. natural gas futures gained about 2% on Friday as extreme cold this week boosted spot power and gas prices to their highest in years across much of the country and cut gas output to a nine-month low by freezing oil and gas wells in Texas, Oklahoma, North Dakota, Pennsylvania and elsewhere. U.S. daily demand from the four biggest gas consuming sectors - residential, commercial, power and industrial - was on track to reach 147.3 billion cubic feet (bcf) on Friday, which would easily break the current record of 131.1 bcf set in January 2019, according to data from Refinitiv. The storms caused about 1.5 million homes and businesses to lose power on the U.S. East Coast, Midwest and Texas, shut several large refineries, and caused problems at the Cameron LNG export plant in Louisiana. The futures price increase came despite forecasts for less cold weather from late December-early January than previously expected, which should allow utilities to leave more gas in storage at the start of the new year. Gas stockpiles were about 1% above the five-year (2017-2021) average for this time of year. Gas output was down about 6.5 billion cubic feet per day (bcfd) over the past four days to a preliminary nine-month low of 92.4 bcfd on Friday. That would be the biggest drop in daily output since the February freeze of 2021 when a winter storm froze gas supplies in Texas and forced that state's electric grid operator to impose rolling power outages. After weeks of extreme volatility, front-month gas futures rose 8.0 cents, or 1.6%, to settle at $5.079 per million British thermal units (mmBtu). On Thursday, the contract closed at its lowest level since settling at a seven-month low of $4.959 on Oct. 21. For the week, gas futures were down about 23.0% after rising about 5.7% last week. That would be the contract's biggest weekly decline since it dropped 23.2% in late October. Refinitiv projected average U.S. gas demand, including exports, would jump from 139.9 bcfd this week to 148.8 bcfd next week with more cold weather coming before dropping to 116.2 bcfd in two weeks with the weather expected to turn mild in late December-early January.
Winter Storm Walloping USA Threatens to Disrupt LNG Exports- A winter storm battering huge swaths of the US threatens to temporarily disrupt exports of liquefied natural gas from the Gulf Coast, exacerbating the global fuel crunch. The arctic front, expected to continue for several days, is triggering warnings and advisories stretching from Maine to the Gulf of Mexico. The US is a major LNG exporter and a key supplier to Europe, which means port disruptions could have a global impact. Subfreezing temperatures and high winds through Dec. 26 may cause delays or suspension to pilot services for the Sabine-Neches Waterway in Texas, according to notices from Moran Shipping. The waterway services the Sabine Pass terminal, the largest US LNG export facility. Pilots for the port of Corpus Christi, who are responsible for docking vessels in the southern Texas region, have suspended boarding vessels due to the cold, according to Moran. That may affect ship traffic to the Corpus Christi LNG export facility. Cheniere Energy Inc., operator of the Sabine Pass and Corpus Christi terminals, said that it always prepares for and responds to extreme weather to safely manage operations. The company didn’t comment on the current operations of the facilities.
IEEFA: European LNG Boom Not All Good For US Exporters -- Data from the U.S. Department of Energy and S&P Global shows that by mid-August European LNG imports had already exceeded the White House target. Although full-year data isn’t available yet, by the end of 2022 total LNG export volumes from the U.S. to EU member states will likely surpass 55 bcm – which is more than two and a half times last year’s level and represents a 34-bcm year-over-year gain, more than double the White House’s target. Adding in the UK and Turkey, which aren’t part of the EU but have significant gas pipeline connections to the region, U.S. LNG shipments to greater European gas markets could reach 75 bcm by the end of the year, up by 44 bcm from 2021. What made all this even more remarkable was the loss of all output from the Freeport LNG terminal in early June, due to a massive explosion at the Texas plant. At the time, Freeport represented almost 20 percent of total U.S. liquefaction capacity, and it had sent more than three-fifths of its output to Europe in the first part of the year. If Freeport hadn’t blown up IEEFA believes that U.S. LNG exports to greater Europe could have topped 80 bcm in 2022. As dramatic as this shift has been, the U.S. might ship even more LNG to Europe next year than this year. One recently completed LNG project, the Calcasieu Pass LNG plant in Louisiana, was just ramping up output at the beginning of 2022. Now that the plant is operating at full capacity, its annual shipments to the EU rise by 4 to 5 bcm in 2023. To IEEFA, the Freeport LNG terminal remains a wildcard. It's taken far longer than expected to get the plant up and running again, and federal regulators recently asked the company to resolve a long list of issues before the plant can reenter service. But if the plant resumes operation in the second quarter of 2023, IEEFA claims that it could add an additional 1 to 2 bcm to the trans-Atlantic LNG trade over the coming year. Put simply, the U.S. has shipped more LNG to Europe than virtually anyone thought possible and could ship even more next year. Regarding this, IEEFA stated that the lessons here weren’t necessarily what one might think. First, political intervention played almost no role in any of the increase in U.S. LNG shipments to the EU. “The White House has been little more than a cheerleader, watching the game from the sidelines. The real action has been in prices: The key reason that the U.S. LNG industry shipped so much of its product to Europe is that European buyers paid them,” IEEFA said. European buyers were willing to pay a premium for any LNG cargo they could get. Since U.S. LNG contracts don’t limit where the fuel can be shipped, European buyers snapped up as much as they could. “In the process, U.S. LNG companies and traders made boatloads of money, both literally and metaphorically, shipping their wares to Europe,” the Institute added. Second, despite the massive increase in LNG imports, Europe is still short of gas. As U.S. liquefied LNG exports to Europe surged, Russia progressively slashed its pipeline gas exports. “It’s difficult to know whether the two are linked, yet it’s clear that Russia was using its dominance in the EU gas market to inflict both political and economic pain on its rivals. The result is that Europe is more gas-starved than ever, with total gas consumption falling more than 20 percent year-over-year in the latter portion of 2022. Energy-intensive industries have been particularly hard-hit by the shortfalls,” the Institute stated. Third, the dramatic increase in U.S. LNG shipments to Europe was accomplished without building any new gas infrastructure beyond what was already planned at the beginning of the year. Two new U.S. projects were approved in mid-2022, but they won’t be online for years. Germany rushed one new LNG receiving terminal into service in mid-December, but the first cargo isn’t expected until next year. European politicians are considering expansions of gas infrastructure, with plans that analysts are already calling massively oversized. But the major gains in LNG imports from the U.S. were accomplished without any new terminals. As it turned out, boosting LNG exports to Europe didn’t require new infrastructure. Using existing facilities more efficiently was enough. A fourth lesson is that the EU’s gain in LNG imports has mostly come at the expense of Asia—particularly developing nations with fragile economies. For example, global traders Eni and Gunvor defaulted on their contracts to deliver LNG to Pakistan at least 11 times since 2021, forcing gas rationing and emergency tenders for more supplies. “At this point, sky-high prices and supply glitches have saddled LNG with a reputation as an unreliable and volatile energy source, curbing LNG-to-power plans in Asia and forcing energy forecasters—including Bloomberg, ICIS, and IEA, among others—to slash their projections for Asian LNG demand growth,” IEEFA claimed. Lastly, the Institute believes that the EU’s appetite for U.S. LNG is far from guaranteed in the long run. Europe is certainly reeling from limited gas supplies in the short term. But the continent is responding mostly by cutting demand for gas, by using the fuel more efficiently while ramping up substitutes such as wind and solar. Those shifts are likely to last for the long haul and are being supercharged both by high prices and by the continent’s ambitious climate goals, which call for major cuts in gas consumption. The European economic think tank Bruegel projects that cuts in European gas demand by 2030 could be so steep that most of the continent’s LNG import infrastructure will be unneeded. In short, the boom in U.S. LNG exports to Europe could be fleeting. European demand for LNG can be expected to remain high for several years, as the continent adjusts to a new and more fractious relationship with Russia, its former top gas supplier.
Corrosion Left Keystone Pipeline ‘Less than Half the Thickness of a Dime,’ Says U.S. Government Accountability Office - - Total oil spills from the Keystone Pipeline have grown to 25,975 bbl since TC Energy Corp. opened the conduit in 2010 to transport Canadian crude south to the Midwest and Gulf of Mexico. The estimated 14,000 bbl leak began on Dec. 7 into a Kansas creek and farm, halting flows for a week and leaving TC unable to state the cause as of yet. The leak has more than doubled the 11,975 bbl spill count as of mid-2021 by the U.S. Government Accountability Office (GAO).The count, in a report titled Pipeline Safety: Information on Keystone Accidents and Department of Transportation Oversight, followed a 17-month performance audit. The GAO examined Keystone as the only U.S. oil line allowed to exceed standard industry operating pressure in its pipe.The cause of the Kansas spill remains under investigation. High pressure did not cause Keystone leaks documented until mid-2021, said the 38-page GAO report to the U.S. House of Representatives’ Energy and Commerce Committee and Transportation Committee.An inquiry for the Pipeline and Hazardous Materials Safety Administration (PHMSA) blamed the mishaps on construction issues such as pump station vibration, a failed weld, a dent inflicted by a work vehicle, and an “atypical” steel seam that weakened the pipe. Risks caused by corrosion are also severe. The GAO described an October 2012 spill disaster threat that TC and the PHMSA spotted and prevented on four pipe sections in sensitive, populated areas on a Keystone leg across Missouri and Illinois.“In all four locations, the amount of metal loss – that is, corrosion – was over 60% deep. In one location, 97% of the metal had corroded, leaving a remaining pipeline wall thickness of 0.0120 inch – less than half the thickness of a dime,” said the GAO.The PHMSA granted Keystone its lone standing as a high-pressure U.S. line during its design in 2007. The permit lets the conduit work at 80% of specified minimum yield strength (SMYS). The U.S. industry standard is 72%.Use of the high-pressure permit spread gradually after Keystone deliveries began in 2010 and the entire network qualified as of 2017. The line also had its previous biggest spills, in North Dakota and South Dakota, in 2017 and 2019.Canada adopted an 80% SMYS rule for high-strength oil pipe in 2004. In the U.S., TC accepted 51 conditions to secure the Keystone pressure permit. Others follow the lower SMYS standard as cheaper to obey than the Keystone conditions, reported the GAO. Safer pipelines for natural gas have obtained 94 high-pressure permits.By a standard that industry critics favor, Keystone spills stand out. The 25,975 bbl total would fill an entire long course or Olympic-sized swimming pool plus nearly two-thirds of a second one, each 50 meters long, 25 meters wide and two meters deep.But by industrial shipping standards, the spills are small. Total leaks to date work out to 4.3% of one day of traffic on the 2,6875-mile Keystone route for 600,000 b/d of Canadian exports to the U.S. Midwest and Texas coast of the Gulf of Mexico.
UPDATE: 6,900+ barrels of oil recovered from Keystone spill - More than 6,900 barrels of oil have now been recovered from the Keystone Pipeline oil spill in Kansas. As of 5 p.m. on Friday, Dec. 16, TC Energy - the company which operates the Keystone Pipeline - says crews have recovered a total of 6,973 barrels of oil - nearly half of the 14,000 released into Mill Creek in Washington Co. - following a rupture in the pipeline. It noted that the total includes 10,351 barrels of oil and water. The company also indicated that the response personnel now on the scene exceeds 400 members. It said it continues to respond to the incident alongside the U.S. Environmental Protection Agency and the Kansas Department of Health and Environment, as well as the U.S. Pipeline and Hazardous Materials Safety Administration. TC Energy noted that the affected segment of the Keystone Pipeline System remains safely isolated as investigation, recovery, repair and remediation continues. It will not be restarted until it is safe to do so and with regulatory approval from PHMSA.
More than half of oil spilled in Keystone Pipeline rupture recovered - - More than half of the oil spilled into Mill Creek in the Keystone Pipeline rupture has been recovered. TC Energy, the Canadian company which operates the Keystone Pipeline, says as of 5 p.m. on Sunday, Dec. 18, that it has recovered more than half the barrels of oil from Mill Creek that had spilled into it from the rupture in the pipeline. It said efforts continue to progress at the Washington Co. site. The oil spill was detected on Dec. 8. About 10 days later, 7,233 barrels of the 14,000 released into the creek had been recovered. As of Monday morning, about 600 personnel were on site. According to TC Energy, the forecasted cold weather has the potential to slow recovery efforts. The company also indicated that it has established a notification system for those who wish to sign up and receive the latest updates in its recovery efforts. TC Energy noted that it continues to work alongside the U.S. Environmental Protection Agency and the Kansas Department of Health and Environment. The EPA has also released an interactive tool to show updated data on response efforts which will be updated daily. TC Energy said the affected segment of the Pipeline remains isolated as investigation, recovery, repair and remediation continue to advance. It said the segment will not be restarted until it is safe to do so and when regulatory approval is provided.
TC Energy Recovers Around 14K Barrels from Incident Site - TC Energy has revealed that, as of December 18, an estimated 13,877 barrels of oil and water have been recovered as part of its response and oil recovery effort at its Keystone Pipeline System Milepost 14 Incident site in Washington County, Kansas. Although the company’s recovery rates have been building over the past few days, TC Energy warned these have the potential to slow by the upcoming cold weather in the area. As of December 16, the company had recovered 10,351 barrels of oil and water from the incident site, as of December 15, it had recovered 7,397 barrels of oil and water, as of December 14, it had recovered 5,567 barrels of oil and water, and, as of December 12, it had recovered 2,598 barrels of oil and water, TC Energy’s website shows. On December 7, TC Energy responded to a release of oil from its Keystone Pipeline System into a creek in Washington County, according to a statement posted on its website, which noted that the affected segment had been isolated. “We continue to gather information as part of the investigation,” TC Energy stated in a frequently asked questions segment on its site focusing on the incident’s cause. “What we know is that the line was operating at reduced pressure at the time of the incident. We have ruled out a third-party strike as the cause,” the company added. “With the area around the impacted segment of pipeline section now excavated, we will be able to learn more about the next steps for repair and investigation. Once we remove the pipe section, it will be transported to a metallurgical laboratory for testing by an independent third party. Ultimately, PHMSA will share the final analysis of the root cause or causes,” TC Energy continued. “We won’t have specifics about the cause of the incident until we complete the investigation, and the segment of the pipeline is thoroughly analyzed by the NTSB metallurgical lab. Any findings shared until then would be speculation,” TC Energy went on to state.
Keystone pipeline operator reports more than half of leaked oil has been recovered -— The Canadian company that operates the Keystone pipeline indicated Wednesday that more than half of the crude oil spilled from a rupture near a northeast Kansas creek has now been recovered.TC Energy, in an update posted Wednesday morning, said its crews had recovered an estimated 7,599 barrels of oil from Mill Creek, and a total of 15,488 barrels of oil and water.That would be more than half of the estimated 14,000 barrels of oil — about 588,000 gallons — that spilled into the creek east of Washington, Kansas, in a leak detected Dec. 7.It was the largest leak to date on the 12-year-old crude oil pipeline, and larger than five previous, reportable leaks combined, according to the Government Accountability Office.TC Energy, formerly TransCanada, said Wednesday that crews had removed the impacted pipeline segment and have sent it to an independent lab for metallurgical testing.The testing was ordered by the U.S. Pipeline and Hazardous Materials Safety Administration, which regulates pipelines. The leak site is just a few miles south of Steele City, Nebraska, where TC Energy has a pipeline terminal. The cause of the leak is still under investigation, but it occurred as the company was sending a diagnostic tool through the metal pipe in that area.A group that has opposed tar sands pipelines, the Bold Alliance, has called for the entire pipeline to be shut down so the integrity of the metal pipe can be assessed. Environmental groups have also expressed worry about the oil recovery because tar sands oil sinks in water, rather than floats like conventional oil.The Keystone pipeline — a forerunner of the more controversial and now abandoned Keystone XL pipeline — transports refined crude oil from Canada’s tar sands region to refineries on the Texas Gulf Coast and in southern Illinois.
