oil prices ended lower for the first time in three weeks on rising inventories and disappointment in Europe's proposals to restrict Russian fuel exports….after rising 1.9% to a two month high of $81.64 a barrel last week, the contract price for the benchmark US light sweet crude for March delivery moved higher in thin Asian holiday trading on Monday, on hopes that a Chinese demand recovery would follow their recent easing of travel restrictions. but faltered in afternoon US trading to settle 2 cents lower at $81.64 a barrel, selling off after news of a big build in oil inventories at Cushing, Oklahoma, the delivery point for the benchmark US crude contract…oil prices rose again in early Asian trade on Tuesday as traders focused on prospects of demand recovery from top importer China, and on the global economic outlook, but tumbled again in New York trading after S&P Global reported that U.S. business activity contracted in January for the seventh consecutive month, and the Conference Board's Leading Economic Index fell by 1% in December and by 4.2% over six months, and settled $1.49 lower at $80.13 a barrel on concerns about a global economic slowdown and on preliminary indications of a bigger than expected build in U.S. oil inventories…..oil prices held those losses in overnight trading after the American Petroleum Institute reported the largest Cushing depot build since April 2020 and a larger than expected increase in overall crude supplies, but turned mixed in late morning trade on Wednesday after the EIA reported commercial crude and gasoline inventories increased while demand for middle distillates fell back and closed flat at $80.15 a barrel as unplanned refinery outages left commercial crude stockpiles at 16-month highs....however, oil prices rose more than 1% early Thursday after several economic reports came in stronger than expected and settled 86 cents higher at $81.01 a barrel, as the solid growth momentum evident in the data raised hopes that inflation would ease without a recession...oil prices rose again in Asian trading on Friday on demand optimism after better-than-expected economic data in the United States and hopes that the Chinese economy would recover from the impact of Covid, but turned lower in afternoon trade in reaction to reports the G7 coalition was considering a price cap of $100 bbl. for Russian diesel exports -- a level that would allow Russia to continue fuel shipments to the global market with minimum interruptions, and settled $1.33 lower at $79.68 a barrel, as uncertainty increased ahead of next week's OPEC+ committee meeting and the European Union ban on Russia oil products and left oil prices down 2.4% for the week, as indications of continued strong Russian oil supply offset better-than-expected U.S. economic growth data, strong middle distillate refining margins, and hopes of a rapid recovery in Chinese demand.
Meanwhile, US natural gas prices finished lower for the eighth week in nine, as winter gas supplies rose above normal and traders bet against a prospective Freeport export restart…. after falling 7.2% to a 19 month low of $3.174 per mmBTU last week on indications of a further delay in the resumption of LNG exports from Freeport Texas, the contract price of US natural gas for February delivery opened 35 cents higher on Monday after the latest forecasts showed a frigid end to January and possibly into early February, and settled 27.3 cents, or 8.6% higher at $3.447 per mmBTU following Freeport LNG's request to begin the restart process on their LNG plant in Texas...however, natural gas prices reversed and dropped about 6% early Tuesday on uncertainty about when Freeport LNG's plant would restart, and on forecasts for milder weather over the next two weeks than previously forecast, and settled 18.9 cents lower at $3.258 per mmBTU...Wednesday’s trading was more of the same, as natural gas prices fell 19.1 cents to a new 19 month low at $3.067 per mmBTU, as updated forecasts moderated the temperature outlook heading into the second week of February….natural gas prices then fell below $3 for the first time in 20 months on Thursday, as weak weather, strong production and another anemic storage report sent prices down a third consecutive day.…February gas prices jumped ahead of the contract expiration on Friday, with the now thinly traded February contract settling up 16.5 cents to $3.109 per mmBTU on the day but still down 2.0% for the week, while the more active contract of US natural gas for March delivery, which will be quoted as the price of gas next week, settled just a penny higher at $2.849 per mmBTU, and was down 6.2% on the week…
The EIA's natural gas storage report for the week ending January 20th indicated that the amount of working natural gas held in underground storage in the US fell by 91 billion cubic feet to 2,729 billion cubic feet by the end of the week, which left our gas supplies 107 billion cubic feet, or 4.1% above the 2,622 billion cubic feet that were in storage on January 20th of last year, and 128 billion cubic feet, or 4.6% more than the five-year average of 2,601 billion cubic feet of natural gas that were in storage as of the 20th of January over the most recent five years….the 91 billion cubic foot withdrawal from US natural gas working storage for the cited week was more than was expected by a Reuters survey of analysts, whose average forecast called for a 82 billion cubic feet withdrawal of gas, but it was less than half of the 217 billion cubic feet that were pulled out of natural gas storage during the corresponding week of 2022, and also less than half of the average 185 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 January 20th indicated that even after a big decrease in our oil imports and a jump in our oil exports, we still had a small surplus oil left to add to our stored commercial crude supplies for the 5th consecutive weekly increase, and for the 24th time in the past 40 weeks, essentially due to a big increase in oil supplies that could not be accounted for... Our imports of crude oil fell by an average of 956,000 barrels per day to average 5,905,000 barrels per day, after rising by an average of 511,000 barrels per day during the prior week, while our exports of crude oil rose by 835,000 barrels per day to average 4,707,000 barrels per day, which combined meant that the net of our trade in oil worked out to a net import average of 1,198,000 barrels of oil per day during the week ending January 20th, 1,791,000 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 12,200,000 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 13,398,000 barrels per day during the January 20th reporting week…
Meanwhile, US oil refineries reported they were processing an average of 14,981,000 barrels of crude per day during the week ending January 20th, an average of 127,000 more barrels per day than the amount of oil that our refineries processed during the prior week, while over the same period the EIA’s surveys indicated that an average of 76,000 barrels of oil per day were being added to 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 January 20th appears to indicate that our total working supply of oil from net imports and from oilfield production was 1,659,000 barrels per day less than what was added to storage plus our oil refineries reported they used during the week. To account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a [+1,659,000] 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 an omission or error of that magnitude in this week’s oil supply & demand figures that we have just transcribed.... Furthermore, since last week’s “unaccounted for crude oil” was at [+866,000] barrels per day, that means there was a 793,000 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 useless....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)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,207,000 barrels per day last week, which was 0.4% less than the 6,233,000 barrel per day average that we were importing over the same four-week period last year. This week's 76,000 barrel per day increase in our overall crude oil inventories was all added to our commercially available stocks of crude oil, while the amount of oil in our Strategic Petroleum Reserve remained unchanged.. This week’s crude oil production was reported to be unchanged at 12,200,000 barrels per day because the EIA's rounded estimate of the output from wells in the lower 48 states was unchanged at 11,700,000 barrels per day, while Alaska’s oil production was 3,000 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 6.8% below that of our pre-pandemic production peak, but was 25.8% 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 86.1% of their capacity while using those 14,981,000 barrels of crude per day during the week ending January 20th, up from their 85.3% utilization rate during the prior week, but still below normal utilization for mid January. The 14,981000 barrels per day of oil that were refined this week were 3.3% less than the 15,497,000 barrels of crude that were being processed daily during week ending January 21st of 2022, and 11.1% less than the 16,857,000 barrels that were being refined during the prepandemic week ending January 17h, 2020, when our refinery utilization was at a close to normal 90.5% for mid-January ...
Even with the increase in the amount of oil being refined this week, gasoline output from our refineries was a bit lower, decreasing by 34,000 barrels per day to 8,831,000 barrels per day during the week ending January 20th, after our gasoline output had increased by 332,000 barrels per day during the prior week. This week’s gasoline production was also 1.0% less than the 8,917,000 barrels of gasoline that were being produced daily over the same week of last year, and 7.4% less than the gasoline production of 9,535,000 barrels per day during the prepandemic week ending January 17th, 2020. Similarly, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 9,000 barrels per day to 4,592,000 barrels per day, after our distillates output had increased by 57,000 barrels per day during the prior week. With that, our distillates output was 3.4% less than the 4,756,000 barrels of distillates that were being produced daily during the week ending January 21st of 2022, and 7.3% less than the 4,954,000 barrels of distillates that were being produced daily during the week ending January 17th 2020...
With the recent increases in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the 9th time in eleven weeks and for the 12th time in 24 weeks, increasing by 1,763,000 barrels to 232,022,000 barrels during the week ending January 20th, after our gasoline inventories had increased by 3,483,000 barrels during the prior week. Our gasoline supplies rose by less this week because the amount of gasoline supplied to US users rose by 88,000 barrels per day to 8,142,000 barrels per day, and because our imports of gasoline fell by 103,000 barrels per day to 453,000 barrels per day, while our exports of gasoline fell by 41,000 barrels per day to 893,000 barrels per day.. But even after 9 recent gasoline inventory increases, our gasoline supplies were still 6.4% below last January 21st's gasoline inventories of 247,918,000 barrels, and about 8% below the five year average of our gasoline supplies for this time of the year…
With our recently depressed level of distillates production, our supplies of distillate fuels decreased for the 5th time in 6 weeks, and for the 28th time over the past year, falling by 507,000 barrels to 115,270,000 barrels during the week ending January 20th, after our distillates supplies had decreased by 1,939,000 barrels during the prior week. Our distillates supplies fell by less this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, decreased by 146,000 barrels per day to 3,878,000 barrels per day, and because our imports of distillates rose by 172,000 barrels per day to 320,000 barrels per day, while our exports of distillates rose by 104,000 barrels per day to 1,106,000 barrels per day... After a run of fifty-six inventory withdrawals over the past ninety weeks, our distillate supplies at the end of the week were were 7.9% below the 125,154,000 barrels of distillates that we had in storage on January 21st of 2022, and about 20% below the five year average of distillates inventories for this time of the year...
Meanwhile, with a big increase in oil supplies that could not be accounted for, our commercial supplies of crude oil in storage rose for the 12th time in 24 weeks and for the 22nd time in the past year, increasing by 533,000 barrels over the week, from 448,015,000 barrels on January 13th to 448,548,000 barrels on January 20th, after our commercial crude supplies had increased by 8,408,000 barrels over the prior week. After recent big oil supply increases following the Christmas refinery freeze offs, our commercial crude oil inventories were at a 19 month high, about 3% above the most recent five-year average of commercial oil supplies for this time of year, and were 40.8% above the average of our available crude oil stocks as of the third weekend of January 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 even 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 January 13th were 7.8% more than the 416,190,000 barrels of oil we had in commercial storage on January 21st of 2022, but 5.9% less than the 476,653,000 barrels of oil that we had in storage during the 2nd Covid surge on January 22nd of 2021, while 4.8% more than the 428,106,000 barrels of oil we had in commercial storage on January 17th of 2020…
Finally, with our inventories of crude oil and our supplies of all products made from oil trending 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 for a sense of the big picture.. After the commercial crude and gasoline inventory increases 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, rose by 3,989,000 barrels this week barrels this week, from 1,601,607,000 barrels on January 13th to 1,605,596,000 barrels on January 20th, after our total inventories had increased by 2,378,000 barrels during the prior week. Even after those increases, our total petroleum liquids inventories were still down by 512,047,000 barrels, or by 24.2% from their early pandemic high, and are just 1.7% from hitting a new 18 1/2 year low...
This Week's Rig Count
The number of drilling rigs active in the US were unchanged from the prior week during the week ending January 27th, and hence remain 2.8% below the prepandemic level, despite increasing in 94 of the prior 121 weeks....Baker Hughes reported that the total count of rotary rigs drilling in the US remained at 771 rigs over the past week, which was still 161 more rigs than the 610 rigs that were in use as of the January 28th report of 2022, but was 1,158 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 decreased by 4 to 609 oil rigs during the past week, after the number of rigs targeting oil had decreased by 10 during the prior week, but there are still 114 more oil rigs active now than were running a year ago, even as they amount to just 37.8% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014, while they are now down 10.8% from the prepandemic oil rig count….at the same time, the number of drilling rigs targeting natural gas bearing formations increased by 4 to 160 natural gas rigs, which was also up by 45 natural gas rigs from the 115 natural gas rigs that were drilling during the same week a year ago, even as they were still less than 10% 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 decreased by three to thirteen rigs this week, with all of those left now drilling in Louisiana's offshore waters....that Gulf rig count is now down by 5 from the 18 Gulf rigs running a year ago, when 17 Gulf rigs were drilling for oil offshore from Louisiana and one was deployed for oil offshore from Texas....since there aren't any rigs drilling off our other coasts at this time, the Gulf rig count is equal to 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 were also two rigs drilling on inland waters...
The count of active horizontal drilling rigs was up by 5 to 705 horizontal rigs this week, which was also 152 more rigs than the 533 horizontal rigs that were in use in the US on January 28th of last year, but just 51.3% of the record 1,374 horizontal rigs that were drilling on November 21st of 2014....on the other hand, the directional rig count was down by 4 to 45 directional rigs this week, while those still were up by 9 from the 36 directional rigs that were operating during the same week a year ago…in addition, the vertical rig count was down by 1 to 21 vertical rigs this week, which equalled the 21 vertical rigs that were in use on January 28th of 2022…
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 January 27th, the second column shows the change in the number of working rigs between last week’s count (January 20th) and this week’s (January 27th) count, the third column shows last week’s January 20th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 28th of January, 2022...
while rigs in the Permian basin increased by three, natural gas targeting drilling in the Permian increased by four to seven rigs, while oil rigs in the basin were down by one to 350... in checking the Rigs by State file at Baker Hughes for changes in the Texas Permian basin, we find that there were two rigs added in Texas Oil District 7C, which includes the southernmost counties in the Permian Midland, but that two rigs were pulled out of Texas Oil District 8, which overlies the core Permian Delaware, while rig counts in other Texas Permian districts were unchanged....since the national Permian basin count was up by three oil rigs, we can thus figure that all three rigs added in New Mexico were set up to drill in the far western Permian Delaware, in the southwest corner of that state...thus, four of the five rigs added in the Permian were targeting natural gas, and both of the rig removals from Texas district 8 had been drilling for oil...elsewhere in Texas, there was a rig pulled out of Texas Oil District 2, while there was a rig added in Texas Oil District 4, both of which were most likely offsetting oil rigchanges in the Eagle Ford shale....there was also a rig added in Texas Oil District 6, which was most like a natural gas rig addition in the Haynesville shale, since the rig count in the Haynesville shale area in adjacent Louisiana was down by one, while Haynesville drilling is shown as unchanged....the three rig decrease in Louisiana included that Haynesville reduction, and two rigs pulled out of the state's offshore waters, while Texas also had a rig removed from the Gulf waters of that state..
It appears the remaining changes all also offset each other....In Oklahoma, there was an oil rig pulled out of the Ardmore Woodford, while there was an oil rig added in the Cana Woodford at the same time, leaving the Oklahoma count unchanged...while there were two rigs added in the Williston basin in North Dakota, there were two rigs pulled out of the Williston in Montana, leaving Montana with one rig remaining and leaving the Williston basin count unchanged...and finally, while there was a natural gas rig added in Pennsylvania's Marcellus, the was a natural gas rig pulled out of West Virginia's Marcellus at the same time, leaving the Marcellus rig count unchanged...
DUC well report for December
Tuesday of last week saw the release of the EIA's Drilling Productivity Report for January, which included the EIA's December data on drilled but uncompleted (DUC) oil and gas wells in the 7 most productive shale regions (click tab 3)....that data showed an increase in uncompleted wells nationally for the second time in 30 months and by the most since June 2020, as well completions slowed while drilling of new wells increased in December, 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 40 wells, rising from a revised 4,537 DUC wells in November to 4,577 DUC wells in December, which was still 10.2% fewer DUCs than the 5,099 wells that had been drilled but remained uncompleted as of the end of December of a year ago...this month's DUC increase occurred as 1,011 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during December, up by 6 from the 1,005 wells that were drilled in November, while 971 wells were completed and brought into production by fracking them, down by 18 from the 989 well completions seen in November, but up by 192 from the 779 completions seen in December of last year....at the December completion rate, the 4,577 drilled but uncompleted wells remaining at the end of the month represents a 4.7 month backlog of wells that have been drilled but are not yet fracked, up from the 4.5 month DUC well backlog of a month ago, and now clearly rising from the 7 1/2 year low of 4.4 months of three months ago, despite a completion rate that is still nearly 15% below 2019's pre-pandemic average...