Pipeline company says Kansas oil spill contained, but chemicals found downstream -- Chemicals from the Keystone pipeline spill in north-central Kansas have shown up farther downstream in Mill Creek than the oil company’s repeated statements suggest. TC Energy and regulatory agencies say the oil spill is limited to a containment area — the length of the stream that lies between where the company’s pipeline burst and where workers quickly built an earthen dam about four miles downstream. Yet state environment officials say benzene, toluene and other volatile organic compounds have been detected beyond the two emergency dams that were installed after the Keystone pipeline’s worst environmental accident to date. The contamination that migrated downstream of the four-mile, oil-soaked stretch of Mill Creek poses a threat to animals but not to human drinking water, the Kansas Department of Health and Environment said Wednesday. Two weeks after the Dec. 7 spill, contamination levels remain below a threshold for acute harm to aquatic life, a spokesperson confirmed by email, but they could hurt wildlife that ingests the chemicals through the food chain. Last Thursday, an official who directs state efforts at the pipeline spill told members of the Kansas Water Authority that public drinking supplies remain safe. “The downstream public water supply intakes are far enough downstream that — and I never want to say this — (the contamination) will experience a lot of dilution before it gets there,” Erich Glave said. “Dilution is not the solution, but (drinking water) is protected at this point.” Glave directs KDHE’s Bureau of Environmental Field Services. Mill Creek flows into the Little Blue River, about 10 miles from the Washington County spill site. The Little Blue flows into the Big Blue River, which feeds Tuttle Creek Reservoir near Manhattan. The state says the levels of benzene and other chemicals “remain below our standards in the Little Blue River and downstream in Tuttle Creek Reservoir.” Glave said people with private wells could reach out with concerns. “If a private well owner thinks that they’ve been impacted,” he said, “they should contact us and then we can work with them to make sure that TC tests their well, and gets it right.” TC Energy and the crews it hired are carrying out the cleanup, with oversight, guidance and orders from the EPA and KDHE. More than 600 workers are at the site, including those crews and people from various state and federal agencies. TC Energy and the U.S. Environmental Protection Agency have kept a tight lid on details at the scene — where the company says about half of the nearly 600,000 gallons of spilled diluted bitumen crude oil have been recovered — so Glave’s public update to the Kansas Water Authority at a meeting in Colby opened a small window into how things are progressing. Here are details divulged in his update and in emails from a KDHE spokesman since then:
Despite giant oil spill, push continues for more pipelines -TC Energy provides nearly daily updates on its efforts to clean up its recent oil spill in Kansas, but the incident continues to pour fuel on the political debate surrounding the company’s Keystone pipeline system. The company’s record regarding pipeline leaks provides ready talking points for environmentalists who opposed TC’s plans for its Keystone XL pipeline expansion project. Still, Oklahoma’s congressional delegation, state leaders and industry heads continue to push for approval of the company’s pipeline permits. “As of Dec. 18, 5 p.m. CT, we have recovered an estimated 7,233 barrels of oil from the creek (13,877 barrels of oil and water),” reads the update TC Energy posted Monday morning. “Our recovery rates have the potential to slow by the upcoming cold weather in the area.” The Keystone pipeline released an estimated 14,000 barrels of oil – roughly 588,000 gallons – into a creek and pastureland in Washington County, Kansas, on Dec. 7. The spill will be particularly difficult to clean up due to the type of oil that was being transported through the pipeline: tar sands oil, also known as diluted bitumen. Previous spills of bitumen took years and required removal of environmental elements that came into contact with the substance. The spill is the worst in the system’s history and follows major spills in 2017, when more than 6,500 barrels spilled near Amherst, South Dakota, and in 2019, when 4,515 barrels spilled near Edinburg, North Dakota. The Keystone pipeline, which currently transports oil and natural gas from Canada down through Cushing, Oklahoma, on its way to Gulf Coast refineries, has experienced 22 leaks since 2010, though most incidents were small. Since 2010, more than 3.6 billion barrels of crude oil has passed through the Keystone pipeline, which has the capacity to deliver up to 590,000 barrels a day, according to TC Energy. Nearly 30,000 barrels have been spilled – a fraction of the pipeline’s capacity but a greater percentage than industry norms. In 2021, a U.S. Government Accountability Office issued a report on the Keystone pipeline, examining the system as the only one in the United States to have been granted a permit to exceed standard industry operating pressure. The cause for the Dec. 7 is yet to be determined. The GAO report did find extensive corrosion in the pipeline. In one portion of the pipeline, 97% of the metal had corroded, leaving the wall less than half the thickness of a dime; in other portions the corrosion reached 60%. Yet, pipelines are crucial to the nation’s oil and gas industry, said Cody Bannister, spokesperson for the Oklahoma Petroleum Alliance. “Pipelines play an important role and being able to move crude oil and natural gas across the United States benefits us all,” Bannister said. The pipelines that move oil through Oklahoma to the Gulf are the reason gas prices are typically lower for Oklahoma than much of the nation. Oklahoma’s congressional delegation continually has pressed the Biden administration for revoking the permit for the Keystone XL, which would have allowed the company to transport even more oil across the Canadian border into the U.S.
TC Energy Expects Significant Winter Weather Impacts - In its latest Keystone Pipeline System incident update, TC Energy has warned that it is expecting “significant” winter weather impacts over the upcoming days. “We continue to prioritize the safety of people and the environment and will be working safely according to weather conditions,” TC Energy said in its latest update. “Recovery rates have the potential to slow due to the upcoming weather,” the company added. In the update, TC Energy revealed that, as of December 20, 5pm CT, it had recovered an estimated 15,488 barrels of oil and water from the incident site in Washington County, Kansas. The company also stated that it had removed the impacted pipeline segment and sent it to an independent lab for metallurgical testing, as directed by the U.S. Pipeline and Hazardous Materials Safety Administration (PHMSA). “The affected segment of the Keystone Pipeline System remains safely isolated as investigation, recovery, repair and remediation continue to advance,” TC Energy said in the update. “This segment will not be restarted until it is safe to do so and when we have regulatory approval from PHMSA. We will continue to provide updates as information becomes available,” the company added. Extremely cold arctic air is expected to plunge southward and impact much of the U.S. through Hanukkah and into the week of Christmas, according to NOAA forecasters. “Temperatures 40 degrees below average and dangerous life-threatening wind chills as low as 50 degrees below zero are possible in the northern Rockies and northern Plains,” NOAA said in a statement posted on its website on Wednesday. “Sub-zero to single-digit temperatures are likely across the central Plains, Midwest, Great Lakes, Ohio Valley and Midsouth … Well below freezing temperatures will extend into the Mid-Atlantic, Northeast and as far south as the Gulf Coast through the holiday weekend,” NOAA added. In a market note sent to Rigzone on Wednesday, Rystad Energy Analyst Nikoline Bromander warned that the central U.S. region could experience a Polar vortex this week, which Bromander said “could break regional temperature records”.
Storm cuts U.S. oil, gas, power output, sending prices higher (Reuters) - Frigid cold and blowing winds on Friday knocked out power and cut energy production across the United States, driving up heating and electricity prices as people prepared for holiday celebrations.Winter Storm Elliott brought sub-freezing temperatures and extreme weather alerts to about two-thirds of the United States, with cold and snow in some areas to linger through the Christmas holiday.More than 1.5 million homes and businesses lost power, oil refineries in Texas cut gasoline and diesel production on equipment failures, and heating and power prices surged on the losses. Oil and gas output from North Dakota to Texas suffered freeze-ins, cutting supplies.Some 1.5 million barrels of daily refining capacity along the U.S. Gulf Coast was shut due to the bitterly cold temperatures. The production losses are not expected to last, but they have lifted fuel prices.Knocked out were TotalEnergies, Motiva Enterprises. and Marathon Petroleum facilities outside Houston. Cold weather also disrupted Exxon Mobil, LyondellBasell, and Valero Energy plants in Texas that produce gasoline, diesel and jet fuel. Sempra Infrastructure's Cameron LNG plant in Louisiana said weather disrupted its production of liquefied natural gas without providing details. Crews at the 12 million tonne-per-year facility were trying to restore output, it said. Freeze-ins - in which ice crystals halt oil and gas production - this week trimmed production in North Dakota's oilfields by 300,000 to 350,000 barrels per day, or a third of normal. In Texas's Permian oilfield, the freeze led to more gas being withdrawn than was injected, said El Paso Natural Gas operator Kinder Morgan Inc. U.S. benchmark oil prices on Friday jumped 2.4% to $79.56, and next-day gas in west Texas jumped 22% to around $9 per million British thermal units , the highest since the state's 2021 deep freeze. Power prices on Texas's grid also spiked to $3,700 per megawatt hour, prompting generators to add more power to the grid before prices fell back as thermal and solar supplies came online. New England's bulk power supplier said it expected to have enough to supply demand, but elsewhere strong winds led to outages largely in the Southeast and Midwest; North Carolina counted more than 187,000 without power. Gas output dropped about 6.5 billion cubic feet per day (bcfd) over the past four days to a preliminary nine-month low of 92.4 bcfd on Friday as wells froze in Texas, Oklahoma, North Dakota, Pennsylvania and elsewhere. That is the biggest drop in output since the February 2021 freeze knocked out power for millions in Texas. One billion cubic feet is enough gas to supply about 5 million U.S. homes for a day.
U.S. poised to become net exporter of crude oil in 2023 (Reuters) - The United States has become a global crude oil exporting power over the last few years, but exports have not exceeded its imports since World War II. That could change next year. Sales of U.S. crude to other nations are now a record 3.4 million barrels per day (bpd), with exports of about 3 million bpd of refined products like gasoline and diesel fuel. The United States is also the leading liquefied natural gas (LNG) exporter, where growth is expected to soar in coming years. But the United States consumes 20 million barrels of crude a day, the most in the world, and its output has never exceeded 13 million bpd. Until recently, the idea that it would be anything but a big crude importer was folly. Last month, U.S. government data showed net U.S. crude oil imports fell to 1.1 million barrels per day (bpd), the lowest since record keeping began in 2001. That is down sharply from five years ago, when the United States imported more than 7 million barrels per day. Factors changing that equation this year include sanctions hurting Russia's exports of oil and natural gas following its invasion of Ukraine, and Washington's massive release of oil from emergency reserves to combat spiking gasoline prices. "Russia's invasion of Ukraine has spurred new demand for U.S. energy and should push oil exports above imports late next year assuming shale output accelerates," said Rohit Rathod, market analyst at energy researcher Vortexa. To become a net exporter of crude, the United States needs either to boost production or curtail consumption. U.S. petroleum demand is expected to rise 0.7% to 20.51 million bpd next year, so that means production would have to rise.The United States already produces more oil than any other country in the world including Saudi Arabia and Russia. U.S. shale fields are aging and production growth this year has been sluggish. Overall output should reach a record 12.34 million bpd next year - but only if prices are lucrative enough to encourage oil drillers to pump more. European refiners have snapped up U.S. grades to offset the loss of Russian oil, and with U.S. crude's deeper discounts to global benchmarks, Asian refiners have stepped up purchases to 1.75 million barrels per day, data analytics firm Kpler said.
US Buying Oil For Strategic Petroleum Reserve | Rigzone - The U.S. Department of Energy’s Office of Petroleum Reserves has announced that it will start repurchasing crude oil for the Strategic Petroleum Reserve (SPR). This repurchase is an opportunity to secure a good deal for American taxpayers by repurchasing oil at a lower price than the $96 per barrel average price it was sold for, as well as to strengthen energy security. In October, President Biden announced a plan to replenish the SPR using updated authorities that allow for fixed-price purchases of crude oil. Relative to conventional purchase contracts that expose producers to volatile crude prices, this new approach, when used at scale, can give producers the assurance to make investments today, knowing that the price they receive when they sell to the SPR will be locked in place. Today’s notice will pilot this new approach by starting with a purchase of up to 3 million barrels of crude oil. “This initial step to fulfilling the President’s replenishment strategy follows his historic release from the SPR to address the significant global supply disruption caused by Putin’s war on Ukraine and provide a wartime bridge for domestic production to increase.” “The releases have helped lower gas prices for American families. National retail gas prices are now the cheapest since September 2021 and are down by over $1.80 per gallon since their peak in June 2022,” the DOE stated. DOE must receive bids for this notice no later than 10:00 a.m. Central Time on Wednesday, December 28, 2022. Contracts will be awarded to successful offerors no later than Friday, January 13, 2023, with deliveries to the Big Hill SPR site in Beaumont, Texas to occur in February 2023. The SPR is the world's largest supply of emergency crude oil, and the federally-owned oil stocks are stored in underground salt caverns at four storage sites in Texas and Louisiana. The SPR has a long history of protecting the economy and American livelihoods in times of emergency oil shortages.
New US Bill Could Halt Sale Of 140Mn Barrels Of SPR Crude - A new bipartisan spending bill could cancel the congressional mandates to sell 140 million barrels of crude from the US Strategic Petroleum Reserve over the next five years. The $1.7 trillion bill would cancel most congressionally mandated crude sales through fiscal year 2027. The change would align with the Presidents’ plan to begin refilling the SPR next year, replacing some of the 180 million barrels of crude Biden sold this year through emergency sales in response to Russia's war in Ukraine. The bill will redirect around $10.4 billion generated from the emergency sales to offset the estimated future revenue from the crude sales that would be canceled. It would also avoid refilling the SPR and selling it at the same time just because of congressional mandates. The US Congress in prior years ordered the sale of 147 million barrels of crude from the SPR in fiscal years 2024-27 to raise revenue for debt reduction, infrastructure, and other priorities. The new bill would cancel all those sales, except for 7 million barrels that the US would sell in fiscal years 2026-27. The emergency drawdown of 180 million barrels of crude from the SPR was as a good deal for taxpayers as it brought down fuel prices this year. The SPR crude barrel was sold at an average price of $96 per barrel. The new spending bill shows the crude sales being canceled only if needed to raise $74.25 per barrel to comply with budgetary rules, indicating a paper profit of $22 per barrel from the emergency sales. It is worth noting that the bill would not cancel a congressionally mandated sale of 26 million barrel of SPR crude that is required to occur by the end of this fiscal year on September 30. The measure would also keep intact previously enacted sales of 92.6 million barrels of SPR crude scheduled for fiscal years 2028-31. The partial refilling of the SPR was started last week by soliciting bids for the fixed-price purchase of 3 million barrels of sour crude, for delivery in February. The administration said it may buy up to 60 million barrels of crude with fixed price contracts at a targeted price of $67-72 per barrel, which it says will give the US producers more certainty now to invest in domestic production. Congress needs to pass the omnibus spending bill by today (Friday) to prevent a partial US government shutdown.
Joe Biden, Oil Trader of the Year 2022? - Of all people, Joe's got the magic touch with petroleum? The endless number of foiled speculators attests to the difficulty of realizing the old adage about how to make money--buy low, sell high. Let's face it: ever-changing markets often result in us doing quite the opposite, and not making money in the process. Now, whenever we are asked to think about who are the least savvy market participants, we often identify governments--or more specifically, government officials. Not being keen market watchers with limited skin in the game--it's taxpayer money they are officially dealing with, not theirs--this sentiment is understandable. Well lo and behold: Quartz is now touting President Joe Biden's timely release from the US Strategic Petroleum Reserve (SPR) as the "oil trade of the year." In retrospect, his release at the near-top of the oil market a few months ago helped ease oil prices. Now that oil prices have come down quite a bit, the SPR is now being refilled. Yes, Biden is buying low after selling high: Instead, it appears the US government made the oil trade of the year: Releasing 180 million barrels of crude from the Strategic Petroleum Reserve between March and the end of this year in an effort to blunt the effect of rising prices, the US government appears to have made about $4 billion, as prices have fallen dramatically over the course of the year.Selling when crude oil prices were high, the US captured billions in value. By one widely-used measure, the price of crude oil in Texas peaked at about $124 a barrel in March, and the average price during the SPR sales period was about $96; today that oil costs just $73 per barrel. These are paper profits, to be sure: The US is still aiming to refill the reserve, and prices may rise as it does so. On Dec. 16, the Department of Energy put out a request to purchase 3 million new barrels of crude, after releasing about 200 million barrels in 2022. There are currently about 382 million barrels still in reserve. His genial manner has caused Joe Biden to be underestimated throughout his life. Can he now be called a market player as well in his eighth decade? T. Boone Pickens, eat your heart out.
Natural Gas Users Brace for Complications as Cold Hits Texas -- Memories of Winter Storm Uri were fresh on the minds of natural gas buyers in Mexico as a cold front raced south through the United States and down into Texas. Mexico’s power grid operator Cenace warned that up to 9,000 MW of natural gas-fired power could be under stress due to limited natural gas supply. The cold was also expected to hit the northern Mexico states of Coahuila, Nuevo Leon and Tamaulipas by as early as Thursday night. “We’re worried, but we can’t do much since we don’t have any gas storage,” a natural gas buyer in Mexico City said. The source added that the welcome news was that the upcoming Christmas holidays were a time of lower industrial and residential demand. Also welcome is the prediction from analysts that the storm won’t be as bad as Uri, which sent natural gas prices skyrocketing and led to severe limitations in natural gas supply to Mexico. At one stage during that February 2021 storm, Texas Gov. Greg Abbott ordered that Texas stop supplying gas outside of state lines. Mexico sources the vast majority of its natural gas needs from Texas. On Thursday, Mexico imported a lower than usual figure of 4.452 Bcf of natural gas via pipeline from the United States, according to NGI calculations. This figure does not include non-public Texas intrastate trades. Of the total gas flows into Mexico, 3.878 Bcf came from South Texas. “We do not expect a repeat of Uri’s production impacts and associated outages of gas-fired power plants,” Wood Mackenzie analysts Colette Breshears and Eric Fell said Wednesday. “This is partially due to weatherization effects” and “partially from the nature of the storm (this year promises to be extremely cold, yet dry and fast to pass through).” On Thursday afternoon, NatGasWeather said, “There’s potential for minor impacts to the electricity grid” but “the duration will be much shorter than what occurred in Feb. 2021, so we do not expect a repeat of the massive grid failure seen back then.” Still, Cenace put into place an operational emergency alert and asked system participants to put into place contingency plans. U.S. production was already being impacted. After starting the week at around 99 Bcf/d, it dropped to around 96 Bcf/d by Thursday with further declines possible, according to Wood Mackenzie.
Big Oil Pours Billions In The Permian Basin - A couple of months ago, U.S. President Joe Biden urged energy companies to stop ‘war profiteering’ and even threatened to slap them with windfall tax if they failed to invest their profits in lowering costs for Americans and increasing production. The calls came at a time when Big Oil has been posting record profits amid high commodity and energy prices. The majority of energy companies have avoided spending big to expand production in the aftermath of the 2020 oil crisis, prioritizing returning more cash to shareholders in the form of dividends and share buybacks. Well, Biden might not fully get his wish but there are signs that companies are willing to spend more in the coming year(s) even as a raft of energy companies have announced major spending and capex hikes.And few places have captured the attention of Big Oil more than the Permian Basin. Some of the basin’s largest oil and gas producers have unveiled plans to ramp up extraction operations and investments in the region next year as production was forecast to increase despite oil prices projected to dip due to an impending global recession. ExxonMobil Corp.has not announced a drastic increase in spending, but has said that its capital spending for 2023 will be closer to the top end of its annual target of $20B-$25B, a level it expects to maintain through 2027. The company said more than 70% of its capital investments will be deployed in the U.S. Permian Basin, Guyana, Brazil and LNG projects across the globe. These investments will help increase the company's upstream production by 500K boe/day to 4.2M boe/day by 2027 with half of that expected to come from the high return regions in the Permian Basin and other high-return regions. Exxon also unveiled plans to boost spending on lower emission projects by 15% through 2027 to ~$17B through 2027. Exxon’s peer Chevron Corp. announced on Wednesday that FY 2023 capital spending budget will clock in at $17B, at the top end of its $15B-$17B medium-term range and up more than 25% from expected spending in 2022. The company said that upstream capex includes more than $4B for Permian Basin development; ~$2B for other shale and tight assets and ~$2B to go into projects that lower carbon emissions or increase renewable fuels production capacity, more than double the 2022 budget. Although Chevron’s spending for 2023 will be considerably higher than capital spending in the 2020-21 pandemic years, it’s still much lower than the $30B annual average of the 2012-19 period. Overall, more and more energy companies are opening up to the idea of increasing spending and production..