Both oil basin DUCS and natural gas basin DUCs rose during December, and only one basin saw DUCs decrease....the number of uncompleted wells in the Niobrara chalk of the Rockies' front range increased by 29, rising from 497 at the end of November to 526 DUC wells at the end of December, as 138 wells were drilled into the Niobrara chalk during December, while 109 Niobrara wells were completed....at the same time, the number of uncompleted wells remaining in Oklahoma's Anadarko basin increased by 3, rising from 712 at the end of November to 715 DUC wells at the end of December, as 77 wells were drilled into the Anadarko basin during November, while 74 Anadarko wells were completed.... likewise, DUC wells in the Bakken of North Dakota were up by 3 to 531 by the end of December, as 80 wells were drilled into the Bakken during December, while 77 of the drilled wells in the Bakken were being fracked...in addition, DUC wells in the Permian basin of west Texas and New Mexico increased by 1, from 1,068 DUC wells at the end of November to 1,069 DUCs at the end of December, as 432 new wells were drilled into the Permian basin during December, while 431 already drilled wells in the region were being fracked....on the other hand, DUCs in the Eagle Ford shale of south Texas decreased by 9, from 517 DUC wells at the end of November to 508 DUCs at the end of December, as 109 wells were drilled in the Eagle Ford during December, while 118 already drilled Eagle Ford wells were fracked........
among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, increased by 1 well, from 620 DUCs at the end of November to 621 DUCs at the end of December, as 100 new wells were drilled into the Marcellus and Utica shales during the month, while 99 of the already drilled wells in the region were fracked....at the same time, the uncompleted well inventory in the natural gas producing Haynesville shale of the northern Louisiana-Texas border region rose by 12, from 595 DUCs in November to 607 DUCs by the end of December, as 75 wells were drilled into the Haynesville during December, while 63 of the already drilled Haynesville wells were fracked during the same period....thus, for the month of December, DUCs in the five major oil-producing basins tracked by this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) increased by twently-seven to 3,349 wells, while the uncompleted well count in the major natural gas basins (the Marcellus, the Utica, and the Haynesville) was up by thirteen to 1,228 DUC wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas...
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Ex-U.S. Rep. Tim Ryan announces his next career move - cleveland.com - Former U.S. Congressman Tim Ryan announced Thursday that he’s joining the leadership council of a political nonprofit that promotes the natural gas industry, where he pledges to boost the role of natural gas in meeting climate goals “securely, reliably and affordably.” Ryan, a Niles-area Democrat who lost a hard-fought battle for U.S. Senate to Republican JD Vance last year, will serve alongside former Democratic U.S. Senator Mary Landrieu of Louisiana at Natural Allies for a Clean Energy Future, the organization announced.
Ohio Court of Appeals Upholds Depth Severance Clause in Shale Lease - Marcellus Drilling News - The Ohio Court of Appeals recently issued a decision in a case involving lease language about a “depth severance clause” that is very important for both landowners and drillers to know about. In Tera LLC v. Rice Drilling D LLC, et al., a landowner in Belmont County, OH, signed a lease with language that leases both the Marcellus and Utica shale layers, but all other formations were “reserved to the lessor” (i.e. the landowner). However, the driller, Rice (now EQT), drilled into and produced hydrocarbons from the Point Pleasant layer that sits immediately below the Utica. According to the lease (and the decision by the court), that was a no-no.
Ohio Court of Appeals Upholds Depth Severance Clause in Lease - At issue in Tera LLC v. Rice Drilling D LLC, et al., Case No. 21 BE 0047 (Ohio Ct. App., 7th Dist. January 18, 2023) were two (2) oil and gas leases, signed in 2013 and 2014, concerning approximately 271 acres in Belmont County, Ohio (the “Subject Leases”). The granting clause in the Subject Leases stated that the lessor was leasing to Rice Drilling D LLC (“Rice”) “all the oil and gas, minerals and their constituents (not including coal) in the formations commonly known as the Marcellus Shale and the Utica Shale…” All other formations were “reserved to the lessor.” As further clarification as to the limited scope of the leasehold granted to Rice, the Subject Leases also contained the following depth severance clause:“The Lessor reserves all rights not specifically granted to Lessee in the Lease. Lessor specifically reserves the right to all products contained in any formation: (1) from the surface of the Leased Premises to the top of the formation commonly known as Marcellus Shale, (2) in any and all formations below the base of Marcellus Shale to the top of the formation commonly known as Utica Shale, and (3) in all formations below the base of the Utica Shale.”Rice subsequently drilled six (6) horizontal wells in and through the leasehold. By 2017, all six (6) wells were in production.[1] The landowner, however, discovered that the wells were actually producing from the Point Pleasant formation, which is deeper than the Marcellus Shale and the Utica Shale. Since the Subject Leases were strictly limited to the Marcellus Shale and Utica Shale, the landowner asserted that Rice had no authority or right to extract hydrocarbons from the Point Pleasant formation. The landowner filed suit in October 2017 seeking damages for bad faith trespass and conversion.Rice did not dispute or deny that the six (6) wells landed in the deeper Point Pleasant formation. But Rice defended the suit by arguing that, in 2013 and 2014 when the Subject Leases were signed, the Point Pleasant formation was considered an “interval” contained within the Utica Shale formation. Rice further argued that industry custom and trade usage in 2013 routinely recognized the Point Pleasant formation as being part of the Utica Shale formation. As such, Rice contended that no subsurface trespass occurred because all six (6) wells were authorized under the Subject Leases. In essence, Rice asked the trial court to broadly interpret the depth severance clause to expand the meaning of the term “Utica Shale” to include the Point Pleasant formation.The landowner moved for summary judgment on the issue of liability. The landowner argued that the Subject Leases were unambiguous and that the depth severance clause plainly excluded all formations “below the base of the Utica Shale.” Since it was undisputed that all six (6) horizontal wells landed in the deeper Point Pleasant formation, the landowner suggested that the only issue ripe for trial was the amount of trespass damages. The trial court agreed.In June 2020, the trial court granted the landowner’s motion, noting that an oil/gas lease “conveys rights to extract all geological formations under the leased property, unless there is specific language of limitation.” Here, the depth severance clause clearly limited the leased formations. As such, the trial court concluded that Rice (and Gulfport) “acquired no interest in the oil and/or gas in the Point Pleasant formation.” The trial court also ruled that “…Rice and Gulfport knowingly, willfully and recklessly drilled their wells into the Point Pleasant formation and are therefore willful trespassers.”Given this finding, the trial court held that the damages “owed to the [landowner] are to be calculated without any deductions for the cost of drilling, operating, transporting and any other expense in removing the oil and gas from the [landowner’s] property.” A jury trial was subsequently conducted in July 2021 solely on the issue of damages. The jury returned a verdict in favor of the landowner in the amount of $40,129,357.62. Rice and Gulfport filed a timely appeal to the Seventh Appellate District.On appeal, Rice and Gulfport argued that the trial court erred when it concluded that the Subject Leases were unambiguous. In so holding, the trial court excluded extrinsic and parol evidence regarding industry custom and trade usage.[2] Rice and Gulfport argued that the phrase “commonly known as the…Utica Shale” in the granting clause was ambiguous and that the trial court erred by not admitting and considering evidence of what the oil and gas industry understood the “Utica Shale” to mean in 2013.The Seventh Appellate District disagreed and held that extrinsic evidence was not necessary. The panel observed that the phrase “commonly known as the …Utica Shale” was not ambiguous:“It is undisputed that the Point Pleasant is a formation below the Utica Shale. Consequently, we find that [the landowner] unambiguously reserved the Point Pleasant formation from the lease. To the extent that ambiguity exists within the “grant of lease” provision, we conclude that it is clarified by the plain language of the reservation section…”
Opinion: Fracking in Ohio's state parks is a recipe for disaster - The new state law requiring Ohio state parks to allow fracking on public lands is a recipe for ecological and economic disaster in Ohio. If there is just one methane leak poisoning groundwater with toxins and waste products from fracking fluid, there will be a mass exodus of talented people and good jobs fleeing Ohio. Is Ohio prepared to become the next poster child for ecological disaster? House Bill 507 is bad law passed in a lame-duck session without public comment. With this law, our legislators pandered to Ohio’s oil and gas industry and have risked our clean air, clean drinking water and the growth of sustainable jobs of the future in exchange for dirty energy and dark money. The federal government doesn’t regulate or require public disclosure of the ingredients in fracking fluid injected into the ground to bring up natural gas. That is the state’s responsibility. That means the Ohio Department of Natural Resources allows solvents, waste products and voltaic organic compounds (VOCs) to be injected into Ohio fracking wells, and possibly, eventually permeate our groundwater.Why are the ingredients of the oil and gas industry’s "secret sauce" for its fracking fluid protected when we know clean air and groundwater are essential to life? The fracking industry’s reputation for self-regulation in Ohio and nationwide is notably poor. In 2018, a fracking well at Powhatan Point on the Ohio River exploded and spewed methane gas into the air at the rate of 120 million tons per hour for nearly 20 days. American and Dutch scientists, which spotted the leak by satellite, agreed Powhatan was likely the largest methane leak in U.S. history. The amount of methane released into the air was more than the entire countries of France, Norway and the Netherlands combined in a year.Where were the Environment Protection Agency and ODNR then, and where are they today on legislation to protect the public from corporations like XTO Energy − a subsidiary of Exxon Mobil − which operates the Powhatan well? What reparation did XTO Energy make to Ohio, the nation, or the world to mitigate personal health effects and expected global warming amounts from that gargantuan leak?The fracking boom in Ohio did not provide the jobs and increased population originally promised to Ohioans. What it has done is build a goldmine for fossil fuel industry shareholders who found eager friends at the state house. Some of these politicians accept fossil fuel campaign and dark money donations − and reciprocate by passing laws like HB 507.The fracking industry needs strict regulation to ensure the health and safety of the people who live in and near fracked areas and to prevent future methane leaks. Methane contributes significantly to rising global temperatures.We live in a pivotal moment in history. Either we continue to hurtle faster toward environmental oblivion or begin to do the hard work necessary to implement sustainable energy strategies and solutions.
Ohio Law Labels Natural Gas 'Green,' but What Does It Mean? - Natural gas is officially labeled “green” in Ohio after Gov. Mike DeWine earlier this month signed House Bill (HB) 507 into law, though the green stamp may not carry much legislative weight for funding or regulations, according to the governor’s office. HB 507 passed the Ohio Senate last month, with the primary goal of ensuring state agencies would lease land for oil and gas exploration and production (E&P) activities. After some holdups at the state’s Department of Natural Resources Oil and Gas Land Management Commission (OGLMC) to fully adopt a state code from September 2021 to establish a standard lease form by which state agencies could enter contract with E&Ps, the Ohio Senate rolled in an amendment to HB507 that would expedite the standard lease form. No longer “may” state agencies lease land, but “shall lease, in good faith, a formation within a parcel of land” for oil and gas development, the legislation reads. The bill contains a qualifier that “‘Green energy’ includes energy generated by using natural gas as a resource,” as well as an energy source that emits reduced air pollutants, and thus reduces cumulative air emissions and “is more sustainable and reliable relative to some fossil fuels,” according to HB507. The green label for natural gas is unseen in the United States, but in Europe, regulators this summer voted to accept a proposal from the European Commission to classify new natural gas and nuclear power projects as green. The European Union, facing what the International Energy Agency has called an “energy crisis,” would allow subsidies and low-cost loans for natural gas and nuclear projects deemed sustainable. But in Ohio, the green label may not do much. As of December, permitting in the Utica Shale has declined by 43%, down by 19 permits, according to the latest data from Evercore ISI. Moving forward, it may be possible that the OGLMC’s issuance of permits rises as a result of other language in HB507, but not necessarily as a result of the green label.“Our legal team reviewed the ‘green energy’ provision, and the legislative language did not affect any funding or regulations,” said Dewine’s Press Secretary Dan Tierney. “It was more of an opinion statement by the General Assembly than anything. This was not administration language from our office.“Natural Gas is an important component of Ohio’s energy mix for many reasons, but of relevance here is the fact that natural gas is cleaner than coal and other fossil fuels,” he told NGI. “Thus, when we move to natural gas, we are helping our country and the world. While wind and solar are cleaner energy sources, we cannot replace fossil fuel with wind and solar overnight, making natural gas all the more important to our energy mix.”
Expansion project planned at Utica Shale Academy - The Utica Shale Academy is looking to expand and has applied for $2.4 million to construct a new building in Salineville. Superintendent Bill Watson said an application was made to the Governor’s Office on Appalachia and would match current funds to help erect a $4.8 million, two-story facility on grounds that USA owns along East Main St. The site, which is located adjacent to the Hutson Building, would feature 5,090 square feet of space for offices, several classrooms, machinery, lockers and restrooms for those working with heavy equipment operation, plus students can also learn CNC plasma cutting. A building has been razed with work on the separate 2,800-square-feet outdoor welding lab currently ongoing, and Watson said officials hope to learn later this year if the construction project will become a reality. “We submitted for a $4.8 million project, but we had nearly 50-percent leverage with two $600,000 equity grants and some ESSER (Emergency Elementary and Secondary School Relief) funding and asked for $2.4 million to build a facility next to the welding lab,” Watson said. “It will be for heavy equipment operation and will also be used for recovery to work. I’ve reached out to [jails and public health commissions in] Jefferson, Columbiana and Mahoning counties to work with recovering addicts and get them back into the workforce.” The expansion comes on the heels of the acquisition of the former Huntington Bank building at 50 E. Main St., which is being used as the Energy Center in collaboration with Youngstown State University. That building was acquired in partnership with YSU using funds from a $300,000 capital budget bill allocation which was acquired by Ohio Sen. Michael Rulli and Rep. Tim Ginter (both R-Salem), and the facility houses megatronics, hydraulics, pneumatics, AC/DC electric, Programmable Logic Controllers (PLC’s), diesel mechanics and horticulture.
14 New Shale Well Permits Issued for PA-OH-WV Jan 16-22 | Marcellus Drilling News - New shale permits issued for Jan. 16-22 in the Marcellus/Utica included only 7 new permits in Pennsylvania, 5 new permits in Ohio, and 2 new permits in West Virginia–for a grand total of 14. The top recipient of permits for last week, scoring nearly half, was Coterra Energy (the former Cabot Oil & Gas), with 6 permits issued in northeastern PA’s Susquehanna County. Others: Brooke County, Carroll County, Clay County, Diversified Gas & Oil, Elk County, Energy Companies, INR, Monroe County, Mountain V O&G, Seneca Resources, Southwestern Energy
Murrysville Council approves 2nd fracking well operation on Plum border - Murrysville Council last week unanimously approved what will be the municipality’s second unconventional gas drilling operation on a property straddling the border with Plum. Canonsburg-based Olympus Energy is seeking to build the Hermes unconventional gas drilling well on a 147-acre property just southwest of the Rolling Fields Golf Club, on the 5000 block of Logans Ferry Road. The land is zoned rural-residential and is in the municipality’s oil and gas overlay district. Part of the property extends into Allegheny County and neighboring Plum. Olympus officials said the rough timeline for the project upon approval is 120 days of construction, 240 days of drilling and 240 days for completion. An initial round of drilling would take place between December 2023 and February 2024, with completions to follow in April 2024, project engineer Ryan Dailey said. A second round of drilling would take place in spring 2025, for a total of eight wells, Lucas said. Olympus Energy owns and operates the Titan well pad off Bollinger Road. Plans for the fracking well also include proposed road improvements, including installing a traffic light at the intersection of Saltsburg Road and Golden Mile Highway and widening Saltsburg’s intersection with Logan Ferry Road to better accommodate truck traffic to and from the site. Olympus attorney Blaine Lucas said the Hermes project ultimately would include eight wells. Councilwoman Jamie Lee Korns abstained from voting, as her husband works as an attorney for law firm Babst Calland, which is representing Olympus.
Businesses, groups tell lawmakers regulatory burden, high energy costs must be lowered - Pittsburgh Business Times --A Pennsylvania Senate panel was told that higher energy costs were strangling businesses and consumers alike and that regulatory burdens on the energy industry need to be lowered to keep the commonwealth competitive. The hearing, held at the Boilermakers Local 154 center on Banksville Road, drew representatives from business and labor to outline an “all-of-the-above” approach to the state’s energy needs, with natural gas in the dominant position but with help from coal, solar and other energy sources. The Republican lawmakers and the officials who testified mostly talked about the strength of Pennsylvania’s energy industry and how it can be leveraged to help boost the economy and lower costs for the future. “We can build products right here in Pennsylvania and have good paying jobs,” said state Sen. Dan Laughlin, R-Erie, chairman of the Senate Majority Policy Committee who convened the hearing. “If we regulate ourselves too much it takes our energy costs up and then our jobs and our energy go over to China.” Jeff Kotula, president of the Washington County Chamber of Commerce, said it wasn’t just foreign countries that Pennsylvania businesses and the economy lose to. He and others mentioned the loss of a $1 billion investment by U.S. Steel in the Mon Valley, and said the decisions by bureaucrats on regulations can have a wide-ranging impact. “It has job creation and economic impacts that radiate throughout our country,” Kotula said. Lauren Connelly, VP of local government affairs and advocacy at the Allegheny Conference on Community Development, said that the region’s current and future economy depends on the ability to use all of its energy assets. She said that jobs and economic growth opportunities will be missed. “We know we’re losing deals and investment to other states that are streamlining these (regulatory) processes,” Connelly said. That has been impacting the Pennsylvania natural gas industry, said David Callahan, president of the Marcellus Shale Coalition. Callahan said permitting in Pennsylvania is unpredictable and often more time consuming that it should be because regulators sometimes go beyond what is in the law. Laughlin agreed, saying that he had seen businesses caught up in the “hamster wheel of red tape” while trying to get projects approved. “You never get your permits, you just run around,” Laughlin said.
Southern officials deal with oil spill aftermath -- Officials with the Southern Huntingdon County School District are dealing with the aftermath and making plans after finding a heating oil tank spill at Spring Farms Elementary School on Jan. 22. Dwayne Northcraft, the district superintendent, said the leak was discovered by their maintenance staff early morning Jan. 22. “Our alarms went off around 5:30 a.m. Sunday saying the heating oil tank was low on fuel, but the tank was filled the prior Thursday (Jan. 19),” he said. “Our maintenance supervisor went to the school to physically check the tank to see if it was full. It turned out the 9,000-gallon tank had only about 1,300 gallons left, which meant that around 7,600 gallons of fuel had leaked.” The 9,000-gallon tank is a fiberglass tank that was installed on the elementary school property in 1991. Northcraft said the district has been in contact with the state Department of Environmental Protection and the Huntingdon County Emergency Management Agency, and they will be hiring a company that specializes in the mitigation efforts of oil spills like this one. As of today, the fiberglass tank in question will be removed by Wagner’s Excavating. Currently, there are no visible signs of heating oil in the stream in front of the elementary school, the basement of the school and the well. The well has been pumped twice. “So far, we’ve determined the oil leaked quickly from the tank, and it’s likely around or under the tank,” said Northcraft. “When the excavator removes the tank, we’ll be able to detect just how far the oil has leaked and determine the path of the oil.” Northcraft said the school would remain off-limits to students for the next few weeks, but teachers can get any materials needed to teach their classes. “We could use bottled water, but we also don’t want to compromise our well, as we use it for other things,” he said. “Without knowing where the majority of the oil is located, we don’t want to put heating oil through our water system and on-site sewage treatment and contaminate that. If we contaminate that, it means we would likely contaminate the stream. So we’re trying to prevent that.”
What happens if the largest owner of oil and gas wells in the US goes bankrupt? - EHN— Diversified Energy Company, the largest owner of oil and gas wells in the country, might abandon up to 70,000 oil and gas wells throughout Appalachia without plugging them, according to a new report.The company, headquartered in Birmingham, Alabama, spent the last five years acquiring tens of thousands of aging, low-producing conventional oil and gas wells and some fracking wells primarily in Pennsylvania, Ohio, West Virginia and Kentucky. Conventional oil and gas wells are traditional wells where fossil fuels are extracted through vertical boreholes.A new report, published by the Ohio River Valley Institute, a progressive think tank, finds that the company’s financial liabilities exceeded its assets by more than $300 million in June2022. According to the report’s authors, it’s rare for an oil and gas company’s liabilities to exceed its assets to this extent, prompting concerns that Diversified Energy will go bankrupt without plugging its wells.“We don’t want to see citizens and taxpayers have to pay for plugging these well after this company is gone,” Ted Boettner, author of the report and a senior researcher with the Ohio River Valley Institute, told EHN. “The way Diversified’s business model is set up, this is a distinct possibility.”Boettner’s report expands on a previous report on Diversified Energy published by the same organization in April 2022 that found the company did not have enough funds on hand to plug its rapidly growing inventory of wells. That report also found that the company claims it can plug wells at a cost less than half the industry average, claims dying wells will continue producing for decades longer than can be reasonably anticipated, and misrepresents methane emissions.“These unusual assumptions — as well as accounting practices that function to punt cleanup costs down the line — are not used by any other company in the industry,” Kathy Hipple, report coauthor and research fellow at the Ohio River Valley Institute, said in a statement at the time. The new report finds that those practices have continued, with the company acquiring additional wells while lowering the amount it expects to pay to decommission them.
The next debate on pipeline safety - For months, lawmakers have wrestled with how to make it easier to build large energy projects, such as pipelines (a GOP priority) and renewable energy transmission lines (championed by Democrats).But now one federal watchdog is asserting that current pipeline safety standards are too lenient, writes POLITICO’s E&E News reporter Mike Soraghan.The National Transportation Safety Board said the formula used to calculate a pipeline’s “potential impact radius” significantly underestimates the danger of explosions, and it is urging regulators to modify the calculation.At least twice since 2017, explosions have blown steel debris beyond that so-called blast zone, including one in Kentucky that killed a woman in a nearby mobile home.A particularly brutal example occurred in 2000. An extended family of 12 was sleeping on the banks of New Mexico’s Pecos River when a nearby gas pipeline ruptured, killing everyone.The blast was 675 feet from the campsite, but today’s formula would have considered the family safe at 600 feet away.The metric used for determining a pipeline’s blast zone is based on a number of assumptions, including that a person in the area could immediately understand what is happening and then run 200 feet within five seconds of an explosion.But that’s an unrealistic assumption — “a fantasy story” — said safety advocate Royce Deaver, who worked as a pipeline consultant from Exxon Mobil Corp. for over three decades.The agency that oversees pipeline rules, the Pipeline and Hazardous Materials Safety Administration, said it would “strongly consider” modifications to ensure bigger safety margins. But that agency, an arm of the Department of Transportation, has faced questions about its own track record on safety. A 2015 POLITICO investigation found that the agency lacked the resources to inspect the country’s millions of miles of oil and gas lines, and that it had granted the industry it regulates significant power to influence the rulemaking process.
Natural Gas Price Volatility ‘Simply Noise’ for Heavily Hedged CNX, Says CEO - Appalachian Basin pure-play CNX Resources Corp. is aiming to lock in elevated natural gas prices and protect itself from market swings through an aggressive hedging strategy, CEO Nick Deluliis said Thursday.He said “from a macro perspective, we expect the recent pricing volatility to continue in 2023 as the US domestic markets continue to fluctuate with shifting weather expectations, uncertain domestic production levels,” and growing liquefied natural gas demand from around the world. “How gas prices unfold in 2023 will depend on a difficult to predict combination of those three core elements.” The CEO said “while the extreme volatility in the natural gas markets will significantly impact near term results, prices along the strip are still materially higher than in recent years and as such, the rates of returns on previous capital investments remain not just high, but improved in this environment…” As a result, “the future business plan not only remains intact, but even stronger,” he added. CNX is forecasting capital expenditures (capex) of $575-675 million in 2023, including $430-475 million for drilling and completions. Total capex in 2022 was $566 million.Plans are to run one to two drilling rigs and one continuous, all electric hydraulic fracturing crew throughout the year, Deluliis said.CNX is expecting “modestly lower” production in 2023 versus 2022, he said. Management expects production levels to be at their lowest during the first quarter, then to accelerate as the year progresses.Production “is a result for us, not an objective within our strategy and business model,” he told analysts.“Most importantly, we’re expecting to return to our 2022 production level run rate around mid-year 2023 plus or minus, and from there return to more elevated annual levels in 2024 and beyond,” the CEO said.
US natgas jumps 9% as Freeport LNG asks to start restart process and colder forecasts (Reuters) - U.S. natural gas futures jumped about 9% on Monday from a 19-month low in the prior session on Freeport LNG's request to begin the restart process for its liquefied natural gas (LNG) export plant in Texas and on forecasts for colder weather and higher heating demand over the next two weeks than previously expected. Freeport LNG, the second-largest U.S. LNG exporter, said it had completed repairs to its plant and asked U.S. regulators for permission to take early steps to restart the fire-idled facility. Freeport has said repeatedly that the plant is on track to restart in the second half of January, pending regulatory approvals. Analysts, however, said the plant would likely return in February or later due to the large amount of work needed to satisfy federal regulators. Freeport has already delayed the plant's planned restart date many times from October to November to December and most recently to January. Its return to service will boost demand for gas and prices will likely jump. The facility, which shut in a fire on June 8, 2022, can pull in around 2.1 billion cubic feet per day (bcfd) of gas and turn it into LNG when operating at full power. That is about 2% of U.S. daily production. Front-month gas futures for February delivery rose 27.3 cents, or 8.6%, to settle at $3.447 per million British thermal units (mmBtu). On Friday, the contract closed at its lowest since June 10, 2021. The front-month contract rose out of technically oversold territory for the first time in four days, on track for its biggest daily percentage gain since early November when it rose about 9.7%. But with prices down about 52% over the past five weeks, gas speculators last week boosted their net short futures and options positions on the New York Mercantile and Intercontinental Exchanges to the most since March 2020, according to the U.S. Commodity Futures Trading Commission's Commitments of Traders report. Shares outstanding in the U.S. Natural Gas Fund, an exchange-traded fund (ETF) designed to track the daily price movement of gas, hit 55.2 million on Friday, its fourth record high in a row, according to Refinitiv data. Purchases of UNG so far this year have already hit three of the top 10 biggest daily share purchases on record. With colder weather coming, Refinitiv forecast U.S. gas demand, including exports, would jump from 130.8 bcfd this week to 139.9 bcfd next week. Those forecasts were higher than Refinitiv's outlook on Friday.
U.S. natgas drops 6% to 19-month low on forecasts for less cold, Freeport delay -(Reuters) - U.S. natural gas futures dropped about 6% to a 19-month low on Wednesday on forecasts for less cold weather and lower heating demand next week than previously expected and a growing belief in the market that Freeport LNG's liquefied natural gas (LNG) export plant in Texas will not actually restart for weeks or months. "With a less severe (weather) outlook across Texas and MidCon (Midcontinent region), narrowing odds for disruptive freeze-offs soften the February outlook," analysts at EBW Analytics, a consultancy, told customers in a note, referring to the freezing of oil and gas wells - freeze-offs - that reduce output. Earlier this week, Freeport said its export plant was ready to begin the process of exiting a seven-month outage, pending regulatory approval. But some analysts have stuck with their earlier estimates that it will take until February, March or even later for the plant to actually start pulling in big amounts of pipeline gas. Freeport, the second-biggest U.S. LNG exporter, is important because the market expects gas prices and demand to rise once the plant restarts. The facility, which was shut by a fire on June 8, 2022, can pull in about 2.1 billion cubic feet per day (bcfd) of gas and turn it into LNG when operating at full power. That is about 2% of what U.S. gas producers pull out of the ground each day. Front-month gas futures for February delivery fell 19.1 cents, or 5.9%, to settle at $3.067 per million British thermal units (mmBtu), their lowest close since June 3, 2021. In another sign of fading hopes that extreme cold will eventually supercharge gas prices this winter, the premium on March futures over April NGH23-J23, which the industry calls the widow maker, fell to a deficit. That put gas futures into contango, with forward prices (April) higher than earlier contracts (March). Analysts have said that March, the last month of winter when demand for heating fuel is high, should never trade below April, the first month of spring when demand is lower. The industry calls the March-April spread the "widow maker" because rapid price moves resulting from changing weather forecasts have forced some speculators out of business. "The collapsing (March-April) spread was driven by the blowtorch warmth of recent weeks and plummeting winter supply adequacy risks," On a daily basis, gas output was on track to drop about 1.7 bcfd over the past two days to a preliminary three-week low of 97.4 bcfd on Wednesday as cold weather starts to cause wells to freeze in some producing basins like the Bakken in North Dakota, the Permian in Texas and Appalachia in Pennsylvania. With colder weather coming, Refinitiv forecast U.S. gas demand, including exports, would jump from 130.9 bcfd this week to 138.7 bcfd next week. The forecast for this week was higher than Refinitiv's outlook on Tuesday, while the forecast for next week was lower.
EIA's US gas storage estimate outpaces consensus as NYMEX bears push prices under $3 -The US Energy Information Administration on Jan. 26 estimated a 91 Bcf withdrawal from domestic gas storage last week in a report that modestly outpaced market expectations. The agency's still-largely-bearish report failed to turn back an overnight selloff in NYMEX Henry Hub prompt-month futures, which dropped below $3/MMBtu for the first time since May 2021, data from CME Group and S&P Global Commodity Insights showed. Last week's inventory drawdown narrowly outpaced analysts' consensus projection for an 84 Bcf withdrawal, expected by S&P Global Commodity Insights' weekly US gas storage survey. EIA's latest estimate, though, was less-than-half the size of the five year-average storage pull of 185 Bcf and only a fraction of the year-ago withdrawal of 217 Bcf, both reported in the corresponding week. Following a third-consecutive bearish storage report from EIA, US stocks are now building on a surplus. At 2.729 Tcf, inventories are now 128 Bcf, or nearly 5%, above the five-year average and 107 Bcf, or more than 4%, above the year-ago level, agency data shows.Since mid-December, benchmark US gas futures prices have pulled back by more than 55%, falling from winter highs around $7/MMBtu just six weeks ago. Since late August, prices are down from sustained highs in the $8-$9 range, S&P Global data shows. This week's push to prices levels below $3 comes as the outlook for US storage this year looks increasingly bearish. Many analysts are now projecting a high-side inventory level near 4 Tcf by early November -- well above the 2022 inventory high at 3.65 Tcf. Added pressure on the NYMEX also comes as many US oil and gas producers prepare to release their 2023 guidance, highlighting the recent strength in domestic output. After a late December freeze, US production staged a surprisingly rapid recovery into the new year to trend at a record monthly average of 97.9 Bcf/d in January. According to many analysts' projections, US output should continue to grow this year at a modest pace – despite expected inflation in oilfield equipment and services. According to the National Weather Service, nearly all of the continental US faces an outsized risk for below-average temperatures in the six- to 10-day forecast with the exception of a handful of states stretching from Florida to the Carolinas. In a slightly longer-dated forecast, the risk for below-average temperatures is lower, but still includes most of the Midwest and the Northeast – both key regions for US heating demand. For the week ending Jan. 27, S&P Global's supply-demand and storage models are predicting an inventory drawdown in the range of 140-160 Bcf in what-would-be a relatively bearish late-January withdrawal estimate compared with a five-year average drawdown of 181 Bcf and a year-ago withdrawal of 261 Bcf, data from EIA shows.