5.4 quake jolts West Texas, one of state's strongest ever (AP) — One of the strongest earthquakes in Texas history struck Friday evening in a western region of the state that's home to oil and fracking activity. There were no immediate reports of damage or injuries. The U.S. Geological Survey said the temblor had a magnitude of 5.4 and struck at 5:35 p.m., local time. It was centered about 14 miles (22 kilometers) north-northwest of Midland, with a depth of about 5.6 miles (9 kilometers). The agency had previously issued a preliminary magnitude of 5.3 before updating it. In the interim, the National Weather Service's office in Midland tweeted that it “would be the 4th strongest earthquake in Texas state history!” Geophysicist Jana Pursley at the USGS's National Earthquake Information Center in Colorado said that according to early reports received by the agency, the quake was felt by more than 1,500 people over a large distance from Amarillo and Abilene in Texas to as far west as Carlsbad, New Mexico. “It’s a sizable earthquake for that region," Pursley said, adding, “In that region such an event will be felt for a couple of hundred miles.” "I haven’t received any information about damages but it can crack stucco or driveways close to epicenter,” she added. A quake of similar magnitude struck West Texas a month ago. That Nov. 16 temblor was measured at 5.3 and had an epicenter about 95 miles (153 kilometers) west of Midland. The quake was followed shortly after by a less-intense aftershock, and Pursley said there could be more going forward with declining magnitude.
Magnitude 5.4 Quake Hits Texas A magnitude 5.4 earthquake occurred around 14 miles north-northwest of Midland, Texas, on December 16, the USGS Earthquake Hazards Program has revealed. The quake occurred as the result of shallow normal faulting, according to the USGS, which noted that the region surrounding the earthquake is seismically active. “Since 2018 about 120 earthquakes of magnitude 2.5 and larger have struck within 50km of the recent quake,” the USGS said in an organization statement. “Larger earthquakes have struck in the broader area. A M5.4 earthquake struck on November 16, 2022, about 200km to the west and a M5.0 occurred on March 26, 2020, also about 200km to the west of the December 16, 2022, earthquake,” the USGS added. “On Aug 1, 1975, a magnitude 4.8 earthquake occurred approximately 200km to the west-southwest of this recent earthquake; however, a detailed history of small (less than magnitude 3) earthquakes in this region is not well know because the region was not well covered by seismometers until recent years,” the USGS continued. Over the past two decades the central and eastern United States has experienced an increase in the occurrence of earthquakes, according to the USGS, which noted that scientific studies have linked much of this increase to human activity, “predominantly wastewater injection into deep disposal wells”. The Texas Railroad Commission (RRC) announced that it had activated personnel Friday evening in response to the quake and said it will take any necessary actions to protect public safety and the environment. Agency personnel are continuing to closely monitor seismic data from the United States Geological Survey, the TexNET Seismic Monitoring Program and private operator monitoring stations. RRC staff will continue its work to keep residents and the environment safe,” the RRC continued. Commenting on the incident, Todd Staples, the president of the Texas Oil & Gas Association (TXOGA), said, “industry operators continue to cooperate with the RRC in response to the recent activity in the Gardendale Seismic Response Area (SRA)”. “The RRC inspection of injection well sites in the area is appropriate and should inform, along with industry data, the best next steps forward and direct actions beyond currently adopted protocols. Reducing injection volumes, targeted shut-in of injection wells, expanding the size of the SRA, and comprehensive data collection and analysis are all available tools. Scientific data confirms that some continued seismicity activity often occurs after an event like the one that occurred Friday evening,” Staples added. “In addition, the industry and academia continue to explore alternatives to wastewater injection through market based water reuse and recycling as well as innovative pilot programs and collaboration with the Produced Water Consortium led by Texas Tech University, which was established by the 87th Texas Legislature,” Staples continued.
5.4 quake jolts oil-producing West Texas as locals blame 'fracking' for 4th strongest tremor in state A moderate earthquake occurred in Western Texas on Friday, December 16. The United States Geological Survey explained that the magnitude 5.4 quake occurred around 5.30 pm, was located 12.5 miles north-northwest of Midland and Odessa, and had a depth of 5.09 miles. It has already been called the fourth strongest earthquake in the state’s history by local meteorologists. The tremors were felt by residents in Roswell as well. This is the second time in two months that the state has been hit by a significant quake and people are blaming it on the ongoing Texas fracking..A reporter in Odessa for CBS 7, Joshua Skinner, reported, "Big earthquake in Odessa, TX. Happened around 5:36 p.m. The whole news studio shook for a solid 10 seconds." As reported by USGS, "The earthquake occurred within the interior of the North America plate, far from any tectonic plate boundaries, and is therefore considered an intraplate earthquake." The statement further reads, "Since 2018 about 120 earthquakes of magnitude 2.5 and larger have struck within 50 km of the recent quake. Larger earthquakes have struck in the broader area." No injuries were reported so far. The state was struck by a massive 5.4-magnitude quake only last month.One startled resident reacted to the quake and wrote, "We have felt a few of the smaller ones but this one really shook the house. Power went out for a few minutes only." Another person who connected the quake to the ongoing fracking in the state wrote, "Could this be due to fracking in the state? I hope there aren't any injuries or fatalities due to this earthquake." One more person said, One person who really felt the quake wrote, "Wow that earthquake! We could hear it coming, like some train from hell before it hit the house. It was the most violent and prolonged shaking that I've experienced here in West Texas. 5.3, at 2km depth. Fracking has a cost. All that crap goes somewhere & effs up the water table." Another person wrote, "Oh hell no!! We just had another major earthquake in the Odessa / West Texas area. I hate this!!! Screw you fracking oil companies!!! This never happened before until you b*****ds started doing this!!!" One person claimed that the quake "sounded like rumbling" and said, "Felt here in North East Texas, sounded like rumbling and a little shaking on my 2nd story Apt building." Another person blamed the constant fracking and quipped, "There was an earthquake in my part of Texas, where (surprise!) a ton of fracking occurs. Our state continues to delve into Mad Max shit"
Permian quake spurs industry review of fracking waste disposal - -- The shale industry is open to reducing underground storage of drilling waste and other measures to reduce earthquake risks after a 5.4-magnitude temblor rattled the Permian Basin.The Texas Railroad Commission, which regulates the state’s massive oil and natural gas industry, is probing disposal of saltwater left over from fracking, which occurs in the Permian region of West Texas and New Mexico more than anywhere in the world. Quakes have been reported across Texas and Oklahoma for years in relation to the disposal of drilling wastewater in rocks close to fault lines. In response to Friday evening’s quake, the Texas Oil and Gas Association said that “reducing injection volumes” and “targeted shut-in of injection wells” are among “available tools” to reduce risks.
Fracking Waste Gets a Second Look to Ease Looming West Texas Water Shortage - Fracked wells in West Texas don’t just produce petroleum. Much more than anything else, they spit up salty, mucky water. Typically, companies have discarded that fluid, hundreds of millions of gallons per day, by injecting it back underground, occasionally causing small earthquakes. But as water becomes more scarce, they’re beginning to reconsider. For now, hydraulic fracturing in arid West Texas uses large amounts of fresh aquifer water to crack open subterranean shales, unleashing a mixture of oil, gas and fossil brine 10 times as salty as the sea. Increasingly, frackers are starting to reuse that brine, easing their burden on aquifers. “We’ve just month by month seen extraordinary growth in the volumes we are managing,” said Matthew Gabriel, CEO of XRI Holdings, which recycles oilfield wastewater in the Permian Basin, the nation’s top oil-producing region. This month, XRI announced a 230-mile expansion to its existing 450-mile Permian pipeline network. Unlike other Permian pipelines, these carry water from oilfields to treatment plants and back, linking the major oil producers’ batteries of tanks. XRI, based in Houston, is also adding three more treatment plants to its existing 30. Fracking doesn’t require particularly clean water and the treatment to prepare it is pretty simple, Gabriel said. It’s the pipeline network that makes it economical, providing the equivalent of oilfield plumbing to replace the laborious process of trucking in water and trucking out waste. “You open a valve and you can have all the water you need,” Gabriel said. “I think we’re going to see enormous advances around this concept in the coming years.” XRI currently manages 1 million barrels of wastewater per day and recycles 800,000 — a small portion of the total volume produced by Permian Basin oil fields. Recently, Texas convened water experts for a state-funded study of recycling that so-called “produced water,” the term for wastewater from oil wells. Released this year, the Texas Produced Water Consortium report estimated Permian Basin wastewater production at approximately 11 million barrels, or 462 million gallons, per day in 2019, the last year of available data. Since then the figure has likely increased in step with soaring Permian oil and gas output. In response to a survey by the Texas consortium, fracking companies on average said they were already reusing about 30% of their wastewater. Even if they satisfied 100% of their need with recycled water, they would still have millions of barrels of produced water left over every day. Underground disposal remained a much cheaper option than reuse, it said, but might not be so for long. “Scarcity conditions,” the 130-page report said, “will eventually make this an economically viable option.”
Companies Flag Labor Issues in Oil and Gas - Finding and keeping qualified workers was the greatest challenge for companies in 2022, according to an American Petroleum Institute (API) reader poll highlighted in a newsletter published recently by the organization. The response received 52.95 percent of the votes in the poll, with ‘regulations and government policies’ receiving 23.52 percent, ‘fluctuations in price, supply and demand’ receiving 17.65 percent and ‘storage or shipment of oil and natural gas’ receiving 5.88 percent. The latest Dallas Fed Energy Survey, which was released at the end of September, also highlighted labor issues. In a section showcasing comments from respondents’ completed surveys, which were edited for publication, one exploration and production company noted that “the labor issue will provide a restraint on any major increase in oil and gas production for the domestic market”. “The biggest challenge for us is adding employees,” another E&P company outlined, according to the Energy Survey. “We are trying to add qualified staff, with little success, and that will negatively impact growth,” the company added. One company in the oil and gas support services sector noted that “meeting demand has been hampered by the availability of qualified people to work and, more importantly, whether they stay working in the oilfield,” the Survey highlighted. “We are seeing a greater percentage of hires, who are new to the industry as of last quarter, with many wanting regular hours and a work/life balance not typical of hourly employees in oilfield services,” the company added. Another company in the oil and gas support services sector said, “we continue to struggle to hire drivers with a commercial driver’s license that have oilfield experience, as well as skilled crew labor for construction and maintenance”, the Survey showed. Earlier this year, Hunter Kornfeind, the leader of Rapidan Energy Group’s U.S. crude production forecasting and analysis, told Rigzone that labor availability was tight and in short supply following the downturn due to Covid and said the U.S. oil and gas industry was not immune from those macro challenges.
Colorado to form ozone-reduction group that will consider new rules on fracking - Denver Business Journal - A stakeholder group will tackle new ozone-cutting strategies after miscalculations complicate getting EPA backing for the state's existing plan. Colorado will explore creating new limits for air pollution emissions made by oil and gas drilling and fracking after determining the state has undercounted emissions in plans meant to bring northern Front Range ozone levels into compliance with federal health standards. The state’s Air Quality Control Commission, in fashioning an ozone-reduction submittal to the Environmental Protection Agency this week, voted to call a stakeholder group together in 2023 to find strategies for cutting emissions of ozone precursor chemicals in the hope of meeting pollution standards the region has violated for years. Environmental activists and some local governments had wanted the state plan submitted to the EPA to clamp down on emissions from oil drilling and fracking now, while oil industry representatives argued to the AQCC that the oil industry has done more to slash emissions in recent years than any other. The AQCC, to the disappointment of some activists and some of its own commissioners, voted to submit an incomplete plan to the EPA and to form the stakeholder group to identify new ozone-control strategies. The decision likely would be received as kicking the can down the road, said Elise Jones, an AQCC commissioner who expressed frustration that effective ozone pollution controls have eluded state planners. “We need to do more, because we are failing collectively on this issue,” she said. Ozone is created when volatile organic compounds, nitrogen oxides and other air pollutants cook in warm sunlight. Breathing high levels of ozone can exacerbate asthma and other respiratory conditions and jeopardize human health. The Denver metro area and northern Front Range of Colorado have violated summertime air quality rules set in 2008 for what ozone levels are considered healthy under the federal Clean Air Act. Those standards were lowered in 2015. Ozone levels in the EPA-defined “non-attainment area” continue to violate standards, and the region has averaged high-ozone alerts on about 30 days each summer in recent years. The EPA downgraded the region from being “serious” to “severe” ozone violator, requiring the state to update its ozone plan. The AQCC, a volunteer commission that steers statewide air quality policy, met for three days this week to vote on ozone-reduction plans Colorado will submit for EPA review by March. The mistakes on nitrogen oxide emissions from oil preproduction prompted the group to pull sections of its federally-required plans from the submission. That’s likely to trigger an EPA finding that the plan is incomplete and start a clock ticking for Colorado to modify its plan. Air quality activists and local governments have criticized the state’s plan as inadequate because, even before the oil and gas preproduction miscalculations were discovered, what the state planned to propose to the EPA would get the region’s air to meet ozone standards before 2027 at the earliest. Clean air advocates and local government officials concerned about their constituents' health had urged air quality officials this week to do more in the ozone plan submission, and oil and gas was singled out by many of the activists as the leading industry to target. They argued for rules limiting emissions of nitrogen oxides from fossil-fuel-powered drilling rigs and the engines use in hydraulically fracturing underground shale to release oil and gas, a process known as ‘fracking.’ The engines used in traditional drilling rigs and fracking engines are regulated by EPA under non-roadway engine standards, but the emissions of oil and gas drilling and fracking aren’t specifically addressed by Colorado’s ozone-reduction planning. That became significant in recent weeks when local government and activist groups called out the state’s ozone plan for undercounting such emissions. This fall, the state’s Air Pollution Control Division staff recalculated its nitrogen oxide emissions totals used in the plan after observers realized oil and gas companies’ drilling project applications to the Colorado Oil and Gas Conservation Commission had been forecasting that drilling and fracking for those wells would create higher preproduction nitrogen oxide emissions than the per-well emissions factors the state uses in its ozone plan modeling. The state had undercounted oil and gas preproduction emissions by about 11%, the APCD staff concluded. That realization prompted the removal of several parts of the state’s ozone plan being submitted to the EPA so the stakeholder group next year could come up with new strategies and a more effective plan be resubmitted. Deciding to delay taking steps to cut nitrogen oxide emissions and set up a stakeholder group wasn’t an acceptable response from state air pollution officials, argued Caitlin Miller, an Earth Justice lawyer, testifying to the AQCC. “It’s a request by the division to be left off the hook for failing to living up to its obligations yet again,” Miller said. Oil and gas industry representatives participating in the ozone-reduction plan hearings this week said oil companies will enthusiastically contribute to the stakeholder discussions but said the effort to find new ozone control strategies shouldn’t single the oil industry out given the heavy regulation it already faces and how much it has cut ozone-related emissions in recent years. “The goal should be to find ways to reduce ozone, not to target oil and gas,” said Chris Colclasure, a lawyer with Denver-based Beatty and Wozniak representing oil and gas industry groups. The state’s own data from ozone monitoring stations show oil and gas production-related ozone below car travel and other sources in the foothills areas most often exceeding EPA ozone standards — monitors near Interstate 70 in Golden, at the Rocky Flats former nuclear weapons site and in Larimer County, all of which are miles from the Weld County oil fields where most wells are drilled. Other industries or pollution sources should be looked at too, Colclasure argued, and strategies, such as electrifying two-stroke, gas-powered lawn and garden equipment, could do more to reduce ozone that targeting oil and gas. Emissions of ozone-causing pollutants generally have been falling over the past decade as current ozone reduction strategies took effect, according to studies by the Regional Air Quality Council, a metro-area agency organized by local governments in the ozone non-attainment area. The long-term trends show lower ozone levels generally than there used to be, even though the northern Front Range remains out of compliance with EPA standards set in 2008 and lowered in 2015.
Merkley, Wyden sound alarm on 'fossil gas' pipeline expansion: 'Not in the public's best interest' – KTVZ - - Sens. Jeff Merkley and Ron Wyden, D-Ore., sent a letter to the Federal Energy Regulatory Commission Chairman Richard Glick and FERC commissioners, urging them to listen to the Oregon Attorney General and deny permits for TC Energy’s Gas Transmission Northwest Xpress project. “In order to reach a net-zero emissions economy by 2050, President Biden pledged to reduce greenhouse gas emissions by 50 to 52% by 2030, below 2005 levels,” wrote Merkley and Wyden. “According to FERCs FEIS, the project would emit 2.3 million metric tons of Carbon Dioxide equivalent emissions each year, until at least 2052. Your FEIS predicts the project will cause nine billion dollars in climate-related damage over the next 28 years. And that’s with a methodology that systematically minimizes the pipeline’s climate impacts. Adding new emissions through pipeline expansions like the GTN Xpress is incompatible with President Biden’s pledge.” In their letter, sent Friday, the senators highlight how Oregon has enacted policies that reduce greenhouse gas emissions—moving away from fossil gas—including investing in renewable energy. These policies show how renewable alternatives can meet energy demands without the climate and safety risks caused by fossil fuels. “The GTN Xpress would risk the safety of frontline communities and the planet for a project that isn’t necessary,” they write. “FERC itself said in its Final Environmental Impact Statement (FEIS) that it cannot determine the end use for the 51,000 Dth/d that Tourmaline Marketing Corp has subscribed for, a clear indication that demand for the project is uncertain. Adding fossil gas infrastructure in a region that is rapidly transitioning to renewable energy risks sticking ratepayers with the costs of an underutilized project and it isn’t in the public interest.” Merkley and Wyden’s letter continues by urging the FERC chairman and commissioners to listen to Oregon when it says the GTN Xpress is incompatible with climate objectives, highlighting how moving forward would not be in the public’s interest.
Environmentalists sue to stop U.S. oil and gas auction off Alaska coast (Reuters) - Environmental groups sued the Biden administration on Wednesday to block a sale of oil and gas drilling rights off the coast of Alaska that is scheduled for next week.The legal action, filed in federal court in Alaska, comes as the Interior Department is preparing to offer nearly 1 million acres in the Cook Inlet on Dec. 30. The sale was among the concessions to the oil and gas sector included in President Joe Biden's climate change law, the Inflation Reduction Act (IRA).Under the law, the administration is required to hold the sale by Dec. 31. Interior had scrapped the Cook Inlet sale this year before the IRA passed, citing a lack of industry interest. An Interior Department spokesperson declined to comment on the lawsuit. The groups suing the administration are Cook Inletkeeper, Alaska Community Action on Toxics, Center for Biological Diversity, Kachemak Bay Conservation Society and Natural Resources Defense Council.
Biden Administration Sued To Prevent Alaskan Cook Inlet Sale - Environmental groups filed a legal challenge today to stop the U.S. Department of Interior’s lease sale in Cook Inlet, Alaska. Lease Sale 258, scheduled for December 30, would auction off nearly a million acres of federal waters in Alaska, opening the door to decades of future oil-and-gas drilling. The Center for Biological Diversity and Natural Resources Defense Council (NRDC) filed the lawsuit together with Earthjustice, which represents the Cook Inletkeeper, the Kachemak Bay Conservation Society, and the Alaska Community Action on Toxics. Cook Inlet is home to beluga whales and sea otters protected under the Endangered Species Act. It also supports thriving subsistence, commercial, and recreational fisheries, and a multi-faceted tourist industry, fed by visitors from around the world who are drawn by the region’s unparalleled natural beauty. In a mutual statement, the groups reminded that the Cook Inlet was also previously hit by catastrophic oil spills like the infamous Exxon Valdez disaster more than 30 years ago. The groups stated that the government’s environmental analysis predicted a 1 in 5 chance of a large oil spill occurring from a Cook Inlet lease sale. The Department of Interior canceled the sale last May, but then announced it would move ahead after the passage of the Inflation Reduction Act. Though that legislation spurred unprecedented efforts to address climate change, it included a provision reviving this lease sale and mandating that it happen before the end of the year. Despite this requirement, the Interior retains full discretion as to how to conduct the sale. Under the legislation, the Interior has the discretion to restrict the amount of offshore acreage put up for lease, limit allowable activity on leased acreage, establish timetables for drilling activity on a leased area, and take other measures to limit harm. The groups claim that the Interior took no steps to limit oil-and-gas drilling and rejected alternatives that would result in a much smaller lease area. “Numerous scientific analyses have determined that the U.S. will not successfully slash greenhouse-gas emissions to meet its own established climate targets if it continues green-lighting new onshore and offshore oil-and-gas development on federal lands and waters,” the statement claimed. Today’s lawsuit argues that approval of the Cook Inlet lease sale violated the National Environmental Policy Act (NEPA) and should be vacated. Even under the new IRA requirements, the Interior must nevertheless adhere to NEPA’s requirements for the public process when considering the leasing decision. “The permitting agency violated NEPA by failing to meaningfully account for climate impacts or consider alternatives that would have resulted in less harm to the climate, marine life, and surrounding communities. Interior has also fallen short on keeping the public adequately informed, by failing to fully respond to public comments,” the groups said. “Our coastal communities have stood up repeatedly to say ‘no’ to oil and gas leasing in Lower Cook Inlet. This is our home, not a sacrifice zone. There would be little to gain in terms of affordable energy and much to lose in habitat, tourism, fisheries, and beauty. Lower Cook Inlet is worth far more — both in economic and cultural senses of value — intact and protected than with oil platforms and pipelines,” said Taylor Kendal Smith, communications director for Cook Inletkeeper “The Biden administration could have done so much more to limit the damage of the Inflation Reduction Act’s lease sale provision in Cook Inlet. Instead, during a climate and biodiversity crisis, it's offering a huge swath of the ocean, nearly a million acres, to fossil fuel bidders. This sale threatens irreplaceable waters and wildlife with oil spills and takes us backward in addressing the climate crisis. We’re going to court to force the administration to comply with our bedrock environmental laws, reconsider this mistake, and act consistently with its climate and biodiversity commitments. The Inflation Reduction Act should not prevent the administration from making the right choices to protect future generations,”
ConocoPhillips (COP) Says More US Cuts to Alaska Plan Would Kill Project - The head of ConocoPhillips’s Alaska operations signaled the company would walk away from an $8 billion oil project in the Arctic if the US government forced it to further scale down drilling to just two locations, saying that would no longer be economically viable. The warning comes as pressure intensifies on President Joe Biden to block the proposed Willow project in Alaska from environmentalists who say the warming world can’t afford to burn the estimated 600 million barrels of crude it could yield.
House Committee Wraps Up Historic Investigation Into Oil Industry - Congressional investigators released a new set of documents that underscored the oil and gas industry’s ongoing attempts to block climate policies and confuse the public about their long-term investments in fossil fuels. The latest tranche of documents caps off a nearly two-year investigation that appears set to come to an end with Republicans taking control of the House of Representatives in January. On December 9, the U.S. House Oversight and Reform Committee published its latest set of documents as part of its ongoing investigation into the oil industry’s history of climate denial and obfuscation. The documents offer more evidence showing that the industry’s “greenwashing” continues up to the present day. “They’re basically saying, ‘we’re going to increase production, we’re going to increase emissions, but we’re also going to be able to claim being this clean tech company, this green company, because we can take some symbolic actions that make it look like we’re in the climate fight,’” Rep. Ro Khanna, (D-CA), a member of the committee, told NBC News.“The cynicism was breathtaking, and unfortunately, it was quite successful,” he said, “It’s been a successful PR strategy.” The framing over the role of methane gas offers one glaring example. For years, the industry and its supporters have claimed that methane gas serves as a “bridge fuel” due to its perceived climate benefit over burning coal. That claim has not been backed up by the science, which increasingly shows that methane leaks can erase the upside of gas compared to coal. But even if true, internal communications show that despite their external claims, oil executives view gas not as a temporary “bridge,” but as something more permanent. Another revelation points to the oil industry’s efforts to cultivate influence through its financial support for Ivy League universities. In a 2019 email from former BP vice president Bob Stout, in which he discusses BP’s efforts at “nurturing” its relationship with Princeton University, he admits that ties with major American universities is part of a strategy of burnishing the industry’s image and also enhancing its influence.DeSmog has previously reported on the oil industry’s attempts to push its agenda through Ivy League universities. And a podcast collaboration between Drilled and Earther explored how oil companies have long been influencing American education for corporate benefit, from elementary schools to universities like Harvard. The latest release adds even more explicit evidence of an intentional strategy.
Big oil is behind conspiracy to deceive public, first climate racketeering lawsuit says - The same racketeering legislation used to bring down mob bosses, motorcycle gangs, football executives and international fraudsters is to be tested against oil and coal companies who are accused of conspiring to deceive the public over the climate crisis. In an ambitious move, an attempt will be made to hold the fossil fuel industry accountable for “decades of deception” in a lawsuit being brought by communities in Puerto Rico that were devastated by Hurricane Maria in 2017. “Puerto Rico is one of the most affected places by climate change in the world. It is so precariously positioned – they get hit on all fronts with hurricanes, storm surge, heat, coral bleaching – it’s the perfect place for this climate litigation,” said Melissa Sims, senior counsel for the plaintiffs’ law firm Milberg. The 1970 Racketeer Influenced and Corrupt Organizations (Rico) Act was originally intended to combat criminal enterprises like the mafia, but has since been used in civil courts to litigate harms caused by opioids, vehicle emissions and even e-cigarettes as organised crime cases. Now, the first-ever climate change Rico case alleges that international oil and coal companies, their trade associations, and a network of paid thinktanks, scientists and other operatives conspired to deceive the public – specifically residents of Puerto Rico – about the direct link between their greenhouse gas-emitting products and climate change. This fossil fuel enterprise, which remains operational according to the lawsuit, resulted in multitude of damages caused by climate disasters that were foreseen – but hidden – by the defendants in order to maximise profits. The plaintiffs are 16 municipalities in Puerto Rico – towns and cities that were hit hard by two powerful hurricanes in September 2017, Irma and Maria – which led to thousands of deaths, food shortages, widespread infrastructure damage and the longest blackout in US history.
'People from the sacrifice zone': Doctors call for moratorium on B.C. fracking as residents living near gas fields report health issues - --A group of doctors is calling for a moratorium on hydraulic fracking in British Columbia, citing reports from nearby residents the industry is deteriorating their mental and physical health. Their evidence is outlined in a report issued Wednesday from the Canadian Association of Physicians for the Environment (CAPE), which surveyed dozens of people living near gas fields in the province’s Peace region, last spring. “We call them people from the sacrifice zone,” said Dr. Larry Barzelai, a Vancouver family doctor and assistant professor in the University of British Columbia’s Faculty of Medicine.“Their lives are challenging. They’re producing the food and the natural gas for the rest of us. People should know what they’re dealing with," said Barzelai, who pointed to studies — mostly from the U.S. — demonstrating people living near fracking operations face increased rates of childhood leukaemia, low birth weights and congenital birth defects.Glacier Media requested comment from several of the largest producers of hydraulically fracked gas in B.C., but has yet to receive a response. Meanwhile, the BC Oil and Gas Commission deferred comment to the B.C. government and a spokesperson for B.C.'s Ministry of Energy, Mines and Low Carbon Innovation declined to immediately comment on the report's findings, saying it was still reviewing the document.
Regulator Lays Charges Against Suncor Over 2019 Worker Incident - The Canada-Newfoundland and Labrador Offshore Petroleum Board (CNLOPB) laid charges against Suncor Energy in relation to alleged offenses related to an injury onboard the Terra Nova FPSO. It is worth reminding that on December 29, 2019, a worker on the Terra Nova FPSO was injured after falling from a ladder while conducting gas testing. An offshore medic and emergency response team were called to the scene. The injured worker was medevaced to St. John’s on Sunday evening and is currently receiving medical care in the hospital. At the time of the incident, production-related operations on the Terra Nova FPSO were suspended as it was determined that Suncor was not compliant with requirements regarding maintaining and comprehensively inspecting equipment critical in the safe operation of the installation. The task being undertaken at the time the worker was injured was safety-focused and was not included in the scope of suspended activity. CNLOPB said that the charges against Suncor were laid on December 15, 2022. It said that, in relation to the incident, Suncor failed to produce a signed written report that complied with relevant regulations, committing an offence. The company also didn’t ensure that every employee entering into, exiting from, and occupying a confined space wore a safety harness that was securely attached to a lifeline, that was attached to a secure anchor outside the confined space, contrary to regulations, committing an offense. Also, on or about December 29, 2019, at or near the Terra Nova FPSO, located in the offshore area off the Coast of Newfoundland and Labrador, Canada, Suncor did not ensure that every employee entering into, exiting from, and occupying a confined space followed the procedures and used the protection equipment as required by regulations, committing an offense.
Mechanical Issues Force Noble To Evacuate Workers Off Rig - Offshore driller Noble Corporation has evacuated all personnel from one of its jack-up rigs after an issue was discovered on one of the rig’s legs. Noble said late last Friday that the jack-up rig Noble Regina Allen experienced a mechanical issue on Thursday, December 15, while preparing to move from its location approximately 26 miles off the coast of Trinidad. According to the company, a technical failure in the jacking gear appears to have caused damage to the bow leg braces and joints, preventing the rig from being able to fully retract one of its legs. With the structural integrity of the leg compromised, all rig personnel have been evacuated after confirming watertight integrity. It is worth noting that the rig completed all well operations before the event occurred and thus the well is secure. Noble is working closely with our customer and local authorities in response to the incident. Data in the driller’s fleet status report indicates that the Noble Regina Allen has been working for an undisclosed operator in Trinidad and Tobago since August 2022. This contract, scheduled to end in September 2023, is for six firm wells plus three two-well options with a day rate of $107,000. The jack-up rig is of the Friede & Goldman JU3000N design. It was constructed at Jurong Shipyard and can accommodate 150 people. With a drilling depth capability of 35,000 feet, this rig is capable of operating in water depths of up to 400 feet.
North Sea Regulator Fines 3 Companies -- The North Sea Transition Authority (NSTA) has announced that three operators have been fined a total of $322,201 (GBP 265,000). The move comes as the NSTA “cracks down on behavior that risks the industry’s drive to cut emissions and bolster the UK’s energy security”, the organization outlined. EnQuest has been fined $182,378 (GBP 150,000) for flaring an excess 262 tons of gas on the Magnus Field between November 30 and December 1, 2021, “despite knowing that it did not have the necessary consent in place”, the NSTA noted. Equinor was fined $79,030 (GBP 65,000) for flaring at least 348 tons of CO2 above the amount permitted on the Barnacle Field between June and November 2020 and Spirit Energy was fined $60,792 (GBP 50,000) for exceeding the maximum allowed production volumes from two fields over three years, the NSTA revealed. The organization said producing too much oil and gas can reduce the overall long-term production from a reservoir, to the detriment of the UK’s security of supply, “so it is vital that when an operator wants to raise production it applies for a new consent so that its new plan can be assessed”. The NSTA also pointed out that operators such as EnQuest and Equinor must follow a clear process to apply for consent to flare or vent gas. “The NSTA is committed to supporting the UK’s energy security and lowering greenhouse gas emissions, including through the use of our robust consenting procedures, which drive down flaring and venting,” Jane de Lozey, the NSTA’s Director of Regulation, said in an organization statement. “We are encouraged by recent improvements on emissions and will take action to ensure this vital work is not undermined by companies who fail to meet their obligations,” de Lozey added in the statement. The NSTA noted that EnQuest, Equinor and Spirit Energy all cooperated fully with the NSTA’s investigations, conducted their own internal reviews and have taken steps to avoid repeats of these breaches. Rigzone contacted all three companies for comment on the NSTA fines. “The fine relates to an administrative breach on the cross-border Barnacle field,” an Equinor spokesperson told Rigzone. “Barnacle is developed with a single well drilled from the Statfjord B platform on the Norwegian side of the median line. Any flaring from the field therefore happens and is accounted for in Norwegian waters,” the spokesperson added. A spokesperson from EnQuest told Rigzone, “EnQuest can confirm it has been sanctioned by the North Sea Transition Authority for a breach of flaring consent that occurred on the group’s Magnus asset in November 2021”. The company also conducted its own internal review to determine the cause of the failure and to prevent any future failure to comply,” the spokesperson added. “Notwithstanding the above, EnQuest accepts the NSTA’s sanction and will meet its obligations to pay the financial penalty as required by the regulator,” A Spirit Energy spokesperson said, “Spirit Energy is committed to operating in a socially and environmentally responsible way and takes any non-compliance in this regard seriously”.
NSTA names and shames as North Sea operators Equinor, EnQuest and Spirit hit with £265,000 fines - The North Sea’s oil and gas regulator has fined a trio of operators as it vows to “crack down” on behaviour that undermines energy security and transition.Operators EnQuest, Spirit Energy and Equinor were handed the penalties for issues linked to historic emissions violations and over-production. EnQuest was slapped with what is believed to be the largest fine issued by the North Sea Transition Authority (NSTA) to date, and must now stump up £150,000 for flaring an excess 262 tonnes of gas on its Magnus field. The activity, which occurred between 30 November and 1 December 2021, was conducted despite EnQuest knowing it did not have the necessary consent in place, the regulator stated. Norway’s Equinor was fined by the NSTA £65,000 for flaring at least 348 tonnes of CO2 above the amount permitted on its Barnacle Field between June and November 2020 – though notably the regulator made clear was an “administrative” issue. Equinor uses an allocation model to measure flaring volumes for the Barnacle Field, which straddles the UK/Norwegian border, as output from the field is mixed with oil and gas from other assets and processed on the Statfjord B platform in Norwegian waters. A spokesperson for Equinor added: “In 2020, Equinor became aware that it needed to log flaring allocations in the UK, in addition to Norway. The flaring on Statfjord was within Norwegian permits, but technically, the field was operating outside the UK flaring consent for a period of four months due to the missing logs. The NSTA acknowledged this was in essence “an administrative breach”, but nonetheless found the operator to have contravened its UK flare consent over the four months in question. In addition, Spirit Energy was fined £50,000 for exceeding its maximum allowed production volumes from two fields over a period of three years – the Rhyl field between 2018-20 and Ceres between 2019-20.
Strikes Underway At BP And Repsol North Sea Platforms -Unite, the UK’s largest industrial union, has informed that over 240 Petrofac workers posted on Repsol and BP offshore installations would be going on strike over two separate disputes. Unite said that around 170 members working for Petrofac are taking 48-hour strike action on Repsol installations offshore from today, December 22. The action follows workers rejecting the latest pay offer from the company by 79 percent on an 89 percent turnout in an increasingly bitter dispute over pay and working terms, which has seen previous rounds of industrial action. The installations impacted include the Arbroath, Auk, Bleo Holm, Claymore, Clyde, Fulmar Alpha, Piper Bravo, Saltire, Tartan Alpha as well as the Flotta oil terminal. Unite also confirmed that a further 48-hour strike will impact the Montrose platform starting on December 29 – 31. The dispute centers on the removal of a 10 percent Equal Time payment, years of below inflationary pay increases as well as issues around payments for Offshore Energies UK (OEUK) medicals, mileage, and stand-in duties. “Petrofac Repsol workers across the various installations are taking this latest action due to a series of unacceptable pay offers. Unite’s members are watching offshore oil and gas giants mount up eye-watering profits. Instead of paying the workforce what they deserve because they are the ones ultimately generating these profits Petrofac Repsol are reveling in playing Scrooge. Unite supports and will continue to support our members at Petrofac for as long as it takes for them to achieve a successful resolution,” Unite general secretary Sharon Graham said. In a separate dispute, Unite members at Petrofac’s BP installations: Andrew, Clair, Clair Ridge, ETAP, and the Glen Lyon FPSO will also begin 48-hour strike action on December 29 – 31. The Petrofac BP dispute centers on the working rotation, which is currently a work 3 on/3 off rotation. This action involves 76 members. Unite anticipates that the strike action by Petrofac workers at both Repsol and BP facilities are likely to cause considerable disruption and the trade union has warned that further action is being actively considered which would extend the dispute into 2023. “Unite’s members have been left with no choice but to take further strike action due to the indifference and intransigence shown by Petrofac management. Several rounds of 48-hour strike action will now take place following our members rejecting the latest pay offer which represents real terms pay cut.”