February Natural Gas Futures Fall Below $3; Spot Prices Slip - Natural gas futures could not shake their losing ways on Thursday. Weak weather, strong production and another anemic storage print sent prices lower a third consecutive day. The February Nymex gas futures contract settled at $2.944/MMBtu, down 12.3 cents day/day. It marked the first front month close below $3 since mid-2021. March shed 6.7 cents to $2.848. NGI’s Spot Gas National Avg. dropped too, falling $1.735 cents to $3.585. Production held close to 100 Bcf/d on Thursday, as it has most of January, hanging within striking distance of record levels even as demand so far this year proved modest. Benign weather across much of the Lower 48 this month minimized heating needs and natural consumption, weighing on prices. Diminished export capacity also played a role. The 2.38 Bcf/d Freeport LNG facility, out of commission since a fire last June, was expected to return to service late in 2022. It has yet to relaunch, however, amid regulatory delays. Regulators gave the nod this week to begin the restart process, but it remained unclear when Freeport would ramp back to full capacity. Those bearish factors were amplified Thursday by the U.S. Energy Information Administration’s (EIA) inventory report, which showed utilities withdrew 91 Bcf of natural gas from storage for the week ended Jan. 20. It extended a trend of uninterrupted weak storage results so far in 2023. The print for the Jan. 20 week compared with a five-year average draw of 185 Bcf and a year-earlier pull of 217 Bcf. The decrease lowered inventories to 2,729 Bcf, but it left stocks well above the year-earlier level of 2,622 Bcf and the five-year average of 2,601 Bcf. After the EIA report, the end-of-the winter strip in March fell below the first month of the summer strip in April. “Incredibly,” this created a situation in which gas sold during withdrawal season traded below the coming injection season
U.S. natgas jumps 6% in low volume trade ahead of contract expiration (Reuters) - U.S. natural gas futures jumped about 6% on Friday from a 20-month low in the prior session as late buying during a low-volume day ahead of the expiration of the February contract caused prices to swing wildly from negative to positive several times in the last half hour of trade. Traders noted this usually happens as some gas sellers seek to exit their front-month futures positions on the New York Mercantile Exchange (NYMEX) before they expire because they do not want to deliver gas to the Henry Hub in Louisiana. Volatility often peaks near contract expiration days because trading volumes are usually extremely low since few in the market want to deliver or take gas from the Henry Hub. There were only about 3,476 front-month contracts traded on the NYMEX on Friday. That compares with an average of 138,000 front-month contracts traded daily on the NYMEX over the past five years (2018 to 2022). In 2022, gas prices soared by a record 46% on the day the February contract expired before plunging 26% the next day when the March contract became the new front-month. On its last day as the front-month, gas futures NGc1 for February delivery rose 16.5 cents, or 5.6%, to settle at $3.109 per million British thermal units (mmBtu). On Thursday, the contract closed at its lowest since May 2021. For the week, the contract lost about 2%, putting it down for a sixth week in a row for the first time since October. During those six weeks, the front-month has dropped about 53%. The March NGH23 contract, which will soon be the front-month, was little changed on Friday at $2.84 per mmBtu. Earlier in the day, gas futures were down about 4% due in part to a growing belief that there is more than enough gas in storage for the rest of the winter. The weather, meanwhile, is expected to turn from warmer than normal now to colder than normal from Jan. 30 to Feb. 6 before turning warmer than normal again through mid-February. That should keep heating demand mostly low, at least when the weather is warmer than normal, and allow utilities to continue pulling less gas from storage for at least a fourth or even fifth week in a row. Gas stockpiles were currently about 5% above the five-year (2018-2022) average and are on track to rise to 7% above normal in next week's federal storage report.
Natural gas ends unchanged, raising questions on whether it has bottomed -- Natural gas futures fell for a sixth week in a row although Friday’s flat close raised questions on whether the ferocious selloff in the heating fuel over an unseasonably warm winter was coming to an end. The front-month March gas contract on the New York Mercantile Exchange’s Henry Hub settled at $2.849 per mmBtu, or metric million British thermal units — down 10% from a week ago but virtually unchanged from Thursday’s close. Gas futures have lost 57% of their value over the past six weeks after an unusually warm start to the 2022/23 winter led to a collapse in demand for the heating fuel. Prior to this week’s plunge to $2 levels, gas hit 14-year highs of $10 per mmBtu in August, and even traded as high as $7 in December. Friday’s flat close, however, raised hopes among some traders that the market may have bottomed with Thursday’s 21-month low of $2.688 for March gas. The collapse in gas prices came after record high production of above 100 billion cubic feet per day on the average in October and November, and after tepid heating demand for the winter, which officially began on Dec. 21. Due to weak consumption, U.S. gas in storage stood at 2.729 tcf, or trillion cubic feet, at the close of last week, up from the year-ago level of 2.622 tcf. Notwithstanding the latest week’s slide in gas prices, weather forecasts show a likely return to freezing conditions February onwards. Texas-based LNG export terminal Freeport is also reported to be readying to resume operations in February. Freeport consumed 2 bcf per day of gas until its sudden closure in June left the market with some 420 bcf of idle supply. Traders are estimating that it could take till late next month for LNG shipments to again leave the terminal. Despite this, another poor storage report for next week could send prices lower again, warned some traders. The Energy Information Administration reported that utilities drew 91 bcf, or billion cubic feet, from the U.S. national gas storage for heating and electricity generation last week. That was higher than the forecast, as well as the prior week’s draw of 82 bcf. Analysts said weekly gas consumption had to be between 100 and 200 bcf a week in order to meaningfully send prices higher. “Other than the lack of significantly cold winter weather, the looseness of the supply/demand imbalance continues to be led by hefty dry gas production, which is up by more than 5 bcf/d year-over-year, Further price deterioration is still possible and will begin to subside when producers decide to more aggressively put on the brakes with regard to additional production plans this year,” .
Natural gas feeds half of humanity – Mackinac Center --Half of the people on Earth are alive today thanks to nitrogenous fertilizers made of and with natural gas.So why are governments at home and abroad scrambling to cut off humanity’s natural gas supply? Michigan Gov. Gretchen Whitmer has spent years trying to shut down the Line 5 natural gas pipeline – precipitating an international disagreement that puts the state in conflict with both the Biden administration and the Trudeau government. Other natural gas projects in the United States have been attacked, shut down, or blocked, while investment in oil and gas is also under fire.The Dutch and Canadian governments plan to cut fertilizer usage significantly despite heavy backlash. The leadership ofSri Lanka curtailed fertilizer use – until massive crop failures helped fuel an economic crisis and a popular uprising that toppled the government. United Kingdom Prime Minister Rishi Sunak recently brought back the country’s moratorium on hydraulic fracturing, during an energy crisis that leaves thousands of Britons at risk offreezing to death. Meanwhile, an estimated four trillion cubic meters of natural gas sit unused under the English countryside.Natural gas provides many well-known benefits to society, but one of the lesser-known benefits is right on your plate. Fertilizers produced using natural gas are essential in feeding the global population.An estimated 44 percent of the world’s people were consuming food produced with nitrogen fertilizers in 2000, according to an article in Our World in Data. That percentage had risen to 48 percent by 2008. The article, which summarized findings published in Nature Geosciences by scientist and policy analyst Vaclav Smil, estimated that by 2015, three-and-a-half billion people were alive thanks to these products.
U.S. Coast Guard responds to spill in Mississippi River after vessel capsizes - The U.S. Coast Guard said it was responding to an oil spill in the Mississippi River after a dredging vessel capsized in the vicinity of mile marker (MM) 85, near Meraux, Louisiana, on Monday morning. “The reported maximum capacity aboard the vessel is 5,500 gallons of diesel and 100 gallons of hydraulic oil. The discharge amount is unknown but it has been contained,” the Coast Guard said in a statement. Coast Guard Sector New Orleans Incident Management Division is coordinating with Wood Resources in overseeing the response and has recovered more than 3,360 gallons of oily water mixture, it added. The waterway from MM 81 to MM 86 was closed for eight hours, but has since reopened with restrictions in place in order to facilitate recovery operations. There were no immediate reports of any impact to wildlife.
Crews have cleaned up most of the oil that spilled out of the Keystone pipeline in Kansas - The pipeline company that spilled nearly 600,000 gallons of oil onto fields and into a stream in north-central Kansas says it has cleaned up more than 85% of the crude. Meanwhile, the Washington County, Kansas, newspaper reported that the Keystone pipeline is by far the county’s biggest source of tax revenue. The county’s second-biggest source of tax revenue? Also a pipeline operator.TC Energy estimates that 588,000 gallons of crude oil spewed out when the Keystone pipeline burst on Dec. 7 — the biggest spill yet on the Canadian company’s largest oil pipeline system.The company says crews have recovered about 516,000 gallons. More than 800 workers are on site, according to the U.S. Environmental Protection Agency.Much of the work focuses on Mill Creek. Several miles of the stream have been blocked off to facilitate the intensive cleanup and contain the contamination.A state environmental agency said last week that it was seeing a drop in chemical levels downstream from the isolated segment of the creek. The Washington County News reported Thursday that seven of the county’s 10 biggest taxpayers involve pipelines. But revenues from the Keystone pipeline eclipse the rest, and only kicked in recently because a 10-year tax exemption expired. The county, two school districts and other local units of government get more than $1.9 million combined in taxes from the Keystone this year, the newspaper said. The second-biggest source of tax revenue, another pipeline owned by Northern Natural Gas, paid about $670,000 to local units of government in Washington County last year.
Oil refineries release lots of water pollution near communities of color, data show : NPR - Oil refineries release billions of pounds of pollution annually into waterways, and that pollution disproportionately affects people of color, according to a new analysis of Environmental Protection Agency regulatory data.The pollution includes heavy metals, nitrogen and other compounds that can kill aquatic animals, feed harmful algae and make waterways dangerous for humans to fish in, swim in or even touch. The pollution affects communities across the country, but is especially concentrated along the Gulf Coast, in California and near Chicago.The new findings underscore health and environmental dangers across fossil fuel operations, from the wellhead to pipelines, refineries and consumer use.The report was published by the Environmental Integrity Project, an independent watchdog group that routinely analyzes public data collected by the EPA."This is a highly polluting industry discharging large volumes of wastewater," says Eric Schaeffer, executive director the Environmental Integrity Project, and former director of the EPA's Office of Civil Enforcement.The report authors examined EPA water pollution data from 2019 to 2021 for 81 major refineries across the country – about two thirds of all refineries operating in the U.S. Refineries are required to tell the government how much pollution they release into waterways.Most refineries included in the analysis reported releasing extra pollution, beyond what they are legally permitted to. But less than a quarter of those with violations were penalized by the EPA, the data show."We have a chronic problem with enforcement of the [Clean] Water Act," Schaeffer says.ExxonMobil, which operates some of the largest refineries in the country including multiple facilities that the report found are among the largest emitters of key pollutants, declined to comment specifically about its operations. Instead, the company referred NPR to a general environmental statement by the American Fuel & Petroleum Manufacturers trade group.
US seeks accelerated return of SPR crude loans --President Joe Biden's administration said it plans to start refilling the US Strategic Petroleum Reserve (SPR) by accelerating the return of some of the 24.4mn bl of crude it loaned out last year.ExxonMobil, Shell, Chevron and Phillips 66 were among the companies that took long-term loans of crude from the SPR as part of an "exchange" program meant to lower fuel prices. Nearly all of that crude had been scheduled to return to the SPR over a four-month period beginning on 1 June 2024, according to contracts obtained by Argus Media.US energy secretary Jennifer Granholm said the administration had a strategy to begin refilling the SPR that would "accelerate" the return of some of the loaned out crude. The SPR is currently at its lowest levels in nearly 40 years, but still has 371.6mn of crude in inventory."I have no concerns that we will be able to refill and replenish the SPR, and do it at a savings to taxpayers," Granholm said today.The US Energy Department did not respond to requests for details on when crude would return to the SPR, or the volume of borrowed crude set to be returned on an accelerated timetable.Biden announced the exchange program in November 2021, marking an effort to combat rising fuel prices by offering loans of crude from the SPR. At one point when the program was open to bidding, prompt-month Nymex WTI crude futures were $19/bl more than futures prices at the end of the program in September 2024.Under the terms of the SPR exchange contracts, companies were able to select a "return period" that required them to return crude loans over a period ranging from 3-33 months. As payment for the loan, companies had agreed to return 2.3-9.1pc more crude than they borrowed from the SPR.Of an initial 21.7mn bl of crude loaned from the SPR, 20.4mn bl was contracted to be returned between 1 June 2024 and 30 September, according to contracts obtained through a public records record. If the existing contracts remain intact, companies will also have to add a total of nearly 1.8mn bl of additional crude to the SPR as payment for the loans.Beyond accelerating the return of crude loans, the administration is also working on a plan to buy 60mn bl of crude for the SPR at a targeted price of $67-72/bl, using revenue from last year's emergency sale of 180mn bl at an average price of $96/bl. The Energy Department earlier this month called offa "pilot" purchase of up to 3mn bl of crude because it said the offers were too high. Granholm said the administration planned to announce soon a plan for the crude purchases.
Senate Republican leaders introduce bills restricting Biden's SPR authority as WH threatens veto - Republican leaders on the Senate Energy and Natural Resources Committee, led by Ranking Member John Barrasso, R-Wyo., introduced companion bills of House legislation targeting President Biden's use of the Strategic Petroleum Reserve (SPR). The first bill, the Secure Auction for Energy Reserves Act which Barrasso introduced with Sen. Susan Collins, R-Maine, would prohibit the federal government from selling SPR stocks to China and other countries of particular concern. Earlier this month, the House passed similar legislation, the Protecting America’s Strategic Petroleum Reserve from China Act, by a margin of 331-97."China is profiting from President Biden’s political abuse of the Strategic Petroleum Reserve," Barrasso said in a statement. "Meanwhile, America has become more vulnerable to true energy and national security emergencies." "Our legislation will ban SPR sales to China and other hostile nations," he continued. "It will also ban SPR sales to state-owned companies which purchase oil from Russia, Iran, and other nations the U.S. has sanctioned. Adversaries cannot be allowed to benefit from America’s security reserve."Sen. John Barrasso, R-Wyo., the top Republican on the Senate Energy and Natural Resources Committee, introduced two bills to restrict President Biden's authority on Strategic Petroleum Reserve releases. (Associated Press)Collins added that it is "inexcusable that our emergency stockpile of crude oil is being sold to dictators overseas." She said legislation was necessary to ensure Americans primarily benefit from future SPR releases.Over the summer, the Biden administration was heavily criticized after reports that it had sold SPR oil to China which reportedly used the stocks to bolster its own reserves. The White House then fired back, saying it was legally required to sell the oil to the highest bidder. The second legislation Senate Republicans introduced Tuesday, the Strategic Production Response Act, would require the Department of Energy to only tap the SPR when there is a severe energy supply interruption and not until the Interior Department issues a plan to increase oil and gas production on federal lands and waters.
Republicans launch newest fight against Biden's oil drawdowns - Republicans are aiming to neutralize one of the main tools that President Joe Biden used to lower gasoline prices before last year’s elections — his prolific releases of oil from the nation’s Strategic Petroleum Reserve. The House GOP is calling a vote this week on legislation, H.R. 21 (118), that would prohibit releases from the underground petroleum stockpile unless the government approves a corresponding increase in domestic gas and oil production on federal lands. Two weeks ago, the House passed legislation that would ban sales from the reserve to China. Both measures are typical examples of the not-gonna-pass messaging bills that a party offers when it takes over a chamber of Congress, although the China bill picked up significant Democratic support. Senate Republicans led by Energy Committee ranking member John Barrasso of Wyoming have released similar legislation on the oil reserve this week, as the GOP uses the issue to express frustration with Biden’s broader efforts to wean the economy off fossil fuels to combat climate change. But Republicans are casting their latest proposal in national security terms — accusing Biden of recklessly making politically timed sales from an emergency reserve created in response to the Arab oil embargo of the 1970s. “The SPR was created during a time of energy scarcity,” Sen. Kevin Cramer (R-N.D.) said in an interview, adding that Biden should instead unleash production from the nation’s fracking hot spots. “You don’t need an emergency reserve to bail you out of high energy prices. You just need to use the Bakken or Permian Basin.” Congress has also turned to the petroleum reserve for non-emergency reasons over the years, with lawmakers of both parties pushing oil sales to raise money for needs such as highway construction and drug approvals,, and former President Donald Trump once proposed selling off half the SPR’s supplies to shrink the federal deficit. Now, though, Republicans argue that Biden has left the U.S. vulnerable to a severe supply disruption by ordering emergency drawdowns after gasoline prices spiked following Russia’s invasion of Ukraine. The GOP voiced similar complaints when then-President Barack Obama sold oil from the reserve in response to supply disruptions amid the Arab Spring. Biden’s releases last year — including a massive release just before the election — totaled more than 200 million barrels of oil from the reserve, a network of underground salt caverns that now holds 372 million barrels. That’s down from 638 million barrels when Biden took office and the reserve’s lowest level since 1983.The Treasury Department has estimated that the Biden administration’s releases reduced gasoline prices by up to 40 cents per gallon. The national average price was $3.446 a gallon Tuesday, down from an all-time high of $5.016 in June.The Biden administration has initiated a plan to begin refilling the reserve, but Republicans accuse the president of failing to explain why Russia’s invasion and the subsequent spike in fuel prices qualified as an emergency. They also complain that he hasn’t tended to preserving the physical condition of the reserve’s infrastructure, saying its pipelines, pumps and caverns have been degraded from frequent drawdowns.
U.S. House passes bill limiting drawdowns from strategic oil reserve (Reuters) -The U.S. House of Representatives passed a bill on Friday limiting the ability of the energy secretary to tap the strategic oil reserve without developing plans to increase the amount of public lands available for oil and gas drilling. Representatives backed the bill 221 to 205, with support from only one Democrat. President Joe Biden would veto the legislation should it pass Congress, the White House said this week. The bill is expected to face an uphill battle in the Senate, which unlike the House, is controlled by Biden's fellow Democrats. The Strategic Production Response Act, or H.R.21, requires the U.S. energy secretary to develop a plan to increase oil and gas leasing on federal lands, including submerged ones on the Outer Continental Shelf, before tapping the Strategic Petroleum Reserve. It would not stop the president from tapping the SPR in case of an emergency, such as a hurricane that halts production of crude. Republicans, who took control of the House this month, have pushed a series of political messaging bills that appeal to conservative voters. Republican backers of the bill said the Biden administration acted recklessly in selling 180 million barrels from the reserve last year, or 1 million barrels a day for six months, in the biggest release ever. That drawdown and others Biden approved have pushed the level of the SPR to its lowest level since 1983. The SPR should be used only to address true emergencies, said Representative Cathy McMorris Rodgers, a Republican and chair of the House Energy and Commerce Committee. "President Biden has turned a longtime bipartisan strategic asset, the Strategic Petroleum Reserve, into a political tool to cover up the consequences of his expensive rush-to-green agenda," said Rodgers. The Biden administration, which is pursuing an aggressive policy to curb climate change by supporting the energy transition off fossil fuels, has said it sold the oil to counter gasoline prices that had risen to $5.00 a gallon and helped fuel the highest inflation levels in decades. Oil prices spiked last year on Russia's invasion of Ukraine and as the world began to emerge from the pandemic. U.S. Energy Secretary Jennifer Granholm told reporters at the White House this week that Biden "will not allow the American people to suffer because of the backwards agenda that House Republicans are advancing."
Meet the top House recipients of oil and gas money - The oil and gas industry donated millions of dollars to members of the House in the last election cycle. Now, many of the top recipients are well-positioned to advance its interests.Two of them — House Speaker Kevin McCarthy (R-Calif.) and Majority Leader Steve Scalise (R-La.) — serve in leadership positions. Several more have been assigned to House committees where they will wield outsize influence over energy and climate policy.Of the top 10 recipients of oil and gas money in the 2022 election cycle, eight are Republican, according to data from OpenSecrets, which tracks political spending. The contributions include donations of more than $200 from individuals, as well as money from political action committees that represent energy companies and organizations, including the American Petroleum Institute, Chevron Corp., Exxon Mobil Corp. and Koch Industries Inc.McCarthy was the top recipient with $616,563 in oil and gas donations. Scalise received $368,291 from the industry, enough to land him fourth on the list. Six of the top 10 lawmakers hail from Texas, including Rep. Wesley Hunt, a rising star in the Republican party.That an industry would give money to politicians to gain influence is neither new nor unique to the fossil fuel sector. But it highlights the problem with American campaign financing, said Richard Painter, chief White House ethics lawyer under former President George W. Bush. The contributions buy real influence, he said. And oftentimes, it has nothing to do with the interests of the constituents in a congressional district, he said. “These industries pick their favorites and back their favorites and expect their legislation or a lack of regulation in return,” he said, adding, “This is a pattern that you see a lot, and fossil fuels is definitely a GOP industry.”
WildFire Energy creates largest consolidated acreage position in Eagle Ford with new acquisition — WildFire Energy acquired approximately 377,000 net acres and approximately 1,350 wells in the Brazos Valley region of its Eagle Ford asset from Chesapeake Energy Corporation. With the acquisition, WildFire will operate approximately 2,000 gross wells on approximately 600,000 net acres in the eastern Eagle Ford encompassing Burleson, Brazos, Robertson, Madison, Lee, Washington, and Grimes counties of Texas. shale production rig in Eagle Ford basin The acquired Brazos Valley acreage had an average net daily production of approximately 27,700 boe (85% liquid) during the third quarter of 2022. As of December 31, 2021, net proved reserves associated with these properties were approximately 96.8 MMboe. "This acquisition is highly synergistic with our existing assets and the combined size of the overall business positions WildFire Energy as a leading operator in the Eastern Eagle Ford basin. The consolidation of 600,000 contiguous acres is transformative to the business and will drive economies of scale to deliver more high-margin barrels to the advantageous Gulf Coast market," said Steve Habachy, President and COO of WildFire Energy.
Earthquakes rattle Permian shale cost discipline - A recent spike in earthquakes in the US Permian basin of west Texas and southeast New Mexico is drawing renewed scrutiny to wastewater disposal methods from shale operations, adding another potential layer of costs for producers. Back-to-back 5.4 magnitude earthquakes that struck the heart of the Permian basin in late 2022 have lent a new urgency to calls to restrict the use of wastewater injection wells, which have been linked to increased seismic activity. Oil regulator the Railroad Commission of Texas (RRC) has responded by expanding the boundaries of areas identified as most at risk and has asked producers that operate within theses areas to limit the amount of wastewater they pump underground, as well as to curb the use of deep wells. As a result, the industry is facing higher costs, as drilling waste will have to be trucked and disposed of elsewhere. "If we continue to see the scale of the kind of five or greater magnitude events that we saw at the end of last year, you'll start to see a larger impact from a cost and a logistical standpoint for disposal," Rystad Energy senior analyst Ryan Hassler says. This threatens to impose an additional burden on operators that are already grappling with record inflation, a tight labour market and equipment shortages in the Permian basin, where production is growing at a record pace. Disposal of wastewater costs around 40-70¢/bl, while hauling it is up to four times as expensive, according to industry estimates. Even as the RRC has stepped up efforts to tackle the increase in injection-induced earthquakes, critics have accused it of being too slow to act. "The fact that we're having such high magnitude earthquakes would indicate they are not doing enough," watchdog Commission Shift's executive director, Virginia Palacios, says. And the risk of aftershocks can extend to more than a year after the initial earthquake, making it more difficult to assess whether enough is being done now.
In West Texas, Water Is Scarce For Fracking, Expensive For Recycling, Cheap For Disposal Wells, And It Causes M5 Earthquakes. – Forbes - The Permian basin of West Texas and New Mexico is desert for the most part. The desert is called the Chihuahuan but is not raw desert like the Sahara, but desert due on average 10 inches of rainfall per annum. Sparse, scrubby bushes like creosote and mesquite and few big trees, like Cottonwoods that exist along creekbeds that carry water. Water is scarce in the Permian. But not oil! The Permian basin is the premier basin in the US for oil and gas production. It produces over 5.5 MMbpd (million barrels of oil per day), which is a big part of total US production approaching 12 MMbpd. Success out there has enabled Texas to remain # 1 US state in crude oil production and last year has propelled New Mexico to # 2.Fracking is key to success in the Permian basin where the shale technique starts with a horizontal well 1-2 miles long, and pumps about 40 separate frac treatments along the well. Total water used is 20 million gallons, which would fill a football stadium to 40 feet above the grassed area. For use in fracking, freshwater has to come from cities, or aquifers, or by recycling produced water.Since a widespread drought hit the Southwest US about 30 years ago, freshwater is not cheap anymore. And if fracking water competes with aquifer water pumped up by ranchers, this spells trouble. Water is produced up a well along with oil and gas. It’s too salty for use but it can be cleaned up. How much produced water? Typically 1 - 5 barrels for each barrel of oil. The Permian basin produces 5 MMbopd which would translate to 5 – 25 MMbwpd (million barrels of water per day). Such enormous volumes of produced water have to be disposed of in some way, or recycled.The Marcellus shale, the queen of gas shales, has very few disposal wells by state government edict. Produced water is recycled or can also be trucked to Ohio where it’s poured into disposal wells.Recycling of produced water has increased in the Permian in the last few years. This includes on-site clean up and recycling of dirty water to use it on the next fracking job. Or sending the dirty water for commercial cleanup, such as in a desalination plant.Although cleanup/recycle methods are more expensive, they are gaining traction as oil and gas companies are feeling pressure to fix a problem that has caused two earthquakes of M5 (magnitude 5) that occurred one month apart at the end of 2022. This is not good for the industry’s image, even if the quakes caused limited damage to property.In 2022, the combined Midland and Delaware sub-basins of the Permianproduced 7 billion barrels which amounts to 19 MMbwd. A large fraction of this was injected via disposal wells into deep geologic layers. This enormous volume of water was much greater than what Oklahoma produced in a year, 2015, when that state recorded 890 earthquakes of M > 3. Looking at Culberson County, where most of the recent earthquakes have occurred (see Figure 1), injected volumes in 2020 were almost 0.7 MMbwpd.In the Permian basin, earthquakes have increased in proportion to volumes of water injected in disposal wells. The correlation is strong, as it was in Oklahoma. Warnings have appeared that the Permian basin might follow the earthquake trajectory of Oklahoma, which led to a 5.9M quake, Oklahoma’s largest ever, even after regulators had recognized the problem and reduced injections into disposal wells. Such delays fell in the range of 6-12 months.So what has happened in the Permian? The Texas Railroad Commission (RRC) acted quickly after a 5.4M quake occurred in Culberson County on November 16, 2022 (Figure 1).Injection volumes in the Culberson area had to be reduced about 70% from early 2022 — and this was to be completed by mid-2023. This area has 78 disposal wells that are active. 19 of these are deep wells operated by Chevron and Coterra. The new injection limits had to be 745,000 bwpd in Chevron’s 10 wells, and 615,000 bwpd in Coterra’s 9 wells.The clincher from RRC was how RRC would react if another M5 earthquake occurred in the area. If another M4.5 or larger quake occurs in the Culberson area, deep disposal wells close to the source of the quake will be shut in for two years. That would mean finding alternatives to dispose of the produced water: either truck the water to disposal wells in other areas or cleanup/recycle the produced water onsite.However, this would be just a mild hand slap, and would barely touch the huge profits being made out of the Permian basin.
Barnett Shale targeted as Permian Basin operators move into new plays - About 20 years ago, the shale revolution was launched in the Fort Worth Basin where the Barnett Shale has yielded one of the nation’s largest onshore natural gas fields. As that revolution headed west toward the Permian Basin, producers tried to crack the Barnett code but couldn’t quite fit the pieces together. But they managed to take the technological advancements in horizontal drilling and hydraulic fracturing that opened the Barnett, applied them to the Spraberry and Wolfcamp formations – as well as the Bone Spring – and as a result the Permian is now producing a record 5.5 million barrels a day. But as the prime rock in those venerable formations begins to play out, operators are looking for the next target, and beginning to revisit the Barnett. “You’ll see different plays – the Barnett Woodford has been tested already and Pioneer has several thousand locations there.” Rich Dealy, Pioneer’s president and chief operating officer, told the Reporter-Telegram the company is drilling four Barnett wells this year and will gauge their productivity. It all depends on the economics, he said. “By the end of 2023, we will have a better understanding of what the productivity is and how the Barnett can compete with our Spraberry and Wolfcamp wells,” he said. “Other operators had previously drilled Barnett gas wells out west in Culberson County with limited success,” Steve Pruett, Elevation’s president and chief executive officer, told the Reporter-Telegram by email. “We were drilling deeper Devonian horizontal wells and had strong shows in the Barnett, which is above the Devonian carbonate at 10,500 feet.” Pruett noted that the economics of the over-pressured Barnett were stronger than the company’s drilling locations in the Delaware and Southern Midland Basin, so the Delaware and southern Midland Basin locations were sold so the company could focus on the development of the Barnett on the Central Basin Platform. “We are now drilling our 47th well in the play, and we have over 70 locations remaining to drill. The Barnett is gassier than the Wolfcamp, but it produces less water, thus the wells are cheaper to operate than the Wolfcamp or Spraberry wells,” Pruett wrote.
Texas Oil & Gas Industry Paid Record $24.7Bn In Taxes And Royalties - The Texas oil and natural gas industry has paid $24.7 billion in state and local taxes and state royalties – by far the highest total in Texas history. According to just-released data from the Texas Oil & Gas Association (TXOGA), the previous record of just over $16 billion set in 2019 was shattered by 54%. “The Texas oil and natural gas industry plays an extraordinary role in securing our state and national economy and advancing global stability. However, growth is not guaranteed, and policy can promote prosperity, or hinder it. Policies and politics in Texas and across our nation will determine if we can continue to deliver for Texans while meeting our nation and the world’s energy needs,” TXOGA President Todd Staples stated. The amount of $24.7 billion translates to roughly $67 million every day that pays for Texas’ public schools, universities, roads, first responders, and other essential services. Production taxes and royalties to state funds more than doubled over fiscal year 2021. Production taxes grew by $5.8 billion, a 116% increase and royalties to state funds increased by $2.2 billion, a 102% increase. Oil and natural gas production taxes exceeded $10 billion for the first time in Texas history. Staples detailed how oil and natural gas tax and royalty revenue is used to support education, transportation, healthcare, and infrastructure both locally in communities across Texas and through royalty and tax revenue that is paid into the Economic Stabilization Fund (Rainy-Day Fund), the Permanent School Fund (PSF), and the Permanent University Fund (PUF) – all of which are funded almost exclusively with taxes and state royalties paid by the oil and natural gas industry. In 2022, 99% of the state’s oil and natural gas royalties were deposited into the PSF and the PUF, which support Texas public education. Each fund received $2.1 billion – more than double the amounts from last year. The Rainy-Day Fund received $1.5 billion from oil and natural gas production taxes. The value of these two funds now stands at an estimated $56.8 billion and $28.8 billion respectively.
Jet fuel prices up as demand jumps, refinery outages limit supply (Reuters) - Jet fuel prices have risen to levels never recorded in January as demand from China's lifting of COVID-19 travel restrictions and U.S. refinery outages, with the surge likely to continue, analysts and refining executives say. Chinese flight activity has more than tripled since early December to more than an average of 10,700 flights per day, according to data from flight tracking firm Airportia. Jet fuel this year will be the largest source of oil demand growth, says the International Energy Agency, which monitors energy consumption. This month's demand should hit 6.6 million barrels per day, the highest reading since February 2020, said Viktor Katona, an analyst at data firm Kpler. Prices are climbing in Asia, Europe and the United States. In Singapore, jet fuel is trading around $122.30 per barrel, up 14% in the last two weeks. Europe's price for the fuel has climbed to $115 per tonne, the highest since June. New York spot prices were quoted on Thursday at $2.45 above U.S. ultra-low sulfur diesel, a premium not seen at this time of the year since at least 2011. Refining outages in the United States are feeding the price run-up. Cold weather along the U.S. Gulf Coast recently knocked out some processing plants and pushed up the premium for jet fuel, said Gary Simmons, chief commercial officer at Valero Energy (NYSE:VLO). "Overall, we expect jet demand to increase significantly this year," he told an earnings call on Thursday, as air travel continues to rise. U.S. East Coast supplies are likely to remain scarce until mid-February, he said. A Feb. 5 European Union embargo on imports of seaborne Russian refined products will also pressure European supplies and will increase the call on U.S. refiners to fill the gap, analysts said. U.S. jet fuel inventories ended last year at 34 million barrels, the lowest since 1990, according to U.S. government data. Total jet fuel supplied, a proxy for demand, stood at 1.56 million barrels per day in 2022, the highest since 2019.