Evidence In Nord Stream Sabotage Doesn't Point To Russia: Washington Post - A surprising admission has come in a Washington Post report Wednesday morning following a months-long investigation into the Sept. 26 Nord Stream 1 and 2 pipeline sabotage attacks. While there remains consensus that the explosions were indeed the result of a deliberate act of sabotage, numerous officials in the West now say the evidence is not pointing to Russia. WaPo begins by recounting the frenzied rush to immediately blame Moscow, which began within a mere hours into the massive gas leaks into the Baltic Sea: After explosions in late September severely damaged undersea pipelines built to carry natural gas from Russia to Europe, world leaders quickly blamed Moscow for a brazen and dangerous act of sabotage. With winter approaching, it appeared the Kremlin intended to strangle the flow of energy to millions across the continent, an act of "blackmail," some leaders said, designed to threaten countries into withdrawing their financial and military support for Ukraine. And then comes this admission: "But now, after months of investigation, numerous officials privately say that Russia may not be to blame after all for the attack on the Nord Stream pipelines." The Post issued the rare about-face of accusations after interviewing a total of 23 diplomatic and intelligence officials in nine countries who have been privy to the international investigation into the sabotage incident which has threatened European energy supplies going into winter. "There is no evidence at this point that Russia was behind the sabotage," one European official is quoted as saying. Further, the report indicated, "Some went so far as to say they didn’t think Russia was responsible. Others who still consider Russia a prime suspect said positively attributing the attack — to any country — may be impossible." Among other prime suspects and theories, typically echoed in independent and alternative media, is that the United States is to blame. At least one UN official and prominent economist shocked a Bloomberg panel in suggesting this in early October...
Fire Detected Onboard Prelude FLNG Facility -- A Shell spokesperson has confirmed to Rigzone that a fire was detected onboard the Prelude Floating Liquid Natural Gas (FLNG) facility offshore Australia. “On Wednesday 21 December at 16:25 AWST, there was a small fire detected onboard Prelude in a turbine enclosure,” the Shell spokesperson told Rigzone. “The fire was quickly contained using a hand-held extinguisher and the area made safe. There were no injuries and all workers on the facility are safe and accounted for,” the spokesperson added. “Production has been temporarily suspended and an investigation into the cause of the incident is underway. We will work methodically through the stages in the process to recommence production with safety and stability foremost in mind,” the spokesperson continued, adding that the regulator had been informed. Prelude FLNG produces natural gas off the coast of Australia in the Browse Basin. The facility has a production capacity of at least 5.3 million tons per annum of liquids - comprising 3.6 mtpa of LNG, 1.3 mtpa of condensate and 0.4 mtpa of liquefied petroleum gas – according to Shell’s website, which highlights that the facility is 488 meters long and 74 meters wide. Prelude FLNG has been designed to remain moored for at least 25 years, Shell’s site points out. Back in June 2019, Shell announced that the first shipment of LNG had sailed from Prelude FLNG. The shipment was delivered by the Valencia Knutsen to customers in Asia, Shell revealed at the time. In May 2011, Shell announced final investment decision on Prelude FLNG. In a company statement at the time, Shell described the project as “groundbreaking”.
Bloomberg Describes Europe’s Severe and Sustained Energy Crisis Due to Loss of Russian Gas - Yves Smith - For some time, this site has predicted the inevitability of a European economic crisis due to the loss of cheap Russian gas and the delay and much higher cost in securing replacement energy sources, primarily LNG. Mainstream press coverage, likely reflecting European leadership’s “kick the can” reflexes, has touted that Europe has decent odds of having its stored Russian gas (along with other sources, like wind and nuclear power) carry Europe through the winter. And in fairness, gas prices in Europe have dropped since late summer peaks: But looking at current and near term price expectations ignores the cost at which this relief has been achieved, namely, deindustrailization. Energy-intensive businesses, from aluminum, glass, chemical, and paper makers to greenhouse operators are cutting back, suspending, or even shuttering operations. Even with energy subsidies in place, many households are cutting back because they can’t afford the higher prices. Needless to say, budget-squeezed consumers are a further drag on business activity. Germany and the UK have been particularly noisy in warning citizens about possible rolling blackouts over the winter. We weren’t alone in warning about the prospect of continued hardship. From Forbes back in September: With natural gas prices over $100 more per megawatt hour than they were a year ago, the Western European economies are heading to the Middle Ages. Forests are being cut for firewood as Russia retaliates with its own Ukraine war sanctions by shutting off the trickle of natural gas it was still piping into Europe….Corporate investment goes where money goes farthest. It used to be taxes and labor and environmental costs they looked at. Now European companies will add electricity to the mix. None of this bodes well for European businesses…. Given that the short-term relief in European gas prices means a lot of people who know better will nevertheless try not to think much about Europe’s sorry prospects, Bloomberg surprisingly published a blunt, fact-filled assessment: From Bloomberg: After this winter, the region will have to refill gas reserves with little to no deliveries from Russia, intensifying competition for tankers of the fuel. Even with more facilities to import liquefied natural gas coming online, the market is expected to remain tight until 2026…. While governments were able to help companies and consumers absorb much of the blow with more than $700 billion in aid, according to the Brussels-based think tank Bruegel, a state of emergency could last for years. With interest rates rising and economies likely already in recession, the support that cushioned the blow for millions of households and businesses is looking increasingly unaffordable…And the EU has competition: Chinese gas imports are likely to be 7% higher in 2023 than this year, according to China National Offshore Oil Corp.’s Energy Economics Institute. The state-owned company has started securing LNG supplies for next year, putting it in direct competition with Europe for spare shipments. China’s historic drop in demand this year was equivalent to about 5% of global supply.China isn’t Europe’s only problem. Other Asian countries are moving to procure more gas. Japan, the world’s top LNG importer this year, is even considering setting up a strategic reserve, with the government also looking to subsidize purchases. Now Europe may get lucky. China dropping Zero Covid looks to be hurting its workforce even more than Zero Covid did. That is likely to lead to yet more supply chain disruption and lower demand within China, both of which will dampen demand for LNG and therefore hopefully alleviate price pressure. Europe may get lucky with the weather, both temperature and wind generation. But even if it limps through the winter, it will still have a structural problem in 2023 even in warmer weather. Electricity won’t get to be cheap enough to bring back those energy-hogging businesses. The loss of jobs and industrial demand will eat into tax revenues, making energy subsidies even more costly in budget terms. Demand for social services will rise..
Mild Christmas and New Year to Ease Europe Power Grid Stress - Mild weather is expected to remain over most of Europe during the holidays, dimming the chances of a white Christmas but easing pressure on the region’s power grids. Temperatures in Paris and Frankfurt are expected to be around 7 degrees Celsius warmer than seasonal norms on Friday, Maxar Technologies Inc. said in a report. The mild weather is expected to stay through the first week of January, it said. That outlook will ease pressure on Europe’s energy systems, which were strained earlier this month by the first cold blast of winter. European natural gas prices fell for a fifth day, while the region’s gas storage remains 83% full. Demand for power and gas typically drops during the holiday period with most offices and businesses shut. A total of 71.4 heating-degree days are expected for Dec. 27 until Dec. 31, below the 10-year average of 76.4 days, Maxar said. German wind output is expected to peak at 15,093 megawatts at midnight on Friday, compared with a high of 19,442 megawatts at 11 a.m. on Thursday, according to Bloomberg model and EEX data. Further north, the Nordics will stay icy with the potential for snow. The temperature in Oslo on Christmas Eve could be 11 degrees Celsius below the seasonal average, according to Maxar.
The EU agreed to limit gas prices, but some analysts are skeptical - The European Union Monday concluded two months of heated talks over how to protect households from rising energy prices — but some analysts argue the bloc’s solution is unsustainable and might not withstand the realities of a 2023 gas supply crunch. EU members compromised by adopting a “dynamic” cap on the price that can be bid for front-month gas contracts on Europe’s benchmark trading facility. The level at which the cap is triggered was lowered to 180 euros per megawatt hour, after an initial proposal of 275 euros per megawatt hour was criticized as far too high by countries including Poland, Spain and Greece. The 180 euro limit must be surpassed for three working days on the Dutch Title Transfer Facility (TTF), and it must be 35 euros per megawatt above the global reference price for liquefied natural gas over the same period. Several conditions were inserted to allay the concerns of members such as Germany, which had argued that the scheme could result in gas shortages next year. These clauses prompt an automatic suspension of the cap and include the dynamic bidding rate dropping below 180 euros per megawatt hour for three consecutive working days, or the European Commission declaring an emergency. Germany eventually voted in favor of the so-called “market correction mechanism,” but the Netherlands and Austria abstained. Austria’s ministry for climate action said in a Tuesday statement that while it was “confident that the market correction mechanism can play an important role to avoid extreme spikes in European gas prices, the last minute extension of the mechanism on more gas hubs than the TTF does issue some concerns.” The ministry noted that “there are some risks that the necessary safeguards are undermined by this extension.” Austria depends on Russian gas. Rob Jetten, Dutch energy minister, said that the mechanism remained “unsafe” despite the latest improvements. He flagged that it could disrupt the European energy market, risk security of supply and have wider financial implications. “From its inception, we have been very clear about this mechanism: it does not solve the core problem,” he said, adding that the Netherlands’ concerns were shared by the European Central Bank and by ICE (Intercontinental Exchange), the operator of the key natural-gas market in Europe. The ECB earlier this month said “the current design of the proposed market correction mechanism may, in some circumstances, jeopardize financial stability in the euro area.” It declined to provide further comment to CNBC following the EU announcement. ICE said in a statement it had “consistently voiced concerns” about the destabilizing impact of a price cap. It added that it would now review the details of the EU announcement to see whether it “can continue to operate fair and orderly markets for TTF from the Netherlands as per our European regulatory obligations.”
Russia reports explosion in pipeline supplying gas to Europe – --- An explosion blew through a pipeline bringing gas from Russia to Europe, killing three people and disrupting gas flows, Russian media reported.The blast in the Urengoi-Pomary-Uzhhorod pipeline — which enters Ukraine via the cross-border metering point Sudzha — was announced by local authorities in the small central Russian village of Kalinino at 11:44 a.m. The resulting gas flare has since been extinguished, according to local officials, and gas flows through a section of the pipeline have been halted. Roughly 43 million cubic meters of natural gas had been flowing to Europe via Sudzha — the only point at which gas is still transiting from Russia to Ukraine — on a daily basis. The pipeline became the main artery for Moscow's gas to enter Europe following the explosions that damaged the Nord Stream pipeline in September; Western officials said the blasts were the result of sabotage. Russia's Gazprom said it would continue to provide natural gas to affected consumers through parallel pipelines. Russian authorities said they are opening a case to investigate any potential "violation of industrial safety requirements" at the site of the blast, where they said repair work was being carried out at the time of the explosion. One person was also injured in the blast.Day-ahead futures on Europe's gas trading benchmark, the Dutch TTF, rose to €114 per megawatt-hour at midday following news of the explosion — €11 higher than the previous hour.
Three killed in Russian gas pipeline explosion during repairs - Three workers were killed in an explosion at a Russian pipeline that was being repaired. The incident occurred Tuesday at the Urengoy-Pomary-Uzhhorod pipeline in the Chuvashia region in central Russia. In addition to the deaths, another worker was injured. The blast caused a fireball of burning gas to rise. Export supplies were not effected by the explosion as they were re-routed to different lines, Gazprom officials said. The pipeline, which starts in Siberia before traveling through Ukraine, is one of the main natural gas suppliers to the European Union. Oleg Nikolayev, the governor of Chuvashia, said it was unclear how long repairs to the impacted area would take but noted the fire was extinguished quickly. In September, the Nord 1 and Nord 2 pipelines under the Baltic Sea were damaged in an explosion believed to have been an act of sabotage, though it is not known who is responsible.
Explosion tears through Russian gas pipeline during repairs - An explosion during repairs on a section of a Europe-bound natural gas pipeline in western Russia has killed three people but didn't affect export supplies, officials said. The explosion on Tuesday ripped through a section of the Urengoy-Pomary-Uzhhorod pipeline in the Chuvashia region during repair work. Three repair workers were killed and one was injured by the blast, which sent a huge plume of burning gas skyward, regional authorities said. The pipeline that originates at a gas field in Siberia and crosses Ukraine along its way to Europe is one of the main routes for Russian gas exports to the EU. Chuvashia's governor, Oleg Nikolayev, said in televised remarks that it wasn't immediately clear how long it would take to fix the section of the pipeline cut by the explosion. The regional branch of Russia's state-controlled natural gas giant, Gazprom, said volumes of gas transportation weren't affected by the blast as supplies were rerouted along parallel lines. The pipeline crossing Ukraine has become the main conduit for Russian natural gas supplies to Europe since an explosion ripped through the Nord Stream 1 and 2 pipeline under the Baltic Sea in September, causing extensive damage.
Deadly Blast Destroys Russia-Ukraine Gas Export Pipeline - A gas pipeline in central Russia that brings gas from Russia's Arctic through Ukraine to Europe has been shut following a huge blast that ripped through and left three people dead and one injured, Reuters cited local officials and TASS news agency as reporting. According to the Chuvashia regional Emergencies Ministry, the pipeline blew up during planned maintenance work near the village of Kalinino, about 150 km (90 miles) west of the Volga city of Kazan. The resulting gas flare has been extinguished, with local officials reporting that the flow of gas through the section of the Urengoi-Pomary-Uzhhorod pipeline was cut off around 1050 GMT, Tass reported.Later on Tuesday morning, a local unit of Gazprom said in a statement carried by Reuters that gas was being diverted to parallel pipelines as a result of the explosion Built in the 1980s, the pipeline enters Ukraine via the Sudzha metering point, and currently is the main route for Russian gas to reach Europe. State-owned gas producer Gazprom and its local branch has, however, failed to respond to requests for comment. Europe probably won’t lose too much sleep over it though. Gazprom had earlier revealed that it expected to pump 43 million cubic meters of gas to Europe via Ukraine through Sudzha in the next 24 hours, a volume in line with recent days. To put that number in context, that run rate represents just 5.4% of the 155 billion cubic meters of natural gas that Europe imported from Russia in 2021. Europe has managed to stockpile huge volumes of natural gas for the winter season, so much so that prices have tumbled sharply in recent months.Whereas supplies of Russian pipeline gas--the bulk of Europe’s gas imports before the Ukraine war--are down to a trickle, Europe has been hungrily scooping up Russian LNG in the meantime. The Wall Street Journal has reported that the bloc’s imports of Russian liquefied natural gas jumped by 41% Y/Y in the year through August.
Volumes Transiting Ukraine Are At Risk - Volumes transiting Ukraine are at risk, with a potential upward impact on prices, according to a new gas and LNG market note from Rystad Energy Analyst Nikoline Bromander. In the note, Bromander revealed that a section of the Urengoy-Pomary-Uzhgorod (UPU) gas pipeline in Chuvashia, Russia, was damaged by an explosion on December 20 during repair work and said it is currently blocked on both sides. “The UPU pipeline is a part of Russia’s ‘Brotherhood’ pipeline network and is used to send gas to continental Europe,” Bromander said in the note, which was sent to Rigzone. “Mikhail Faleyev, former deputy head of Russia’s ministry for emergencies, has been quoted in RIA as saying that the damaged section is expected to be restored within a few days,” Bromander added. “If this doesn’t happen, gas could be re-directed from the UPU pipeline to one of four other pipelines that run alongside it with a total capacity of 100 billion cubic meters. However, it is hard to quantify precisely how much gas could be redirected in this way,” the analyst continued. Bromander outlined that if Russian flows through Ukraine were to halt entirely, “this would put upward pressure on gas prices in Europe, as the volumes represent around four percent of Europe’s total annual gas demand”. “Countries directly importing gas from the Ukrainian transit and connecting pipelines would also face consequences, including Slovakia, the Czech Republic, Austria, Germany, France, Switzerland, Slovenia, Croatia and Italy,” Bromander said, adding that all these countries have sufficient volumes of natural gas in storage. Russian flows through Ukraine have held steady at around 43 million cubic meters per day (MMcmd), with Russian flows through the TurkStream pipeline also stable at 35 MMcmd, the Rystad analyst highlighted in the note.
Russian Ally Mulls More Gas Links to Diversify Supply | Rigzone – Serbia is considering building more gas links with nearby countries to reduce dependence on Russian flows and turn it into a regional transit hub. The former Yugoslav republic is already building an interconnector with Bulgaria — due to be completed next year — which will enable imports from Central Asia and liquefied natural gas terminals on the Mediterranean. It’s now also looking at adding a link to North Macedonia and maybe Albania, the energy and mining minister said. The nation is balancing a bid to join the European Union while refraining from embracing sanctions against its traditional ally Moscow. At the same time, the government is joining international efforts to diversify energy supplies from Russia, with whom it gets almost all its gas from. “We don’t have enough of our own resources, at least when it comes to gas, but everything that can reduce dependence on Russia in the gas segment is important for us,” Energy and Mining Minister Dubravka Djedovic said in an interview. “We’re talking about hundreds of millions of euros” in projects to bring fuel from places like Azerbaijan and connect with terminals in Greece, she said. An EU grant is paying for half of the 93 million-euro ($99 million) cost of building the interconnector with Bulgaria, and Serbia is looking for more support from the bloc for additional cross-border pipes that could turn it into an important transit route. A link between Serbia and North Macedonia — estimated at 80 million euros — is at a preparation stage, said Djedovic, who joined the government in October. One to Albania depends on that country’s progress in developing a planned LNG terminal on its Adriatic coast. “Once we enable the connections to streams that are coming from alternative sources, we will be less dependent on Russian” flows, she said, outlining plans for an eventual connection to the Trans-Adriatic Pipeline, which links to the Trans-Anatolian Natural Gas Pipeline. Still, Serbia’s deep ties with Russia’s Gazprom PJSC should continue, the minister said. Gazprom sells Serbia fuel through an extension of the TurkStream pipeline at below-market rates. Plus, a Gazprom unit co-owns Serbia’s Banatski Dvor gas-storage facility and its oil arm Gazprom Neft operates Serbia’s sole refiner, NIS. In the oil market, an EU ban on Russian crude has disrupted deliveries to refiner NIS, whose only one viable supply route is through a pipe in Croatia. While the refiner has been processing mostly non-Russian oil since before the war in Ukraine, the government is still looking at adding more options, such as new links.