U.S. crude oil production will increase to new records in 2023 and 2024 – EIA - In our January 2023 Short-Term Energy Outlook, we forecast that crude oil production in the United States will average 12.4 million barrels per day (b/d) in 2023 and 12.8 million b/d in 2024, surpassing the previous record of 12.3 million b/d set in 2019. In 2022, U.S. crude oil production averaged an estimated 11.9 million b/d. Increased production in the Permian region and, to a lesser extent, in the Federal Offshore Gulf of Mexico (GOM) drives our forecast growth in production. We base our forecast on our expectations of crude oil prices and infrastructure capacity additions.Our forecast of crude oil production in the Permian increases by 470,000 b/d to average 5.7 million b/d in 2023.Completion of new natural gas pipelines will allow producers to transport more of the natural gas that is produced along with crude oil (associated natural gas) to market, removing a potential constraint on crude oil production. Producers currently flare some of the natural gas they produce. We forecast that crude oil production in the GOM will increase by 120,000 b/d in 2023, while production in other regions of the United States (except for the Permian) declines slightly.In 2024, we forecast that crude oil production in the Permian will increase by 350,000 b/d, while production in the GOM declines slightly. We forecast that production in other U.S. crude oil-producing regions increases by 70,000 b/d in 2024.We forecast the U.S. benchmark West Texas Intermediate (WTI) crude oil price will average $77 per barrel (b) in 2023 and $72/b in 2024, down from $95/b in 2022. Despite declining crude oil prices, we expect the WTI price will remain high enough to support crude oil production growth, especially in the Permian, where data from the Dallas Fed Energy Survey indicate that average breakeven prices range from $50/b to $54/b.
Halliburton Forecasting North American E&P Spending to Rise 15%-Plus from 2022 -North America natural gas and oil customers are likely to increase their overall capital spending by at least 15% year/year, with well completions equipment already fully contracted, Halliburton Co. CEO Jeff Miller said Tuesday.Well completions fetched higher prices, while exploration and production (E&P) customers clamored for more products, signaling a solid business environment ahead for natural gas and oil, Miller said during a quarterly conference call. As an example, Halliburton’s operating margin climbed to 17.5% in 4Q2022, up 460 basis points year/year and the highest since early 2012.“Everything I see today points toward continued oil and gas tightness,” Miller said during the call. “Given the increased spend required to grow and replace production, I expect activity to remain strong and service intensity to increase through 2023. I see the same supply side challenges in the international markets, with one indicator being that despite OPEC’s 2022 production quotas, several members did not meet their goals.”Miller noted the “resilience of oil and gas demand throughout 2022, even as central banks raised interest rates to combat inflation…It’s clear to me that oil and gas is in short supply, and only multiple years of increased investment in both stemming declines and reserve additions will solve short supply.”E&Ps need to make investments, which in turn “will drive demand for oilfield services for the next several years,” Miller noted. “The unique feature of this upcycle, as I see it, is the investor-driven return discipline by both operators and service companies, which I expect drives a longer duration cycle and translates into years of increasing demand for Halliburton services.”
IPT Well Solutions’ Recent Trial Finds Cost Effective, Green Hydraulic Fracturing Alternative - Hydraulic fracturing, or "fracing," is a technique used in the oil and gas industry to extract resources from the ground. It involves injecting a mixture of water, sand, and chemicals into a well to create fractures in the rock and release oil and gas. While it is a useful tool for accessing energy resources, it also has the potential to impact the environment if not properly regulated and controlled. That's why companies like IPT Well Solutions are constantly looking for ways to make the process safer and more environmentally friendly. Recently, IPT Well Solutions conducted a trial of a new, environmentally friendly acid during frac operations for GMT Exploration in the DJ basin. The trial took place on a 2.5 mile lateral well aimed to improve efficiency, lessen any environmental impact, and reduce costs. The use of this acid in this trial can be safely applied during select stages closer to the perforations. The trial compared the acid alternative to the standard hydrochloric acid that is typically used in frac operations. The team used the standard acid for 20 stages, then switched to the new acid alternative for 23 stages, and finally went back to the standard acid for the remaining 17 stages. While there were some initial difficulties with accurately applying the acid alternative, the trial showed that it reduced stage pump time and had no negative effects on treatment performance. It also led to fewer pad requirements, as it doesn't need to be removed from the surface at the start of frac operations. IPT Well Solutions discovered the benefits of the acid alternative didn't stop at reducing the environmental footprint, it also found significant operational cost reductions. As a result of this success, GMT Exploration plans to continue using this product in the future with the help of IPT Well Solutions stimulation experts. The IPT Team is dedicated to finding industry solutions that improve efficiency, cut costs, and have a positive impact on the environment. The success of this trial is an encouraging sign that companies like IPT Well Solutions are making real progress in finding ways to reduce the environmental impact of hydraulic fracturing operations while still being able to access the energy resources that are so important to our modern way of life. It also highlights the potential for acid alternatives to be used more widely in the industry, as a way to reduce costs and the environmental impact while maintaining high levels of completion efficiency.
Boulder to consider ban on gas hookups this year | KUNC -New research, published in December, found rates of childhood asthma were higher in homes with gas stoves. The peer-reviewed study was another piece of evidence indicating the dangers of gas and its effects on the climate and human health. Responding to the science, local governments across the country have accelerated their efforts to wean off gas. Already, nearly 70 cities in California alone have adopted gas bans or electrification ordinances since 2019. But Colorado has largely been absent from this conversation. Last year, Crested Butte, a small mountain town of roughly 1,700, became the first and only locality in the state to ban gas in new buildings. Now Boulder, a hub of climate research and solutions — the gas stove research came out of Rocky Mountain Institute, founded in Colorado, now with an office in Boulder — is joining the electrification conversation. Boulder Mayor Aaron Brockett said the latest gas stove research only increases the council’s interest in exploring a gas ban in new buildings. “We already had it on the agenda for 2023 to consider requiring all-electric construction in new buildings when we update our building codes this year,” he said in an email. Right now, Boulder’s building codes sport an Energy Conservation Code and a Building Performance Ordinance, both of which aim to reduce building emissions, though not to the extent that an all-electric ordinance would. Brockett added that until this point, the council’s interest in a gas ban was mostly for greenhouse gas reductions, to mitigate climate change. Boulder has a goal of shifting to 100 percent renewables by 2035. “These new health reports add a significant additional reason to consider the change,” Brockett said. Gas stoves, like gas-powered furnaces and water heaters, emit methane — a short-lived but powerful greenhouse gas. They also abet a system of facilities and pipelines that leak the global warming pollutant into the atmosphere before it’s burned for cooking, heat or power. In Boulder, commercial buildings make up 45% of greenhouse gas emissions, with residential buildings adding another 16%. That’s in part due to gas. Xcel Energy, Boulder’s supplier of power, derives 29% of its energy from gas.
COPL reports first oil production at Cole Creek Unit in Wyoming — Canadian Overseas Petroleum Limited (COPL) and its partners announced first oil production from the Frontier 1 sands at its Cole Creek Unit. The company began recompletion operations on the well 11-27-35n-77w at the end of Dec. 2022 to evaluate the light oil potential of the reservoir sands. The lowest of three Frontier 1 sands was perforated with sixty-five ft. of perforations with no subsequent stimulation. Initial fluid recoveries were black heavy degraded oil, black emulsion, minor brown un-gasified light oil and water. An excess of 800 Bbl. of light freshwater drilling mud was lost into the formation during drilling 10.5 years ago, as well as cement during cementing operations. The well was then put on pump for clean up as it is the most cost-effective method to recover the invaded fluids and the resultant freshwater degraded crude oil from the near well bore area. Fluid entry from the reservoir has remained constant through pumping at rates between 125-135 bpd. Gasified light oil volumes increased over the last week with increasing oil cuts up to 86% at week’s end, with the well slugging heavy black degraded oil, emulsion and drilling mud periodically at higher water cuts (up to 85%). The proportions of heavy black degraded oil, emulsion and drilling mud are decreasing as the well continues to clean up through pumping operations. COPL has opted to continue with the current process of well cleanup rather than a hydrocarbon-based stimulation to remove the degraded oil and emulsion from the near well-bore area. A stimulation of this type would remove the damage, though at a significant cost, monetary and time.
Daily natural gas spot prices in western United States exceed $50.00/MMBtu in December -On December 21, 2022, daily natural gas spot prices at three major trading hubs in the western United States (Pacific Gas & Electric [PG&E] Citygate, Northwest Sumas on the Canada-Washington border, and Malin, Oregon) were higher than $50.00 per million British thermal units (MMBtu). These hub prices were higher than in any other market and averaged $48.12/MMBtu above the Henry Hub benchmark, which was $6.14/MMBtu on December 21. PG&E Citygate in Northern California and Malin, Oregon, the northern delivery point into the PG&E service territory, reported the highest natural gas spot prices since December 2000—in both real and nominal terms—according to pricing data from Natural Gas Intelligence. The price at Southern California (SoCal) Citygate was highest on December 13 at $49.67/MMBtu.Several events occurring simultaneously in the West contributed to prices rising to these levels:
- Widespread, below-normal temperatures
- High natural gas consumption
- Lower natural gas imports from Canada
- Pipeline constraints, including maintenance in West Texas
- Low natural gas storage levels in the Pacific region
Note: Some prices exceeded the published range. The price at SoCal Citygate for February 12, 2021, averaged $144.00/MMBtu. The price at Sumas for March 1, 2019, averaged $161.33/MMBtu. From the end of November to mid-December, below-normal temperatures stretched from Western Canada to California, leading to more demand for natural gas for heating. In the first three weeks of December, natural gas consumption in the residential and commercial sectors in the Pacific Northwest and California, combined, increased by 23% from the second half of November; in the electric power sector, natural gas consumption increased 14%, according to data from Point Logic.Natural gas supply did not keep pace with the increased demand. The western region receives most of its supply from other parts of the United States and Canada. Net natural gas flows from Canada dropped by 4% in the first three weeks of December compared with the second half of November, and 9% less natural gas was delivered from the Rocky Mountains.Reduced pipeline capacity because of maintenance in West Texas led to less natural gas flowing west, raising Southern California natural gas prices. In addition, natural gas storage inventories in the Pacific that were 30% below their previous five-year average (as of December 16) also contributed to higher prices. In Northern California, PG&E’s injections to rebuild natural gas inventories over this past summer were lower than in summer 2021.
Rockies, Midcontinent Producers Slash Natural Gas Price Forecasts, Citing ‘Too Much Supply’ -- Oil and gas executives in the Rockies and Midcontinent have downwardly revised their expectations for Henry Hub natural gas prices over the near term, according to a new survey by the Federal Reserve Bank of Kansas City. The Kansas City Fed’s quarterly Tenth District Energy Survey gauges current and expected oil and gas activity in the Tenth Federal Reserve District. The district encompasses the western third of Missouri; all of Kansas, Colorado, Nebraska, Oklahoma and Wyoming; and the northern half of New Mexico. Respondents, on average, forecasted Henry Hub prices of $5.01, $5.52, $5.78 and $6.19/MMBtu for six months, one year, two years and five years from now, respectively. These predictions were down substantially from the third quarter survey, when companies predicted average prices of $7.46, $6.48, $6.16 and $6.51 for the same time frames. “Too much supply currently,” one respondent said in the latest survey. “Will force prices down and activity down.” By 2025, though, increased liquefied natural gas export capacity combined with flat to declining supply “will require higher prices.” The same respondent added, “Drilling and completion costs are continuing to increase while forward commodity prices are decreasing, putting pressure on drilling economics.” Asked what natural gas prices were needed for drilling to be profitable across the fields in which they operate, the average response was $4.32/MMBtu. NGI’s Henry Hub Daily Price Snapshot showed an average price of $2.930 as of Friday. The average price needed to spark a substantial increase in drilling, meanwhile, was $6.13. “Inflation pressures are currently high and will need to be arrested before [natural gas production] growth can be resumed or accelerated,” one participant said. “There are tremendous price increases tied to increased activity today.” The same respondent predicted that new methane rules proposed by the Environmental Protection Agency “will decimate small producers with older properties if implemented as currently written.” Pipeline bottlenecks also are hindering the ability of gas to get where it’s needed, said another participant. “While the market price may be increasing and driving inflation through natural gas dependent products, the supply side cannot respond due to lack of infrastructure between growing supply areas and growing domestic and foreign markets,” the respondent said. On the bullish side for prices, one executive said that “five-plus years of underspending will show up on the production side. Demand will be stronger than anticipated. Prices could be higher.”
Gas pipelines explode. How far away is enough to survive? - An extended family of 12 was sleeping on the banks of New Mexico’s Pecos River on an August morning two decades ago when a nearby gas pipeline ruptured. The explosion spit out three sections of severed steel pipe and opened a blowtorch 2 ½ feet wide. Flames reached across the desert terrain to the family’s campsite, scorching their pickup trucks and melting sleeping bags. No one survived. All 12 family members — linked by marriage and shared grandchildren — died at the campsite, or later at the hospital. That included 6-month-old twins Timber and Tamber Heady. The blast was 675 feet from the campsite, not far enough to spare them. But federal regulators later adopted a formula, still in use today, that would have deemed the family safe at 600 feet away. Now a federal safety watchdog is urging regulators to change the calculation, which sets what’s called a “potential impact radius,” or PIR. It has many other names: “blast zone,” “incineration zone,” “hazard area.” Whatever one calls it, the National Transportation Safety Board (NTSB) says the formula significantly underestimates the danger of gas pipeline explosions and called it “inconsistent” with evidence in a recent report (Energywire,, Sept. 15, 2022). Other safety advocates put it more bluntly. “The whole thing was a fantasy story, like a fairy tale,” said Royce Deaver, a pipeline consultant who worked for Exxon Mobil Corp. for more than 33 years. He has criticized the impact formula for years, and his research was cited in the NTSB report. Critics say the industry-crafted formula shows how federal pipeline oversight is tilted away from safety in favor of pipeline operators. The Pipeline and Hazardous Materials Safety Administration (PHMSA) has indicated it is willing to change the formula, telling the NTSB it would “strongly consider” modifications to ensure bigger safety margins. ‘You’re gonna run’ Any increase in the radius of the blast zone could mean costly pipe upgrades for oil and gas companies. But even the engineer who devised the formula has acknowledged it has gaps. “Don’t assume that you can stand and watch this fire at the edge of the PIR,” Mark Stephens told a Transportation Research Board (TRB) panel in October. “You can’t. You’re gonna run. You’re just likely to survive.”
Oil industry takes offshore fracking case to Supreme Court - The fossil fuel industry is asking the Supreme Court to resolve a legal battle over hydraulic fracturing off the California coast — a fight companies say carries “enormous practical and legal significance.”On Wednesday, the American Petroleum Institute, Exxon Mobil Corp. and DCOR LLC filed a petition for justices to reverse a 2022 ruling from a lower bench that upheld a ban on all new permits for unconventional oil production methods on the Pacific outer continental shelf.A ruling by the high court could have implications for the pace of the nation’s transition away from fossil fuels. The Pacific outer continental shelf is estimated to contain about 10 billion barrels of untapped oil and 16 trillion cubic feet of untapped natural gas, industry challengers said.“If allowed to stand, the decision below will undermine the development of oil, natural gas, and renewable energy on the entire Outer Continental Shelf,” industry lawyers said.The region has already produced 1.3 billion barrels of oil and 1.8 trillion cubic feet of natural gas, according to the petition.On the other side of the legal dispute, environmental groups hailed the June ruling by the 9th U.S. Circuit Court of Appeals as a key victory toward curbing rising greenhouse gas emissions and protecting the biodiverse Pacific outer continental shelf, sometimes known as the “Galapagos of North America.”Environmental groups have fought to block well stimulation practices such as offshore fracking, acid fracturing and matrix acidizing, which are techniques used to boost production from declining reservoirs (Energywire, June 6, 2022).“The decision to halt fracking was exceedingly well-reasoned, and I hope the court rejects the oil industry’s reckless attempt to overturn the 9th Circuit’s ruling,” said Kristen Monsell, oceans legal director at the Center for Biological Diversity, in a statement. The environmental group is among those that took legal action to prevent future offshore fracking in the Pacific Ocean. Monsell added: “Fracking is dangerous to whales, sea otters and other marine wildlife, and this dirty, harmful technique has no place in our ocean.”