Exxon Avoiding Tankers That Previously Transported Russian Oil - Exxon Mobil Corp. is avoiding hiring oil tankers that previously carried cargoes from Russia, putting itself in the same camp as Shell Plc with a move that pressures owners to choose whether to serve Moscow’s interests or not. The largest oil company in the US began asking that, from Dec. 5, shipowners must ensure the tankers on lease to Exxon haven’t carried crude cargoes which are either Russian, originated in Russia, or come from a person connected with Russia, a clause seen by Bloomberg shows. Failure to do so would allow Exxon to terminate the charter. A spokeswoman for Exxon declined to comment. The approach is similar to that of Shell, whose first preference is for ships that haven’t carried Russian crude in their last three cargoes. Moves by such big firms only increase the pressure on owners to choose between serving Russian and non-Russian interests. Shipping firms intending to transport the nation’s barrels can already only get industry standard insurance and an array of other G-7 services if the cargoes they’re hauling cost $60 a barrel or less. The measures included a clause that if companies pay above $60 then they can’t access key EU services for the transportation of Russian cargoes for 90 days. The Exxon clause doesn’t apply to Kazakhstan’s CPC oil, so long as the seller isn’t Russian or connected with Russia, and a Kazakh certificate of origin is received. Exxon’s mandate expands from Feb. 5, 2023 to Russian oil products, with the same exception as above. That’s when further G-7 sanctions will kick in, affecting refined fuel markets. The Group of Seven’s measures have triggered the emergence of a so-called dark fleet of tankers that are expected to be dedicated to servicing Russia’s interests. Moves like Exxon’s and Shell’s make it harder for those vessels to return to non-Russian business.
Russia's Baltic Oil Exports Could Fall by 20% Due To Sanctions - Exports of Russia's flagship Urals crude blend from the Baltic Sea ports will probably fall to around 5 million tonnes this month from 6 million tonnes in November, thanks to an EU embargo on Russian oil and a Western price cap, according to Reuters calculations. Some estimates have predicted it could fall as low as 4.7 million tonnes. The $60 per barrel price cap introduced by the European Union, G7 nations and Australia allows non-EU countries to import seaborne Russian crude oil, but prohibits shipping, insurance and reinsurance companies from handling cargoes of Russian crude unless it is sold for under $60. Traders have reported to Reuters that Russia is struggling to fully redirect Urals exports from Europe to other markets such as China and India India and is also having a hard time finding enough suitable vessels. Russia’s problems have been compounded by a shortage of non-western tonnage, moderate demand for the grade in Asia, especially in China and a weak export economy. Indeed, Reuters has reported that Russia’s pipeline monopoly Transneft has been unable to fill some of the available loading slots due to a lack of bids from producers while other slots were postponed or canceled. Only China, India, Bulgaria and Turkey are currently willing to buy Urals with the blend now being sold to export markets at below overall production cost including local levies. Citi’s Global Head of Commodities Research Ed Morse has dismissed the price cap, terming it as silly, impractical and unlikely to work in tight gas markets because gas markets are global and not bifurcated into individual countries, meaning the forces of demand and supply are more likely to prevail in determining gas prices. As such, Morse says the price cap is likely to lead to gas shortages in Europe especially during winter months when demand is high. Further, the commodity analyst says that getting rid of the TTF natural gas benchmark is likely to cause chaos when determining gas prices especially if other existing benchmarks lack sufficient liquidity.
Russia Says It May Cut Daily Oil Output by 700K Barrels - Russia may reduce its oil output by 500,000-700,000 barrels a day in early 2023 in response to the Group of Seven’s price cap on the nation’s crude exports, according to Deputy Prime Minister Alexander Novak. “We are ready to partially cut our production early next year,” he said in an interview with Rossiya-24 TV channel, adding the volumes equate to roughly 5%-6% of what Russia’s now pumping. “We’ll try to find some common ground with our counterparts to prevent such risks,” Novak said. “But right now we’d rather take a risk of a production cut than stick to the policy of selling in line with the threshold.” While he described the potential output declines as “insignificant,” a cut of that size could still tighten the global oil market at a time when many analysts predict demand in China will be rebounding. Novak, Moscow’s main negotiator at OPEC+ and the key governmental energy official, reiterated that Russia will not sell its crude to buyers and nations that use the western price cap. Russian producers are able to reroute their exports to competing markets, including Asia, as the nation’s energy is still in high demand globally, he said. Oil prices have jumped in the past two weeks and climbed further on Friday, with Brent trading at almost $82 a barrel. President Vladimir Putin told reporters on Thursday he will sign a decree on the nation’s response to the cap on Monday or Tuesday. It will feature “preventive measures,” he said, without elaborating. Russia’s full-year oil production this year will probably grow to 535 million tons, according to Novak. That’s equivalent to around 10.74 million barrels per day, based on a 7.33 barrel-per-ton ratio. Russia’s average daily output in November reached an eight-month high of 10.9 million barrels, according to industry data seen by Bloomberg. The G7 and European Union’s $60-per-barrel cap on Russian seaborne crude supplies began on Dec. 5. That move and a ban on EU imports of seaborne Russian flows, regardless of the price, were designed to curb the Kremlin’s oil revenues and hinder its ability to fight in Ukraine. Russian oil cargoes that are traded above the threshold cannot access some key services from western companies, including insurance.
Germany Pivot to Piped Kazakh Oil Looks Like Pipe Dream - Germany is days from halting piped oil imports from Russia, creating pressure to find alternatives. The nation’s economy ministry in Berlin confirmed on Tuesday that Germany won’t be buying Russian oil at all in 2023, reaffirming a pledge to halt by the end of this year. The step is to punish the Kremlin for the war in Ukraine. One emerging idea is to use Russia’s pipeline system to import from Kazakhstan instead. There’s even talk of a test shipment early next year. Germany, along with most of the European Union, already has a ban on seaborne deliveries from Russia. But getting piped supplies of Kazakh crude thousands of miles to refineries in eastern Germany would present huge challenges on multiple fronts. The first is that the pipelines through which the oil would have to flow are Russian — the giant Druzhba network. As such, any decision to facilitate such shipments can only be made by Moscow. So far, Russia’s oil-pipeline operator Transneft PJSC hasn’t received any request from Kazakhstan to deliver to Germany, according to company’s spokesman Igor Dyomin. Some Kazakh barrels are already pumped northward to Almetyevsk in Russia and mixed with oil from Russian fields into a common export grade, officially known as Russian Export Blend Crude Oil, or REBCO, which is more often referred to as Urals. Physically shipping Kazakh crude to Germany without any Russian oil in it is unlikely to be feasible. It would require volumes to be sent in batches to avoid mixing it with molecules of Russian origin. That would be hugely disruptive to the Russian pipeline network and it’s hard to see Transneft supporting the idea. Even if it did, such an approach would see German refineries receiving untested crude grade with characteristics that may be very different from those of their normal diet of Urals, which has tight parameters on density and sulfur content. In practice, though, if shipments do end up getting made, they mightn’t end up being actual Kazakh-origin supplies. Kazakhstan’s KMG Trading, a subsidiary of state oil company KazMunayGas JSC, puts 13 million tons a year into the Russian pipeline system and is allocated an equivalent amount of Urals that it can then sell internationally. The Urals cargoes belonging to KMG have been specifically excluded from EU sanctions on seaborne imports from Russia and have been re-labeled Kazakh Export Blend Crude Oil, or KEBCO, to distinguish them from REBCO. Those cargoes are lifted from the ports of Novorossiysk on the Black Sea and Ust-Luga on the Baltic. They are entirely separate from Kazakhstan’s CPC Blend exports that get loaded onto tankers at a dedicated terminal near Novorossiysk. But even if Russia agrees to some kind of swap, the question is: where would Kazakhstan find the extra crude to put into the Russian pipeline system in order to direct more to eastern Germany. That’s because KazMunayGas must first supply refineries in Kazakhstan to fulfill its obligations on fuel supply to the domestic market. When it comes to exports, the first priority — through KMG Trading — is to meet the needs of the firm’s refinery in Romania. Remaining volumes are sold under long-term contracts, according to KazMunayGas. Kazakhstan can’t redirect the KEBCO it exports via Ust-Luga port without breaking those contracts for 2023 supplies, leaving next to nothing to spare for Germany. So once the domestic market is supplied, and Romania is served, it’s unclear where Kazakhstan could find additional volumes for Germany. And that’s assuming Russia plays ball.
Oil Refiners: Japan sounds out oil refiners on buying Russian oil from Sakhalin - Japan is sounding out major oil refiners about buying Russian ultra light crude from the Sakhalin-2 gas and oil project to ensure that the plant can continue to operate smoothly, two sources with direct knowledge of the talks said.The Sakhalin Island complex, partly owned by Gazprom and Japanese companies, is vital to Japan's energy security as it accounts for 9% of the country's liquefied natural gas imports. ..The government's move signals a potential restart of Russian oil imports by Japan for the first time since June. This is not likely to upset its allies in Group of Seven (G7) as they have agreed to exempt the Sakhalin-2 oil from a price cap placed on Russian crude exports this month.
China boosted crude oil storage even as refiners processed more - China’s loosening of its strict zero-COVID restrictions is widely being viewed as bullish for crude demand. But there are other factors in the world’s largest oil importer that give pause. One is that China is continuing to build crude oil stockpiles, even though its refinery processing rates have risen strongly in recent months. China’s refinery throughput rose to the equivalent of 14.51 million barrels per day (bpd) in November, a one-year high and up from 14.22 million bpd in October, according to official data released on Thursday. On the surface this feels like a strong outcome that is positive for crude oil demand, especially when other indicators such as rail freight, and air and road traffic are also moving higher. But despite the solid gain in refinery processing, it appears that China is still building up crude oil inventories in commercial or strategic storage tanks. China doesn’t disclose the volumes of crude flowing into or out of strategic and commercial stockpiles, but an estimate can be made by deducting the amount of crude processed from the total of crude available from imports and domestic output. The total volume of crude available from imports and domestic production in November was 15.46 million bpd, consisting of imports of 11.37 million bpd and local output of 4.08 million bpd. This means the volume of crude available exceeded the amount processed by 950,000 bpd, which was up from 420,00 bpd in October. Over the first 11 months of 2022 the volume of crude going into inventories was around 700,000 bpd. China has had more crude available than the amount processed in 10 of the 11 months so far in 2022, which is somewhat surprising given crude prices surged after Russia’s Feb. 24 invasion of Ukraine. What is likely is that in recent months, Chinese refiners have been buying up Russian crude on the cheap and ahead of any loss of supplies from the Group of Seven nations cap on the price of Russia crude. Certainly, Russian shipments to China have been strong in recent months, with the country taking over the title of biggest supplier from Saudi Arabia. China imported an estimated 1.80 million bpd from Russia in November, according to Refinitiv Oil Research, exceeding the 1.69 million bpd supplied by Saudi Arabia. Chinese refiners have also been exporting more refined fuels, especially diesel, having been granted additional quotas in order to take advantage of high regional prices for the transport and industrial fuel.
Rising supply from Kuwait, Russia to weigh on Asia fuel oil in 2023 -- Asia is expected to be flooded with more fuel oil supplies in 2023 as Kuwait's new Al-Zour refinery ramps up output and as Russia diverts record volumes from Europe to the East ahead of sanctions. Higher supplies are expected to weigh on Asia's fuel oil prices and refiners' margins next year amid steady demand from the ship fuelling and power generation sectors. The 615,000 barrels-per-day Al Zour refinery, which started exporting products in November, is poised to be a major supplier of very-low sulphur fuel oil (VLSFO), commonly used for ship refuelling, known as bunkering.
Saudi Aramco and Sinopec sign initial agreement to set up refinery in China - Leading crude oil exporter Saudi Aramco and China Petroleum and Chemical Corporation (Sinopec) have signed an initial agreement to build a refinery and a petrochemicals plant in China. The 320,000 barrels-per-day refinery and 1.5 million tonnes-per-year petrochemical cracker complex will be in operation by the end of 2025, Aramco said in a statement on Sunday.Aramco and Sinopec, along with Saudi Basic Industries Corporation (Sabic), have also signed a preliminary agreement to study the feasibility of developing a petrochemicals complex to be integrated with an existing refinery in Yanbu, Saudi Arabia.“These projects represent an opportunity to contribute to a modern, efficient and integrated downstream sector in both China and Saudi Arabia,” Mohammed Al Qahtani, Aramco's senior vice president of downstream, said.“They also underpin our long-term commitment to remain a reliable supplier of energy and chemicals to Asia’s largest economy.”The petrochemicals industry is expected to be a big driver of crude oil demand in the next few decades as consumers switch to electric vehicles.Petrochemicals are set to account for more than a third of the growth in oil demand to 2030, and about half to 2050, ahead of the lorry, aviation and shipping sectors, according to the International Energy Agency. Petrochemicals are also likely 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 agency said.Aramco aims to increase its liquids-to-chemicals capacity to up to four million barrels per day by 2030. This month, Aramco signed an initial agreement with China’s Shandong Energy Group to supply crude oil and chemical products. The scope of the agreement also extends to co-operation across technology related to hydrogen, renewables and carbon capture and storage. Saudi Arabia and China agreed to enhance political, economic and energy ties during Chinese President Xi Jinping's three-day visit to Saudi Arabian capital Riyadh this month.In September alone, China's exports to Saudi Arabia reached $3.43 billion, while imports stood at $6.81bn.Last year, crude oil was Saudi Arabia's main export to China, which shipped the most cars to the kingdom.In 2020, China became the GCC’s top trading partner, and Saudi imports from China rose by 18 per cent in 2020 to $28.1bn, according to Chinese customs data.
South Africa’s massive petrol and diesel price increases -- The fuel pumps were no friends of South African wallets in 2022. Both the retail petrol and wholesale diesel prices reached record highs during the year, following on from a 2021 that had already seen substantial hikes. Prices were heavily influenced by Russia’s invasion of Ukraine and the ongoing conflict, as Russia is one of the world’s major oil producers. That sent the Brent crude oil price to its highest levels in more than a decade. In addition, the US dollar strengthened significantly against other currencies as the Federal Reserve hiked interest rates to try and curb inflation. Since oil is priced in dollars, this effectively further increased oil costs for South Africa. Other contributing factors to South Africa’s fuel price include annual increases in fuel-related taxes. The inland retail price of a litre of unleaded 95 petrol shot up from R19.61 in January 2022 to R26.74 by July 2022 — an increase of over 36% in seven months. Over the same period, the inland wholesale per-litre price of 50ppm diesel surged from R17.25 to R25.53, a jump of 48%. Had it not been for the government’s decision to temporarily reduce the general fuel levy (GFL), prices between April and July would have been even worse. From April to June, motorists paid R1.50 less on the GFL, while the discount was reduced to 75 cents for July. In the case of the latter, the inland price of unleaded 95 would have hit R27.49 had it not been for the GFL discount. The inland prices of petrol and diesel between January 2022 and December 2022 are shown in the graph below. The coastal prices, while slightly lower, followed the same trends.
OPEC raises oil production forecast for Azerbaijan -Azerbaijan's liquids supply for 2023 is forecast to rise by 59,000 barrels per day to average 0.8 million barrels per day, according to the voluntary production adjustments agreed upon at the 33rd OPEC and non-OPEC Ministerial Meeting, Azernews reports per OPEC’s Monthly Oil Market Report from December 2022. “Growth is forecast to come from the Shah Deniz and Absheron condensate projects. Production could rise further after output starts up at the Azeri Central East project in 2023,” the statement reads. Moreover, the statement notes that liquid supply in Azerbaijan is estimated to decline year-on-year by 27,000 barrels per day to an average of 0.7 million barrels per day for 2022. “This has been revised down by 21,000 barrels per day due to downward revisions in 3Q22 and lower-than-expected production in major oil fields in 4Q22. The main declines in legacy fields are expected to be offset by ramp-ups in other fields, such as the BP-led consortium’s Shah Deniz field that has increased gas production capacity in the Azeri sector of the Caspian Sea,” the statement reads. The statement also notes that Azerbaijan’s liquid production in October increased month-on-month by a minor 7,000 barrels per day to an average of 0.7 million barrels per day. “Azerbaijan's liquids production in October increased m-o-m by a minor 7 tb/d to average 0.7 mb/d, although this was down by 50 tb/d y-o-y. Crude production averaged 551 tb/d, with NGLs output at 134 tb/d, according to official sources,” the statement reads.
Kuwaiti oil projects face cash shortage: report - Kuwait’s oil sector is facing a cash shortage and this could impact the Gulf emirate’s hydrocarbon projects, a local newspaper said on Tuesday, citing official data. The Kuwait Petroleum Corporation (KPC), which manages the OPEC producer’s hydrocarbon industry, suffered from a deficit of nearly 2.925 billion Kuwaiti dinars ($9.65 billion) at the end of fiscal year 2021-2022, which ended on March 31, the Arabic language daily Alrai said. It quoted a KPC report as saying the deficit was caused by an “increase in the Corporation’s financial commitments to various government departments.” “The report said the deficit was exacerbated by a decline in revenue during 2021 as result of the spread of Coronavirus pandemic.” “Oil projects in Kuwait are facing serious challenges as a result of this financial gap, which reached in some months nearly 97.7 percent of KPC’s commitments to projects…this forced KPC to sell parts of its investments for nearly $770 million.” The paper quoted the report as saying “KPC is now taking measures to improve its financial position” in coordination with some government departments in the next few years, adding that they include slashing a cumulative debt to the government of more than two billion dinars ($6.6 billion).
Saudi crude exports hit 30-month high in October - Saudi Arabia’s crude oil exports rose for a fifth straight month in October to the highest in 30 months, data from the Joint Organisations Data Initiative (JODI) showed on Monday. Crude exports rose about 0.7% to 7.773 million barrels per day (bpd) in October - the highest since April 2020 – from 7.721 million bpd in September. The world’s largest oil exporter’s crude production, however, fell to 10.957 million bpd in October from 11.041 million bpd in the previous month. Monthly export figures are provided by Riyadh and other OPEC members to JODI, which publishes them on its website. OPEC last week said it expected to see robust global oil demand growth in 2023 with potential economic upside coming from a relaxation of China’s zero-COVID policies, which this year have pushed the country’s oil use into contraction for the first time in years. World oil demand in 2023 will rise by 2.25 million barrels per day (bpd), it had said. Earlier in the month, OPEC+ agreed to stick to its oil output targets at a meeting on Sunday as the oil markets struggle to assess the impact of a slowing Chinese economy on demand and a G7 price cap on Russian oil on supply. Saudi’s domestic crude refinery throughput decreased by 14,000 bpd to 2.679 million bpd in October, while direct crude burn fell 142,000 bpd to 380,000 bpd.
‘The world should be worried’: Saudi Aramco — the world’s largest oil producer — issued a dire warning over 'extremely low' capacity. The global oil market remains tight according to Saudi Aramco, the largest oil producer in the world. And that does not bode well for a world that still relies heavily on fossil fuels.“Today there is spare capacity that is extremely low,” Saudi Aramco CEO Amin Nasser said at a recent conference in London. “If China opens up, [the] economy starts improving or the aviation industry starts asking for more jet fuel, you will erode this spare capacity.”Nasser warns that oil prices could quickly spike — again.“When you erode that spare capacity the world should be worried. There will be no space for any hiccup — any interruption, any unforeseen events anywhere around the world.”
OPEC+ Has No Choice but to Remain Pro-Active - In the face of a wide range of uncertainties, OPEC+ has no choice but to remain pro-active and pre-emptive. That’s what Prince Abdulaziz bin Salman bin Abdulaziz Al Saud, Saudi Arabia’s Minister of Energy, said in a recent interview with the Saudi Press Agency (SPA), adding that, “this is not an easy task, especially … [as] the market has the tendency to overreact to news in both directions”. “We have seen many ill-advised interventions in energy markets,” Al Saud told SPA. “But … the fact that OPEC+ can assess markets in an objective manner, its proactive approach and the cohesion within the group put it in a better position to contribute to a more stable market,” he added. In the interview, Al Saud said, “in OPEC+ we leave politics out of our decision-making process, out of our assessments and forecasting, and we focus solely on market fundamentals”. “This enables us to assess situations in a more objective manner and with much more clarity and this in turn enhances our credibility,” Al Saud added in the SPA interview. OPEC+ held 11 meetings over the course of 2022, with the latest of those concluding on December 4. At that meeting, OPEC+ decided to hold production steady. The meeting followed a decision by the group back in October to cut overall production by two million barrels per day from its August 2022 required production levels, starting November 2022. In a statement posted on its website following the conclusion of the latest OPEC+ meeting, OPEC noted that the participating countries “reiterated their readiness to meet at any time and take immediate additional measures to address market developments and support the balance of the oil market and its stability if necessary”. On December 10, the Declaration of Cooperation between OPEC Member Countries and 10 non-OPEC oil-producing countries turned six. “The Declaration of Cooperation is an unprecedented collaborative framework of 23 oil-producing countries that is based on trust, mutual respect and dialogue,” OPEC Secretary General, HE Haitham Al Ghais, said in an organization statement earlier this month. “Six years later, the framework continues to play an instrumental role in supporting market stability, which is essential for growth and development, as well as attracting the necessary investment to ensure energy security,” he added in the statement.
BofA Reveals 2023 Oil Price Forecast – BofA Global Research’s Commodity Research team forecasts that Brent crude oil will average $100 per barrel across 2023. That’s according to a new report from the company sent to Rigzone recently, which highlighted that the team had “framed downside risks in the form of lower than expected Russian export disruption (so far seemingly unaffected) as well as on the demand side of the equation”. In a separate report sent to Rigzone on December 12, BofA Global Research said global crude oil and petroleum product prices had come down sharply in recent weeks but outlined that Brent could “bounce up quickly”. “Brent may need a Fed pivot and a successful China reopening to turn the corner, but prices could bounce up quickly above $90 per barrel if these two conditions are met, especially now that spec positioning has turned neutral,” the BofA Global Research report noted. In a report released last week, Standard Chartered highlighted that it is forecasting a Brent crude oil price of $91 per barrel in 2023. Earlier this month, the U.S. Energy Information Administration (EIA) lowered its Brent oil price forecast for 2023 in its latest short term energy outlook (STEO). The EIA now sees the Brent spot price averaging $92.36 per barrel next year, according to the STEO. In its previous STEO, which was released in November, the EIA saw the Brent spot price averaging $95.33 per barrel in 2023. Also in December, Fitch Solutions Country Risk & Industry Research revealed in a report that it sees Brent averaging $95 per barrel in 2023.. The projection was unchanged from Fitch Solutions’ previous oil price forecast report. At the time of writing, the price of Brent crude oil is trading at $79.55 per barrel. The price of the commodity has steadily dropped from a close of $123.58 per barrel on June 8.
The Era Of Cheap Oil Has Come To An End - In its latest monthly report, OPEC revealed it had yet again failed to produce as much oil as it agreed to produce the last time it discussed output. And it wasn’t by a few thousand barrels per day, either. The shortfall was some 1.8 million barrels daily, but more importantly, that sort of undershooting of its own target has become a regular thing for the cartel. Meanwhile, the United States federal government needs to buy some oil for its strategic petroleum reserve after releasing close to 200 million barrels from it this year as a way of countering fuel price inflation. Yet U.S. drillers are not in a rush to boost production. On the contrary, it seems production growth has lost its place among these companies’ top priorities. Of course, there are also the sanctions against Russia, which many expect will hurt the country’s oil production, and that may well happen, but it has not happened yet. In fact, the oil sanctions—in the form of a price cap on maritime exports and an embargo on exports to the EU—have had no effect on oil flows out of Russia. For now. Investment banks expect higher oil prices, despite a recent slump prompted by expectations of an economic slowdown pretty much across the globe. The expectations, now beginning to seep into trader circles, too, are largely based on China’s reversal of its zero-Covid policy. But they also probably take into account the fact that oil remains an indispensable commodity. And the era of cheap oil may well be over for good. “We remain constructive on oil prices driven by recovering demand (China reopening, aviation recovering) amid constrained supply due to low levels of investment, risks to Russia supply, the end of SPR releases, and slowdown of U.S. shale,” Morgan Stanley said this week in a note. Yet the situation may be a lot more serious with regard to supply, as noted in a recent market commentary by TortoiseEcoFin’s President and Portfolio Manager, Matt Sallee.“Global oil inventory is at the lowest level since 2004, the Department of Energy has released 200 million barrels of oil from the Strategic Petroleum Reserve this year, OPEC continues to struggle to produce at their stated quota and US producers are helping but can only do so much.” This s a pretty succinct description of the global oil supply situation, but the picture is not one that would invoke positive emotions. It is one that is more likely to evoke concern, and with a good reason. Because there is little evidence that any of these trends will change meaningfully any time soon.
Oil rises on hopes for China’s economy - Oil rose on Monday after falling by more than $2 a barrel in the previous session as optimism over the Chinese economy outweighed concern over a global recession. China, the world’s top crude oil importer, is experiencing its first of three expected waves of COVID-19 cases after Beijing relaxed mobility restrictions but said it plans to step up support for the economy in 2023. “There is no doubt that demand is being adversely influenced,” “However, not everything is so negative as China has vowed to fight all pessimism about its economy, and it will do what it takes to boost economic growth.” Brent crude gained 65 cents, or 0.8%, to $79.69 a barrel by 1248 GMT while U.S. West Texas Intermediate crude rose 85 cents, or 1.1%, to $75.14. Oil surged towards its record high of $147 a barrel earlier in the year after Russia invaded Ukraine in February. It has since unwound most of this year’s gains as supply concerns were edged out by recession fears, which remain a drag on prices. The U.S. Federal Reserve and European Central Bank raised interest rates last week and promised more. The Bank of Japan, meanwhile, could shift its ultra-dovish stance when it meets on Monday and Tuesday. “The prospect of further rate rises will hit economic growth in the new year and in doing so curb demand for oil,” Oil was supported by the U.S. Energy Department saying on Friday that it will begin repurchasing crude for the Strategic Petroleum Reserve - the first purchases since releasing a record 180 million barrels from the reserve this year.
Oil Rises after Wavering in Weak Trading Session - Oil tipped higher as investors weighed a pledge from China to revive consumption against broader low-risk sentiment. West Texas Intermediate settled above $75 a barrel, ending the day higher for the first time in three sessions, after flip-flopping in a narrow range on Monday. Market participants saw Chinese President Xi Jinping’s pledge to focus on the economy as supporting energy demand— even as Covid cases surge and the economic reopening of the country gets bumpy. Meanwhile, markets shied away from risky assets as the outlook for global growth has dimmed in the face of more expected interest-rate hikes. Crude markets are more susceptible to tracking broader markets as liquidity in the commodity declines before the holidays. It’s another day of “fragile trading” where markets are bid following headlines from China reopening, said Rebecca Babin, a senior energy trader at CIBC Private Wealth Management. “At the end of the day, conviction to buy the dip is still quite low.” Oil is still headed for a second monthly loss as concerns about recessions in the US and Europe mount, with central banks continuing to tighten policy. In addition, Russian flows have so far proven resilient as a price cap imposed by the Group of Seven and European Union hasn’t led to major disruptions. Among major buyers, India said it doesn’t expect problems. WTI for January delivery, which expires Tuesday, rose 90c to $75.19 a barrel at settlement. Brent for February settlement gained 76c to $79.80 a barrel. In the US, authorities are moving to replenish the Strategic Petroleum Reserve, starting with a 3-million barrel, fixed-price purchase, the Department of Energy said on Friday. The announcement caps a year that saw President Joe Biden order an unprecedented release from the SPR to help curb soaring domestic energy costs, which spiked after Russia’s invasion of Ukraine.
Crude oil price rises as US seeks to restock Strategic Petroleum Reserve - Oil prices rose in early trade on Tuesday, shored up by a weaker dollar and a U.S. plan to restock its Strategic Petroleum Reserve, but gains were limited by uncertainty over the impact of rising COVID-19 cases in China, the world’s top oil importer. Brent crude futures advanced 61 cents, or 0.8%, to $80.40 a barrel at 0124 GMT, adding to a 76 cent gain in the previous session. U.S. West Texas Intermediate (WTI) crude futures rose 65 cents, or 0.9%, to $75.84 barrel, after climbing 90 cents in the previous session. The market has been supported by the U.S. plan announced last week to buy up to 3 million barrels of oil for the Strategic Petroleum Reserve following this year’s record release of 180 million barrels from the stockpile. A weaker U.S. dollar has also buoyed prices, with the dollar index around 104.7, as it makes oil cheaper for those holding other currencies. Crude demand expected to increase; go long after price breaches Rs 6,500/bbl However for prices to climb further, analysts said there would need to be clear signs of growing demand.”The oil demand outlook will be key for how high crude prices can go and that might struggle for clarity as we see mixed signals with China’s reopening,” China on Tuesday reported a jump in new confirmed coronavirus cases to 2,722 on Dec. 19, up from 1,995 a day earlier. There are, however, mounting doubts over whether the official count is capturing the real number of infections with anecdotal evidence suggesting the disease is ripping through cities. And in another bearish sign, China’s business confidence fell to its lowest since Jan. 2013, reflecting the impact of a surge in COVID-19 cases on economic activity after the country eased pandemic control measures, a survey by World Economics showed on Monday.
Oil prices pare gains on worries U.S. winter storm could cut travel - Oil prices ended higher on Tuesday in a volatile session as a worsening outlook for a major U.S. winter storm sparked fears that millions of Americans might curb travel plans during the holiday season. Brent crude futures settled up 19 cents, or 0.2%, to $79.99 per barrel while U.S. West Texas Intermediate (WTI) crude futures settled up 90 cents at $76.09 per barrel. Oil prices were buoyed by a softer dollar and a U.S. plan to restock petroleum reserves, but gains were capped by uncertainty over the impact of rising Covid-19 cases China. A weaker dollar has also supported prices, making oil cheaper for those holding other currencies. The Midwest and Great Lakes region could see a major blizzard beginning Thursday, while cold air moving east could bring a flash freeze caused a rapid temperature drop across the country, according to the National Weather Service. Heating oil futures have fallen more than 4% since the start of the week to $3.03 per gallon on Tuesday. The storm could majorly affect travel this holiday season. Prices also fell on news that TC Energy Corp submitted its plan to restart the Keystone pipeline to U.S. regulators, a source familiar with the matter said, nearly two weeks after the 622,000 barrel-per-day (bpd) pipeline ruptured in the worst oil spill in the United States in nine years. While China has been relaxing pandemic restrictions, a surge in Covid-19 cases hurt the fuel demand outlook and fed uncertainty about the country’s economic recovery. Cities across China have been racing to add hospital beds and build fever-screening clinics as international concern mounted that Beijing’s decision to dismantle its stringent “zero-COVID” regime could result in deaths and virus mutations. Washington plans to buy up to 3 million barrels of oil for the Strategic Petroleum Reserve after this year’s record release of 180 million barrels.
US benchmark crude-oil contract for February delivery finishes 1.1% higher - The most-active US benchmark crude-oil contract for February delivery finished 1.1% higher at $76.23 a barrel, helped by a weaker dollar that made overseas purchases of dollar-denominated crude more attractive to foreign buyers. China’s cloudy demand outlook limited gains as the number of COVID cases surges. Holiday volume limited the session’s trading range. Oil prices were also supported this week by the U.S. plan to buy up to 3 million barrels of oil for the Strategic Petroleum Reserve after this year’s record release of 180 million barrels. WTI for January delivery gained 90 cents per barrel, or 1.20% to $76.09 while Brent Crude for February delivery gained 19 cents per barrel, or 0.24% to $79.99. RBOB Gasoline for January delivery gained 4.52 cents per gallon, or 2.08% to $2.2228. ULSD for January delivery gained 0.54 cent per gallon, or 0.18% to $3.0589. In the near term, oil futures will be underpinned by a drop in Russian oil output to about 1 million barrels per day by the end of March after full implementation of EU sanctions, while Chinese demand is expected to drop due to the rise in the number of COVID cases. The $1.66 trillion government funding bill that U.S. lawmakers are trying to pass cancels “certain” congressionally-mandated sales of oil from the SPR. Congress mandated in previous laws a sale of about 26 million barrels of oil in fiscal 2023 and about 147 million barrels of oil from fiscal 2024 to fiscal 2027. The Biden administration is beginning to buy back oil for the reserve after a record 180 million barrel sale to counter high oil prices. Saudi Energy Minister, Prince Abdulaziz bin Salman said OPEC+ members leave politics out of the decision making process and out of their assessments and forecasting. The minister added that the OPEC+ decision to cut output turned out to be the right one for supporting the stability of the market and the industry. According to Refinitiv analysis, diesel imports into Europe continue at a “relentless pace” following a blast of cold weather. Europe is set to import 2 million tons of diesel this week, slightly down from 2.03 million tons last week of which 380,000 tons has yet to finish discharging. Barclays said a full China re-opening could increase global oil demand by 1-2 million bpd but that could be partly offset by spillover from weakening in advanced economies. It said the recovery could be bumpy and may take weeks if not months to play out. It forecast Russian output falling by 1 million bpd by the end of the first quarter of 2023 with the full implementation of European Union sanctions. TC Energy Corp submitted a restart plan for its Keystone Pipeline to U.S. safety regulator Pipeline and Hazardous Materials Safety Administration which is being reviewed. It later stated that it was delaying the restart of the pipeline until at least December 28th-29th.
WTI Extends Gains After API Reports Surprise Crude Draw -Oil prices rose modestly on a low volume, low liquidity day helped by the tumble in the dollar that The BoJ enabled. Ongoing hopes for China demand (post Zero-COVID policies) helped prices and continued supply disruptions in the US are also supporting oil. TC Energy pushed back its targeted restart for the Keystone pipeline by a week and is now aiming for December 28 or 29. API:
- Crude -3.069mm (-167k exp)
- Cushing +840k
- Gasoline +4.510mm
- Distillates +830k
After last week's huge crude build (and builds across the board), all eyes are on this week's data for any signs that it was a one-off, or that a sudden demand drop has hit the US economy. API reported a 3.069mm barrel Crude draw (bigger than the expected small draw) but builds at Cushing and in products...