Big Oil Asks US Supreme Court to Reinstate Offshore Fracking in California - The American Petroleum Institute and a pair of oil companies filed a petition for certiorariwith the U.S. Supreme Court on Wednesday in a bid to overturn a lower federal court ruling that blocked fracking in public waters off California's coast."The decision to halt fracking was exceedingly well-reasoned, and I hope the court rejects the oil industry's reckless attempt to overturn the 9th Circuit's ruling," Kristen Monsell, oceans legal director at the Center for Biological Diversity (CBD), said in a statement. "Fracking is dangerous to whales, sea otters, and other marine wildlife, and this dirty, harmful technique has no place in our ocean."CBD and the Wishtoyo Foundation sued the Trump administration to stop offshore fracking in 2016. Then-California Attorney General Kamala Harris filed a similar case.In 2018, U.S. District Judge Philip S. Gutierrez ordered a prohibition on permits for offshore fracking in federal waters off California, ruling that the U.S. Department of Interior (DOI) had failed to adhere to multiple federal laws.A three-judge panel of the 9th Circuit Court of Appeals upheld Gutierrez's decision last June, arguing that the DOI violated the Endangered Species Act, the National Environmental Policy Act, and the Coastal Zone Management Act when it allowed fracking in offshore oil and gas wells in all leased public waters off California.In late August, the Biden administration, of which Harris is the vice president, asked the 9th Circuit for an en banc review to overturn the panel's ruling. The Biden administration's request, which drew the ire of environmentalists because it would have enabled offshore fracking to resume, was denied in September.
Containership spills oil off Vancouver - An oil spill was reported in English Bay, Canada, on January 21, that came from a Greek-owned containership.According to information, the incident involving the 8,468-teu Europe (built 2004), which had arrived from Prince Rupert and remained anchored off Vancouver. More specifically, the coast guard said a pilot notified it of pollution from a ship in the area. The organisation identified the Danaos-owned post panamax as the culprit. Namely, a spill was visible from the air close to Spanish Banks beaches, but the most recent updates informs that the oil had not reached the shore. According to estimations, around 60 and 100 litres of fuel was released into the water, the coast guard said, while a boom has been deployed around the vessel. In addition, the ship’s owner has also activated a response and has contracted the Western Canada Marine Response Corporation (WCMRC) to respond. In the meantime, a helicopter, drones and pollution response vessels were sent out to look for any remains of the fuel released. As the Canadian Coast Guard reported, responders reported some non-recoverable sheen off Point Grey and the North Arm, and an initial drone and helicopter surveys of shorelines found no impact to shorelines. Transport Canada has now launched an inspection of the vessel.
Coast Guard To Contain Oil Spill From Ship In English Bay - On Saturday, January 21, at 11:40 am local time, containership MV Europe docked in the English Bay in British Columbia started leaking oil. First Nations and government agencies are fighting to contain the oil spill. An estimated 60-100 litres of oil have already blackened the waters of Vancouver as per a Canadian Coast Guard estimate who are working from both air and water to monitor the slick formed by the oil spill. They boomed around the ship to contain the oil spill, which stopped the oil spill, as there had been no new oil leakage since Saturday. They are working aggressively to identify sensitive zones so that the ship owners and the response partners can act swiftly to protect those areas, said the Coast Guard. They are likely to announce an update on the situation soon.
Cleanup underway to contain oil spill in Sudbury's Ramsey Lake - Contractors have been deployed to Sudbury's Ramsey Lake to clean up a residential oil spill that migrated to the shoreline on Jan. 17. The Ontario Ministry of the Environment, Conservation and Parks estimates around 812 litres of home heating fuel spilled onto the ground from a storage tank at a property on Gennings Street, near the lake. While Ramsey Lake is the main source of the city's drinking water, ministry spokesperson Gary Wheeler said there is only a low risk to the thousands of people who get their municipal drinking water from the lake. "There is a low risk to the David Street water treatment plant intake because the spill happened over two kilometres away," he said in an email to CBC News. The spill on the property happened on Jan. 14, at which point Public Health Sudbury and Districts notified area residents. Wheeler said the ministry is aware of six homes that directly draw their drinking water from an area near the spill, and they have all been contacted. He said cleanup crews installed absorbent containment booms and pads around the property and near the shoreline. Wheeler added the ministry does not yet know when the cleanup efforts will be complete.
Canadian energy giant Suncor faces multiple charges for death of contractor in frozen tailings pond - An astounding 28 charges have been laid under the Alberta Occupational Health and Safety Act against two companies in relation to the death of a contract worker in the province’s oil sands. Patrick Poitras, 25, of Saint-André, New Brunswick was drowned in a frozen tailings pond at the Suncor base mine about 30 kilometres north of Fort McMurray, Alberta on January 13, 2021. He had been operating a bulldozer on the frozen pond when the ice beneath gave way and the vehicle fell through. Christina River Construction is facing nine charges in the fatal incident, while Suncor Energy is facing 19 counts. Both Suncor and the contractor face charges under sections 3 and 195 of the Occupational Health and Safety Act (OHS). These include failing to ensure the health and safety of a worker by permitting the use of a John Deere dozer on ice when it was unsafe to do so, directing a worker to use a dozer on ice that was too thin to support the load, failing to measure ice thickness prior to the start of the job, and failing to use ground penetrating radar to gain a profile of the ice. Suncor was also charged with failing to have the site monitored by an ice engineer and incorrectly calculating the dozer’s weight when determining whether it was safe to operate on the ice. A plea hearing for the charges is scheduled for March 15, 2023 at the Fort McMurray provincial courthouse. It is government policy that any court proceedings resulting from work site fatalities must be completed before investigation reports are published.
Colombia’s choice to halt new oil and gas exploration contracts “absolutely urgent”— Colombia’s Energy and Mines Minister Irene Velez said that the government’s decision not to award new oil and gas exploration contracts was “absolutely urgent” and needs “immediate action.” Speaking in a panel on energy transition from the World Economic Forum at Davos, Velez doubled down on President Gustavo Petro’s campaign promise to transition the country away from fossil fuels. Her remarks signal a stark difference to comments by Finance Minister Jose Antonio Ocampo, who has said Colombia is open to the possibility of new oil and gas exploration contracts given its high fiscal revenue dependence on fossil fuels. “We have decided not to award new oil and gas exploration contracts, and while that has been very controversial, it’s a clear sign of our commitment in the fight against climate change,” Velez said in a panel alongside the CEOs of Repsol and Honeywell International. “This decision is absolutely urgent and needs immediate action.” Velez said the administration’s decision to halt new exploration required investment in other sectors, such as agriculture and tourism, to “leave behind coal and hydrocarbons while surviving as a nation.” While new exploration won’t be allowed, Petro has said oil, gas and coal producers with existing contracts could “carry on normally.” Still, the government, which owns 88.5% of state oil company Ecopetrol SA, has spooked investors with its plans to transition toward renewables.
Brazil increases gas reinjection, flaring --Brazil increased natural gas reinjections and flaring in December from the same month in 2021, decreasing the amount of gas available to the market, according to preliminary data from oil and gas regulator ANP. Gas reinjections — when gas is pumped back into wells to enhance oil recovery or avoid flaring — amounted to almost 69.5mn m³/d in December, up by 14pc from the same month in 2021. But it decreased by 3.8pc from November. Gas flaring rose to 3.7mn m³/d, an 11pc increase from December 2021 and a 1.6pc rise from the previous month. There was 52.8mn m³/d of gas available to the market, a 3pc decrease from the previous year and 5pc less than in November. Total gas production rose to 140.1mn m³/d, 6pc higher than in December 2021. Production was 0.1pc lower than in November. Gas consumption on production platforms rose to 14.6mn m³/d, up by 2.1pc from the same period in 2021 and down by 0.1pc from November.
Brazil losing $1 million per day on oil rig that hasn’t started drilling - The conflict between Brazil’s ambitions to become a more responsible environmental steward while also ramping up lucrative oil exports has turned into an early test for President Luiz Inacio Lula da Silva. Petrobras oil rig offshore Brazil Off the coast of northern Brazil where the Amazon River enters the South Atlantic, state-controlled oil giant Petroleo Brasileiro SA has had an oil rig on site since early December that hasn’t started drilling. The entire industry is waiting to see if the exploration well opens up a new oil frontier in an area known as the Equatorial Margin. World-class finds in Guyana, north of this site, have helped generate further excitement about the area. The delay is costing Petrobras a fortune of about $1 million a day for the rig, three helicopters, support boats and workers, according to calculations by consultancy Wood Mackenzie Ltd. The holdup: State authorities are reviewing a permit for Petrobras to operate a wildlife rescue facility to be used in the event of an oil spill, and it could take them until mid-April to make a decision. Petrobras and other operators have had little success over the past decade exploring Brazil’s basins off its southern coast, which has made the Equatorial Margin a major priority. The country needs to find more reserves, otherwise, production will start declining in the 2030s. At the same time, Lula has also vowed to strengthen the country’s environmental agencies and oversight, which goes beyond just reversing deforestation in the Amazon. A report by Lula’s transition team, which was delivered to the mines and energy ministry in late December, recognized that oil exploration in sensitive areas like the Equatorial Margin may be incompatible with its environmental goals. Petrobras didn’t provide a date for starting the well when contacted by Bloomberg. Deep-water drillships like the ODN II cost between $300,000 and $500,000 a day just in rig rental fees, according to ABESPetro, an association of oil service providers
Music is Love - U.S. LNG, Underground Storage Help Save Europe From Another Tough Winter | RBN Energy - With the war in Ukraine ongoing and Europe largely cut off or quitting Russian natural gas imports, many feared that global gas prices would skyrocket this winter, but prices have fizzled out instead and are at their lowest level since September 2021. That’s not to say gas prices are low, as they are still well above historic norms and high enough to incentivize LNG imports and the development of future LNG capacity. But despite losing its largest gas supplier, and prices running up in the months ahead of this winter, Europe appears to be in much better shape than it was last winter and gas prices have been relatively calm and on the downswing. So why is that? The difference between this winter and last largely boils down to storage inventories and the ability to attract LNG cargoes. In today’s RBN blog, we look at the European gas market, the impact of U.S. LNG supplies, and what it all means for developing LNG projects. Like the U.S., Europe — or at least continental Europe — has a robust underground gas storage system. It works similarly to the U.S. system in that gas is injected into storage during the spring, summer and fall and then withdrawn as needed in the winter. And just like in the U.S., starting withdrawal season with low inventory levels leaves the European market more exposed to weather-related price volatility. Going into the winter of 2021-22, that’s exactly what happened. Due to a confluence of factors, Europe began the season with the lowest level of gas reserves in more than a decade. Then the market was hit with the 1-2 punch of cold weather and rising geopolitical tensions with its largest gas supplier, Russia. Prices were volatile as inventories were drawn down and Russian aggression accelerated, culminating in its invasion of Ukraine in late February 2022. Prices peaked in March before calming slightly in the spring, but the decline in prices was very short-lived.When we last checked in with our friends across the pond back in September (see Beyond the Sea), Europe was aggressively working to refill storage inventories, unwilling to face the winter without Russia and a storage safety net. Over the course of summer and fall, European offtakers outbid Asian offtakers and other end-users for LNG cargoes while imposing austerity measures on consumers to hoard gas for the winter. Europe’s gas-bidding behavior, combined with a steady stream of reductions and cutoffs from Russia, pushed prices to their highest levels ever, including a startling single-day settlement record of nearly $100/MMBtu for TTF on August 26. It may have been an uncomfortable journey from a pricing perspective (just ask the now partially state-owned German utility, Uniper); from an individual perspective, as hot-water use, street lighting, and more were curbed; and from an economic perspective, as industrial end-use was curtailed or priced out of the market, but it worked. While Europe began the winter of 2021-22 with a record-low storage inventory level (right end of yellow line in Figure 2), it began this winter (right end of orange line) with storage comfortably above 90% full.European gas imports from Russia are now nearly non-existent, but there is still one path through Ukraine flowing some gas. (It’s important to note that was not the case while inventories were being replenished last year.) Although reduced from years past, that gas was there to help refill inventories, along with a record-setting amount of LNG.
EU regulators outline trading risks of gas price cap -- The EU's soon-to-be-launched gas price cap will change trading behaviour in potentially disruptive ways for financial stability, regional regulators have warned. In their initial assessments of the EU's so-called market correction mechanism (MCM), EU financial regulator Esma and energy regulator Acer conclude that while trading behaviour is unchanged for now, it could shift dramatically and in destabilising ways if the MCM's activation becomes imminent. The MCM, which will apply from 15 February, would be triggered if the TTF front-month derivative on the Ice Endex exchange holds above €180/MWh for three working days and is at least €35/MWh above Acer's LNG reference price basket, and would limit prices to €35/MWh above this price basket. It will initially apply to TTF exchange-based transactions with an expiry date between the front month and the front year — the European Commission must decide by the end of March whether to extend the mechanism to cover other EU virtual trading points. Market participants are likely to adapt their trading behaviour in such a way to avoid being bound by the price limit if it becomes likely that the MCM will be activated, Esma said. One alternative is to trade on the over-the-counter (OTC) market, while another is to switch to non-EU venues such as the UK's NBP, which would be used as a proxy hedge of gas for EU delivery. Another option is to trade contracts with an expiry date before the front month or after the front year, while firms still have the option of trading in EU markets other than the TTF unless they become part of the MCM. But as none of these alternatives is a perfect substitute, disruptive effects may materialise, Esma said — in particular affecting the ability of non-financial counterparties to adequately manage the risks associated with their business activity. While these behaviour changes "would appear rational on an individual basis, it would trigger significant and abrupt changes of the broader market environment, which could impact the orderly functioning of markets, and ultimately financial stability," the regulator warned.
Yellen says setting price caps on Russian refined oil products 'complicated' - Western countries are working to structure price caps on Russian refined petroleum products to ensure continued flow of Russian diesel, but the markets are complicated and there is a chance things do not go to plan, Treasury Secretary Janet Yellen said. Group of Seven countries and Australia implemented a price cap on Russian oil Dec. 5, banning the use of Western-supplied maritime insurance, finance and other services for cargoes priced above $60 per barrel. They are now finalizing two separate price caps on Russian refined petroleum products, such as diesel and fuel oil, that are due to take effect on Feb. 5 along with a European Union ban on diesel imports, Yellen told reporters in Dakar, Senegal. One will cover high-value products typically sold at a premium to crude, while another will apply to low-value products like fuel oil, she said told reporters traveling with her in Africa. Yellen said setting the new price caps had proven "more complicated" than for crude, given the range of different refined products and price structures, and the importance of ensuring continued supplies of Russian diesel to the market. "It's more complicated, but we've been working hard to figure out how to achieve the same objectives," as with the broader cap on Russian crude, she said. "You know, there's always the potential that things may not go according to plan but we've studied these markets very carefully and we believe that we're going to come out with a set of caps that will achieve the same things that we've achieved with crude so far," she said, adding that adjustments could still be made over time.