Dan Yergin says oil prices could hit $121 a barrel when China fully reopens - Dan Yergin expects oil at $90 in 2023 but says there’s a chance it could go as high as $121 when China fully reopens, but warned there are three major uncertainties looming over the market. “Our base case for 2023 is $90 for Brent but you have to look at other cases,” the S&P Global vice chairman said, adding there are three major uncertainties: the Federal Reserve’s decisions, China demand and Moscow’s reaction to the price caps. That could be “one big boost” and push prices to $121 a barrel, building on strains caused by underinvestment in oil and gas, Yergin said. That would be near highs set in March after Russia invaded Ukraine. On the flipside, Yergin said prices could fall to around $70 per barrel in a recession. In the past three weeks, local and central government authorities in China loosened several strict Covid measures that had required people to stay home and businesses to operate mostly remotely.Oil demand from the world’s top importer could reach 15.7 million barrels per day in 2023, which is around 700,000 barrels higher than 2022, S&P said in its most recent forecast.Other considerations include Russian President Vladimir Putin’s response to the price caps imposed by the European Union, as well as further rate hikes undertaken by the Fed.EU energy ministers on Monday agreed to cap natural gas prices at 180 euros per megawatt hour, but the European Commission cautioned that the measure could be suspended if the “risks outweigh the benefits.” The decision came on the heels of an oil price cap of $60 per barrel at the start of December. Yergin said he thinks the recently imposed gas price cap “probably will work. He said it also acts as an anticipation of higher gas prices in subsequent winters due to a lack of Russian gas and competing demand between Europe and Asia for LNG. In Asia’s Wednesday morning trade, Brent crude futures added 0.40% to $80.31 a barrel, while U.S. marker West Texas Intermediate futures traded up 0.33% at $76.48 per barrel.
WTI Extends Gains After Bigger Than Expected Crude Draw; SPR Hits 1983 Lows. | ZeroHedge - Oil prices are higher for a third straight day ahead of this morning's official inventory data (following API's reported crude draw). Trading volumes remain dismally low. DOE:
- Crude -5.895mm (-2.1mm exp)
- Cushing +853k
- Gasoline +2.53mm
- Distillates -242k
After last week's huge crude build, analysts expected a small draw this week (confirmed by API) but the official data showed a considerable crude drawdown of 5.895mm barrels. Inventories at Cushing rose 853k (2nd straight week) while Gasoline stocks rose for the 6th week in a row (distillates inventories drew down a small 242k barrels) While the increase in refined-product stockpiles has muted fears of shortages on the East Coast this winter, it was mainly due to a decline in consumption, possibly a sign of slowing economic activity, which may ultimately pressure crack spreads further. Exports have been a critical component in lessening the pace of inventory additions, but as Bloomberg notes, may drop if a recession hits Latin America. The SPR saw a 3.647mm barrel drain last week (so total Crude inventory draw was 9.5mm barrels), which pushed the SPR down to its lowest level since Dec 1983...
NYMEX Oil Futures Add to Gains on Large Crude Drawdown - New York Mercantile Exchange oil futures held higher post-inventory trade Wednesday after federal data from the Energy Information Administration showed U.S. commercial crude oil inventories declined by a larger-than-expected margin despite refineries cutting run rates for the third consecutive week through Dec. 16. Further supporting the oil complex, demand for gasoline rebounded from a five-month low 8.255 million barrels per day (bpd) last week, indicating stronger driving demand ahead of the holiday travel season that officially begins on Friday, Dec. 23. In the reviewed week, gasoline supplied to the U.S. market, a measure of demand, grew 459,000 bpd to 8.714 million bpd. Gasoline stockpiles still built by 2.5 million barrels (bbl) to 226.1 million bpd compared with expectations for inventory to have increased by 1.3 million bbl. Distillate fuel inventories dipped by 242,000 bbl to 119.9 million bbl and are now 7% below the five-year average. Analysts had expected distillates inventories would stay unchanged from the previous week. Demand for middle-of-the-barrel fuel also recovered to above 4 million bpd, up 247,000 bpd from the previous week. In the crude complex, commercial oil stockpiles fell by a massive 5.9 million bbl to 418.2 million bbl, and are now about 7% below the five-year average, the EIA report showed. Analysts had mostly expected crude stockpiles would fall by just 300,000 bbl in the reviewed week. The supersized draw was realized despite another relatively large 3.6-million-bbl transfer of crude oil last week from the Strategic Petroleum Reserve to the commercial side, extending a yearlong effort by the U.S. government to stabilize oil markets. Oil stored at Cushing, Oklahoma, hub, the delivery point for NYMEX West Texas Intermediate futures, increased 853,000 bbl from the previous week to 25.2 million bbl, the EIA said in its weekly report. U.S. crude oil production remained unchanged from the previous week at 12.1 million bpd, according to the EIA. The refining utilization rate, meanwhile, dropped 1.3% from the previous week to 90.9% of capacity in contrast to expectations with a 0.2% increase. That follows a decline in refinery run rates for each week so far this month. Refiners processed 16 million bpd of crude during the week-ended Dec. 16, 150,000 bpd less than the previous week's average. Near 11:30 a.m. EST, February WTI futures were up $1.57 to $77.81 per bbl, with January ULSD futures gaining than 6 cents to $3.1262 per gallon. January RBOB futures advanced 2.42 cents to $2.2470 per gallon.
Oil prices rose by more than $2 a barrel on Wednesday - Oil prices rose by more than $2 a barrel on Wednesday after data showed a larger-than-expected draw in U.S. crude stockpiles, but gains were capped by a snowstorm that is expected to hit U.S. travel. Prices were also boosted by hopes that China would relax some COVID-19 curbs after no new COVID-19 deaths were reported. China's crude oil imports from Russia in November rose 17% year on year as Chinese refiners rushed to secure more cargoes ahead of a price cap imposed by the Group of Seven nations and an EU embargo from Dec. 5. Markets also awaited clarity on when the Keystone pipeline, a major artery ferrying Canadian crude to the United States, would restart after TC Energy said it had removed the ruptured segment of the pipeline that caused an oil spill earlier this month and sent it for metallurgical testing as directed by U.S. regulators. WTI for February (new front month) delivery gained $2.06 per barrel, or 2.70% to $78.29, while Brent Crude for February delivery gained $2.21 per barrel, or 2.76% to $82.20. RBOB Gasoline for January delivery gained 3.30 cents per gallon, or 1.48% to $2.2558, ULSD for January delivery gained 8.06 cents per gallon, or 2.63% to $3.1395. Traders remain focused on a winter storm stretching across the U.S; which is expected to bring heavy snow and curtail holiday travel season. Flight delays, cancellations and impassable roads during one of the busiest travel periods of the year could drive down fuel demand. The EIA reported that U.S. crude oil in the SPR fell by 3.6 million barrels in the week ending December 16th to 378.6 million barrels, its lowest since December 1983. TC Energy said that it had safely removed the ruptured segment of Keystone pipeline that caused an oil spill earlier this month and sent it for metallurgical testing as directed by U.S. regulators. Even though a cleanup will take weeks or months, the line can still restart once it is repaired and the plan approved by the regulator. IIR Energy reported that U.S. oil refiners are expected to shut in about 282,000 bpd of capacity in the week ending December 23rd, increasing available refining capacity by 316,000 bpd. Offline capacity is expected to fall to 73,000 bpd in the week ending December 30th. ,Platts is reporting that the recent blizzard that left more than a foot of snow in some parts of North Dakota has impacted crude oil production by shutting in some 300,000 b/d and 400,000 b/d, according to state officials. With below zero temperatures expected across the state and expected reduced staffing over the Christmas holiday period, officials do not expect to see a major bounce back in production to normal levels of 1 million b/d until after the New Year.
Crude oil prices rally on tight US stocks as winter blast hits - Oil prices rose for a fourth straight day on Thursday with U.S. crude, heating oil and jet fuel stocks seen tight just as a chilly blast hits the United States and travel is set to soar for the holiday season. U.S. West Texas Intermediate (WTI) crude futures climbed 35 cents, or 0.5%, to $78.64 a barrel, while Brent crude futures gained 27 cents, or 0.3%, to $82.47 at 0145 GMT, extending gains of around 2.7% in the previous session. Both benchmark contracts jumped on Wednesday after government data showed U.S. crude inventories fell by much more than analysts had expected, posting a drop of 5.89 million barrels for the week ending Dec. 16. At the same time there was a decline in distillate stocks, which include heating oil and jet fuel, which defied expectations for a build. The falling stockpiles come as demand for heating oil is set to soar with a powerful winter storm hitting the United States, expected to bring sub-zero wind chills as far south as Texas and record-breaking lows to Florida and the eastern states. Jet fuel consumption is also expected to pick up with a post-COVID boom in travel for the end-of-year holiday season. “On our numbers…the crude market is finely balanced,” said National Australia Bank’s head of commodity research Baden Moore. “As we look into 2023, we see China’s re-opening and a likely continued steady roll-up in global jet demand (towards 2019 levels) will tighten global crude markets and drive prices higher,” he said. A softer U.S. dollar has also buoyed oil prices, as crude becomes cheaper for buyers holding other currencies.
Oil Futures Follow Equities Lower as USD Regains Momentum -- Reversing earlier gains, West Texas Intermediate futures on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange settled Thursday's session lower amid risk-off sentiment in broader markets as equities on Wall Street accelerated a selloff and the U.S. dollar regained momentum into afternoon trading. Thursday's lower settlements follow a two-session rally for the crude complex as traders positioned for this winter's first arctic storm that is pushing through the Great Plains and upper Midwest to northern New England states and reaching as far south as Texas. The cold snap is set to disrupt some holiday travel, with as many as 1,700 flights canceled by midmorning Thursday and another 2,500 having been delayed, according to tracking site FlightAware. Several airlines issued fee waivers for those looking to rebook flights later this weekend. The arctic blast is delivering bone-chilling temperatures to large swaths of the country, while demand for heating oil in the Northeast is set to surge, with 83% of the country's space heating demand satisfied with heating oil drawn by households in New England states. The Energy Information Administration reports the region's distillate fuel stocks at 4.277 million barrels (bbl) on Dec. 16, 2.6 million bbl or 37.5% below the comparable year-ago period. DTN meteorologists forecast that a complete flip of the weather pattern will occur next week as above-normal temperatures will take hold across Central and Eastern U.S. In financial markets, U.S. equities plummeted on Thursday and the dollar index reversed higher, sending Dow Jones Industrials down as much as 600 points. DJIA was about 350 points lower in late session trade, and S&P 500 was down 1.4%. The Labor Department on Thursday reported initial jobless claims rose to 216,000 last week but were still below estimates for a rise to 225,000. At settlement, U.S. dollar rallied 0.27% against a basket of foreign currencies to settle at 104.127, weighing on front-month WTI futures. The February WTI contract fell $0.80 to $77.49 per bbl at settlement, and the international crude benchmark Brent contract for February delivery declined $1.22 to $80.98 per bbl. NYMEX January ULSD futures settled down $0.0081 at $3.1314 per gallon, and front-month RBOB futures slipped $0.0070 to $2.2488 per gallon.
Russia threatens to slash oil supplies in 2023, spooks markets-- Russia may cut oil output by 5-7 percent in early 2023 and halt sales to countries supporting a price cap on its crude and oil products, a senior official has said. Deputy Prime Minister Alexander Novak told state television on Friday that the cuts could amount to 500,000-700,000 barrels per day. His remarks marked the first in-detail Russian response to the recent price caps rolled out on Russian energy exports by Ukraine’s Western allies over Moscow’s invasion of its neighbour. The European Union, G7 countries and Australia introduced a $60 per barrel price ceiling on Russian oil from December 5 on top of the EU’s embargo on imports of Russian crude by sea and similar pledges by the United States, Canada, Japan and the United Kingdom. The EU has also introduced restrictions on gas prices. These moves are aimed at restricting Russia’s revenue streams while making sure much-needed energy exports do not come to a standstill. Novak, however, said Moscow would ban sales of oil and oil products to countries that join the price cap and companies that demand its observance. Such a step would force those nations to source their oil from other countries. But if Moscow simultaneously cuts oil production, as Novak threatened, it would reduce the total volume of crude available in the market, pushing up prices of non-Russian oil, bringing pain to consumers globally — and potentially giving the Kremlin leverage against the West. “We believe that in the current situation, it is even possible to take risks of lower production rather than be guided by the selling policy regarding the price caps. Today it is $60, tomorrow it can be anything, and getting dependent on some decisions made by unfriendly countries is unacceptable for us,” Novak said. The threatened cutbacks sparked a rise in global oil prices of more than $1 fuelled by expectations of a drop in crude supply. Brent crude was up by 73 cents, or 0.9 percent, to $81.71 a barrel by 07:15 GMT, while US West Texas Intermediate (WTI) crude was at $78.40 a barrel, up 91 cents, or 1.2 percent higher. They hit highs of $82.17 and $78.77, respectively, earlier in the session. Both contracts were on track to post a second weekly gain, with Brent up 3.3 percent and WTI up 5.5 percent. “Crude prices are higher as energy traders focus on Moscow’s response to the price cap put on Russian oil,” Russian President Vladimir Putin said on Thursday that he would issue a decree early next week detailing Moscow’s actions in response to the price cap. Novak said Russia’s share of the global oil export market was currently 22 percent and that its share of the global gas export market was 20 percent, underscoring global dependence on Russian energy. He added that despite Europe’s efforts to cut reliance on Russian oil and gas, energy exports from Russia are in demand worldwide and Moscow has been diversifying its buyers.
Oil rises $3/bbl after Russia signals output cut due to price cap (Reuters) - Oil prices settled about $3 per barrel higher on Friday for a second straight week of gains after Moscow said it could cut crude output in response to the G7 price cap on Russian exports.Brent crude settled at $83.92, up by $2.94 or 3.6%, while U.S. West Texas Intermediate (WTI) crude settled at $79.56 a barrel, up $2.07, or 2.7%. Both benchmarks recorded their biggest weekly gains since October. Russia may cut oil output by 5% to 7% in early 2023 as it responds to price caps, the RIA news agency cited Deputy Prime Minister Alexander Novak as saying on Friday.Russia's Baltic oil exports could fall by 20% in December from the previous month after the European Union and G7 nations imposed sanctions and a price cap on Russian crude from Dec. 5, according to traders and Reuters calculations."The potential cut from Russia could be giving the bulls more fuel," said Eli Tesfaye, senior market strategist at RJO Futures. "If global demand continues at current pace, that cut could have a significant impact and we may stay in the $80s range." Both crude oil demand and output could slump over the next few days due to shut-ins from a massive winter storm that cascaded across a broad swath of the United States. Several of the largest U.S. refineries shut down due to the extreme cold while output shut in Texas and North Dakota.U.S. gasoline and ultra-low-sulfur diesel futures both rose more than 5% on anticipated refining production cuts and a surge in heating oil demand. Swiss bank UBS expects prices could move back above $100 per barrel next year on Russian output cuts and easing of COVID-related restrictions in China, analyst Giovanni Staunovo said."The road for higher prices will however stay bumpy," he said.
Israeli practices in Palestine rejected, to be peacefully resisted: Palestinian president (Xinhua) -- Palestinian President Mahmoud Abbas said Friday that the Israeli practices in Palestine are rejected and will be confronted with peaceful popular resistance. In a Christmas message published by the official Palestinian News Agency, Abbas called on the international community "to break its silence and take concrete measures to stop Israeli crimes, including colonial-settlement expansion and ongoing annexation, the consolidation of a racist apartheid regime, attempts at changing the identity and the character of the city of Jerusalem." "The only way for all the peoples of the region to enjoy security, stability, prosperity and good neighborliness is for the Palestinian people to obtain their legitimate rights, which were approved by the UN resolutions," said Abbas. "The Palestinians are looking to end the Israeli occupation and establish their independent Palestinian state with East Jerusalem as its capital and the return of refugees," he added. Christmas celebrations in Palestine, titled "the spirit of Christmas brings us together in the Palestinian territories," come amid escalating tensions between the Palestinians and the Israeli army in the West Bank.
Israeli Shelling in Damascus Area: Syrian State Media - Israeli shelling overnight targeted the Damascus area, Syrian state media said Tuesday, adding that air defenses had intercepted some of the missiles. The Syria official news agency SANA reported “explosions in the vicinity of Damascus.” The Syrian Observatory for Human Rights war monitor said the strikes hit Hezbollah weapons depots, killing two people. A Syrian military source, quoted by SANA, said Israel carried out “a burst of missiles” at around 12:30 am Tuesday (2130 GMT Monday) “targeting some points in the vicinity of Damascus city. Our air defenses intercepted the aggressor’s missiles and shot down a number of them.” “The aggression resulted in the injury of two soldiers with some material losses,” the source said. Israel rarely comments on such reports, but it has carried out hundreds of air strikes on Syrian territory since civil war broke out there in 2011, targeting government positions as well as allied Iran-backed forces and Hezbollah fighters. Israel has repeatedly said it will not allow its archfoe Iran to gain a foothold in Syria.
Israel 'kicks out' Ukrainian refugees, ends free housing; Tel Aviv's bid to appease Putin? - (news video) Israeli authorities told Ukrainians to evict state-sponsored housing, a report has said. Israel's N12 reported that some 100 Ukrainians who had fled Russian war have been told to vacate the housing. The refugees had been informed about the decision last week, N12 reported. Watch the video for more.
UAE supports Ukraine with household electricity generators to cope with harsh winter - The UAE announced on Saturday, the dispatch of about 2,500 electric generators to support civilians affected as a result of the ongoing crisis in Ukraine, which led to the impact of energy infrastructure and the occurrence of power outages. The move will help them cope with the harsh winter conditions. The aid includes 2,500 home electric generators, the power of each generator ranges from 3.5 kilowatts to 8 kilowatts, as these generators will contribute to providing energy for civilian homes, which will help alleviate the difficulties faced by the families affected by the crisis. Reem Bint Ibrahim Al Hashemi, Minister of State for International Cooperation, said that this aid to Ukraine stems from the UAE's belief in the importance of human solidarity, especially in conflict situations, and is part of the country's continuous efforts to mitigate the humanitarian repercussions of the Ukrainian crisis. The UAE will transport about 1,200 electric generators to the Polish capital, Warsaw, on Saturday, and will transfer the rest of the generators in January. This support comes within the humanitarian relief aid allocated by the UAE to civilians affected by the crisis in Ukraine, at a value of $100 million. It should be noted that the UAE has taken the initiative since the beginning of the crisis to alleviate the suffering of those affected by it, as it has already flown about 8 planes carrying 360 tonnes of food and medical aid and ambulances for Ukrainian refugees in Poland, Moldova and Bulgaria, in response to the United Nations urgent appeal and the regional response plan for refugees from Ukraine.