185 global ports can bunker LNG - Offshore Energy -Ports around the world are ramping up their efforts to develop LNG bunkering infrastructure as demand for LNG-fuelled ships hits new highs. Over the past year, 44 global ports have joined the club of global ports able to provide LNG bunkering. Namely, according to the data from Clarksons, in January 2022, LNG bunkering was available at 141 ports worldwide. Today, this number has increased to 185 ports worldwide, with a further 50 facilities planned by 2025. Insights from the shipbroker show that 61% of tonnage ordered last year (35% by number) was alternatively fuelled. Over half of tonnage ordered (397 orders, 36.7m GT) was LNG dual fuel, and 1.4% of orders were LNG “ready” (31 orders). Based only on existing orders, DNV forecasts the number of LNG-fuelled ships will reach 876 by the end of this decade. However, if current growth trends continue, LNG bunkering coalition SEA LNG believes the market can expect to see 2-4,000 LNG-fuelled ships in operation by 2030. By the end of 2022, there were 40 LNG bunker vessels operating in northern Europe, the Mediterranean, United States, Canada, South Korea, Japan, Malaysia, China, Singapore, Brazil, and Australia. In addition, 2022 saw commercial ship-to-ship bunkering of LNG taking place for the first time in China, the Caribbean, and Russia. Namely, China welcomed its first seagoing LNG bunkering vessel last year. The 30,000 cbm Hai Yang Shi You 301, described as the world’s largest LNG bunker vessel, was officially put into operation by China State Shipbuilding Corporation’s subsidiary Guangzhou Shipbuilding International following a conversion project for the China National Offshore Oil Corporation (CNOOC).
India's natural gas imports to rise on lower global prices - Petronet LNG - India's liquefied natural gas (LNG) imports are set to recover as global prices ease, the chief executive of the country's top gas importer Petronet LNG Ltd said. Asian spot LNG prices have fallen due to mild weather in Europe and ample inventories, from an average of $30-$35 per million British thermal units (mmBtu) in the December quarter to around $17/mmBtus, A.K. Singh said. India wants to raise the share of gas in its energy mix to 15% by 2030 from 6.2% at present. However, a spike in global gas prices last year, triggered by the Russia-Ukraine conflict, cut demand for cleaner fuel from price-sensitive Indian customers. "Now the export cargoes are hovering at $17 (million British thermal units). We definitely expect that we will get the movement of more cargoes coming to our country." Singh said at the company's earnings press conference. "In previous months it was a lot of volatility," he added. India's gas imports in October and November declined by about a fifth to about 1.8 million tonnes from this fiscal year's peak of 2.2 million tonnes in May, according to government data. Data for December has not yet been released. Due to low local demand, Petronet operated its 17.5 million tonnes a year Dahej LNG terminal on the west coast at 68% capacity in the December quarter. The capacity use has improved to 81% and is expected to rise further as global prices ease, Singh said. Petronet supplies gas, mostly procured under long-term deals with Qatar and Australia, to Indian energy companies for sale to end-users. These companies have also booked capacity at Dahej to import gas directly.
China Becomes World's Biggest LNG Buyer With Flurry Of Long-Term Deals - China is rapidly becoming the world's most dominant force in liquefied natural gas, with Chinese buyers accounting for 40% of recent long-term LNG contracts among global players, according to Nikkei Asia.Take Chinese energy giant Sinopec Group, which reached a 27-year agreement with state-owned QatarEnergy late last year to buy 4 million tonnes of LNG annually. The imports are due to begin around 2026. As a key client, China is also negotiating to invest in a massive Qatari project to expand LNG output.At the same time, a private-sector Chinese energy company, ENN Group, signed a contract last year with Texas-based Energy Transfer to buy 2.7 million tonnes of LNG annually for 20 years. ENN increased its purchasing agreement with NextDecade, also headquartered in Texas, to 2 million tonnes a year for 20 years as well. In addition, NextDecade has agreed to supply 1 million tonnes of LNG yearly to China Gas Holdings, whose principal shareholder is an investment vehicle controlled by the city of Beijing. Imports are to start in the latter 2020s.Over 2021 and 2022, China closed long-term LNG purchasing contracts worth nearly 50 million tonnes a year, European research firm Rystad Energy reports. In this not so covert attempt to corner the LNG market, China has tripled the scale of purchases through long-term contracts in just two years, up from the annual volume of roughly 16 million tonnes from 2015 through 2020.In 2020 and 2021, spot transactions accounted for 40%-50% of China's natural gas imports, well above the estimated 30% for Japan. But China appears to have changed strategy to fit long-term demand. Long-term contracts offer more stability in supplies compared with spot contracts.In 2021, China surpassed Japan as the world's top LNG importer. But last year, imports apparently dropped 18% to around 65 million tonnes on the economic fallout of the coronavirus pandemic. Yet China's demand for natural gas in 2030 is projected to be over 50% higher than in 2021.Amid global efforts to reduce carbon emissions, many countries have converged on natural gas as a relatively clean bridge fuel. The Institute of Energy Economics, Japan predicts annual worldwide LNG demand will reach 488 million tonnes in 2030, up about 40% from 2020. But global supply is on track to fall short of demand by 7.6 million tonnes a month in 2025.The China contingent are addressing the risk of being cut off from the LNG supply chain at a time when U.S. and allies work to create China-free supply chains for semiconductors. Long-term contracts are seen as a hedge against such disruptions.
Investigation: Ukraine buys huge amounts of Russian fuels from Bulgaria – In 2022, Ukraine bought a huge amount of fuels from Bulgaria made from Russian oil, according to data by the Bulgarian National Statistical Institute, provided exclusively to EURACTIV Bulgaria. From January to November 2022, Bulgaria exported €700 million worth of fuels to Ukraine, and if the trend continues in December, the total value for the year will exceed €825 million. Compared to the period before the war, this is a 1,000-fold increase, as Bulgaria’s 2021 fuel exports to Ukraine totalled only €750,000. The current scale of Bulgarian oil exports to Ukraine is so large that it corresponds to about 1% of the size of the entire Bulgarian economy. The main fuel export from Bulgaria to Ukraine is gas oil (also known as red diesel), which makes up more than 90% of deliveries. Gasoline supplies have also increased rapidly over the past six months, which is explained by Russian attacks on Ukrainian critical infrastructure. Diesel fuel is used in heavy industry to power machinery, generators, and off-road vehicles, as well as in agriculture and marine shipping. The producer of gas oil in Bulgaria is the country’s only refinery, located in the port city of Burgas, owned by the Russian oil company Lukoil, which still operates mainly with Russian oil imported by tankers via the Black Sea, thanks to a derogation from EU sanctions. The refinery in Burgas can afford to export fuel at significantly lower prices because it works with its own raw material. Last year, because of Western sanctions, Russian oil prices on world markets were on average $20-30 per barrel lower than stock market prices. Bulgarian statistics show that Ukraine is now the Balkan country’s third-largest trading partner thanks to the export of fuels, having replaced the USA. In 2021, Ukraine ranked eighth among the countries outside the ЕU as a destination for Bulgarian exports. Fuel exports from Bulgaria to Ukraine peaked in November 2022, when €130 million worth of petroleum products were exported. The avalanche of oil exports то Ukraine began in May, when €40 million worth of products were exported, and reached €105 million in June. From June until the end of the year, levels were consistently high.
India Becomes Largest Importer Of Russian Crude - India has become the largest seaborne importer of Russian crude in the wake of the EU ban on seaborne oil imports and subsequent G7 price cap for exports. According to Poten & Partners, exports to India increased to 1.2 million barrels per day in November last year. The volumes of exports eased slightly in December 2022. India is followed by China, which has increased its intake of Russian crude, from around 600,000 barrels per day in the beginning of the year to around 940,000 barrels per day in November. “While India is targeting mostly European barrels from the Black Sea and some from the Baltic, China has focused on the Russian exports from the Far East. Currently, China buys almost all crude exported from Kozmino as other traditional customers Korea and Japan reduced their imports. Turkey initially increased its purchases from the Kremlin, but its imports of Russian crude have fallen by more than 50 percent since peaking in August,” Poten stated. The exact data on the shift in exports are not available as transparency of the Russian trade flow data has been reduced due to the conflict, sanctions, and the increased use of ship-to-ship transfers as well as by shutting off vessels’ AIS responder to hide their destination. The sanctions also resulted in the use of the ‘shadow fleet’ which are older vessels near-retirement used to circumvent western sanctions. These vessels are mostly owned by offshore companies in countries with more lenient shipping rules. The result of this trend has been an ‘ageing’ of the tanker fleet calling on Russian ports. “For example, in January 2022, 40% of the Aframax voyages ex-Russia were done on tankers that were younger than 10 years and only 28% on vessels that were older than 15 years. No vessels older than 20 years were utilized. By December, this age profile had changed dramatically – only 22% of the Aframaxes were less than 10 years old and 50% was over 15 years old. Several voyages were performed on vessels older than 20 years and one Aframax employed was even older than 25 years,” Poten added. The ton-mile demand generated by Russian crude oil exports has tripled since the February of 2022, driving more ton-mile demand, and tightening the oil markets. This trend has been very supportive for the freight market and is likely to continue in 2023. For January to date, Europe has imported around 1 million barrels per day of clean products from Russia, most of which is diesel. Rather than weaning itself of Russian supplies this month, Europe has maximized import volumes, Gibson said in its weekly tanker report.
Pakistan could start importing Russian oil after March - Russia could start exporting oil to energy-starved Pakistan after March if terms are agreed, and is discussing with Islamabad whether payment could be made in the currencies of "friendly" countries, Russia's energy minister said on Friday. Pakistan has been battling a balance of payment crisis with foreign exchange reserves falling to $4.6 billion, barely enough to cover three weeks of imports - mostly for oil. It said in October it was considering buying discounted Russian crude, citing neighbouring India, which has been purchasing from Moscow. Pakistani officials and Russian Energy Minister Nikolay Shulginov, who is in Islamabad for an annual inter-governmental commission on trade and economy, said the key elements of the deal had yet to be agreed. "As for the supply of crude oil and petroleum products, we conceptually agreed on the development and signing of an agreement that will determine and resolve all issues of logistics, insurance, payment, volumes," Shulginov told reporters in Russian, according to the Russian state news agency RIA Novosti. Shulginov also said "negotiations are going on" about settlement in the currencies of "friendly" countries, meaning non-Western countries that have not imposed economic sanctions on Russia in response to its invasion of Ukraine. Oil is generally paid for in dollars. Shulginov said the two sides had "established a timeline of this agreement in our joint statement - which is late March", according to RIA.
The black hell of Albania's ageing oil fields - The people of Zharrez in central Albania live amid a stinking apocalyptic landscape of leaking oil wells and rusting storage tanks, the soil blackened from spills of crude that seep into their water. "We all have health problems," said Milita Vrapi, one of 2,000 villagers who live cheek by jowl with the Balkan nation's largely unregulated oil industry. "The air is very heavy. I often feel dizzy and nauseous with headaches and persistent fatigue," she said the 49-year-old mother as a ramshackle rig wheezed into life only four metres from her home. The water is undrinkable and the vegetables in her garden no longer grow, she said. Abandoned wells and storage tanks and rusted and leaking pipelines litter the oil-rich Patos-Marinza area, where swamps and little lakes of black crude scar the landscape. Much of the equipment in the oil fields has not been maintained for nearly three decades. "Black gold has brought millions of dollars out of the ground, but local residents have hardly benefited from it," said villager Marsilin Senka, while clutching his two-month-old baby, who has acute bronchitis. The air stinks from old wells that have been left open and crude left to rot in crumbling tanks and open-air pits. In summer some locals say it is unbreathable. Zharrez alone has around a dozen wells run by state-owned Albpetrol -- most half a century old -- just a stone's throw from homes. Others in the area are operated by the Chinese Bankers Petroleum group. "Pollution is not a priority for the oil companies," Senka added. "More than 18,000 square metres are heavily polluted by crude oil because infrastructure has been left abandoned for more than 25 years, with harmful effects on the environment and the health of the inhabitants," said Qani Rredhi, the head of the village's environmental group. Even human rights groups have condemned the situation, with the Albanian Helsinki Committee saying in its latest report that "the proximity of residential areas and greenhouses to oil fields and old wells... and the lack of safety and rehabilitation measures are of great concern."Locals say the oil fields may be responsible for myriad health problems affecting residents. "The number of inhabitants who complain of respiratory problems, high concentrations of carbon dioxide in the blood or who suffer from illnesses linked to industrial activities is very high,"
Beetaloo gas fracking could start soon, despite NT government delay in implementing Pepper inquiry recommendations - ABC News --The gas industry's peak body says licences to begin fracking in the Northern Territory could be issued in a month, despite the government missing a key deadline. The NT government had repeatedly claimed it would implement all 135 recommendations of the Pepper Inquiryby the end of 2022, paving the way for industry to ramp up production in the Beetaloo Basin. The Beetaloo Basin is located 400 kilometres south of Darwin and stretches across an area more than twice the size of Tasmania, which contains enough shale gas to power Australia for an estimated 200 years. Since the Northern Territory governmentlifted a temporary ban on fracking in 2018, a number of exploration permits have been issued to gas companies in the region.But the NT government has promised to implement all 135 recommendations of the Pepper Inquiry – intended to mitigate the risks associated with any onshore shale gas development – before it allows companies to move into production.Despite being "due for completion" by the end of 2022, according to the NT government's website, 35 recommendations were yet to be completed.NT environment minister Lauren Moss said all the recommendations would be implemented before production begins.Does carbon capture and storage mean we can keep burning gas?The technology is being hailed as one way Australia can open new oil and gas projects while simultaneously combating climate change. But there are doubts CCS is up to the task. But critics and environment groups have maintained the recommendations were "impossible" to enact and have raised concerns the NT government is caving to pressure from the oil and gas industry.
Pipeline Rumble: farmers the final line of defence in Narrabri fight over Santos gas fracking - These pipelines represent the head of the snake”, says Coonamble farmer David Chadwick.“Australia is the biggest gas exporter in the world that has somehow found itself with the some of the dearest energy costs in the world, and a gas shortage. You don’t have to be a rocket scientist to work out this industry has “played” successive decades of politicians and bureaucrats to end up in this mess.“We are the driest inhabited continent in the world and here is Santos prepared to sacrifice our only secure water supply, the Great Artesian Basin, that sits under 22% of our most productive country.“The Great Artesian Basin is our only secure water supply and it underwrites our $80b agriculture industry. That is why there is a 97% objection to the project across the five shires that surround Narrabri. No water equals no food. This is food versus gas. You can’t eat coal and you can’t drink gas. What’s going in our grandchildren’s lunchboxes?” Having squared away governments, as well as both major political parties, the two major media houses and even environment agencies and regulators, Santos faces a last bloody hurdle in its epic battle against local communities to get its Narrabri gas fracking project off the ground. That’s the farmers. It is the farmers which may kill it.Santos needs to have its gas piped to the Hunter for processing. That means a pipeline; and that means coming onto farmers’ land to survey it, and run a pipeline through. Last Friday NSW Energy Minister Matt Kean issued the company with the authority to force its way onto farmers’ land to conduct surveys for a crucial pipeline, while the Gomeroi people filed an appeal in the Federal court to overrule a decision by the Native Title Authority in support of the project. The battle for Narrabri is still very much afoot. According to Peter Wills, Quirindi landowner, “For Matt Kean to sign off on a gas pipeline to be surveyed in 2023 is incredible. He’s just trashed his reputation with that signature.” Santos’ Narrabri gas project is set to frack for LNG in the Northwest Slopes region of New South Wales. The project would involve drilling up to 850 wells which environmentalists say is highly likely to negatively impact the water table.Meanwhile, the Gomeroi people have made an appeal to a decision by the National Native Title Tribunal which rules that the public benefit of the gas
Santos edges in on fracking the Liverpool Plains despite repeated denials - Santos is denying it, but local farmers on the pristine Liverpool Plains tell a different story. Santos is poised to start fracking in the Gunnedah Basin, Callum Foote reports.During Santos’ 2018 annual general meeting, Tamber Springs farmer and former Gunnedah Shire councillor David Quince, asked Santos CEO Kevin Gallagher what Santos’s plans were with the petroleum exploration areas it controls on the Liverpool Plains.Gallagher’s response was that “What I said last year, and I will reiterate it again this year, we have no plans to drill wells in the Liverpool Plains. The Narrabri Gas Project is contained to areas that you are familiar with and that’s all I can say. Our plans are simply not to drill in the Liverpool Plains and the fact that the permit area that we have covers the Liverpool Plains is something that we have to live with. We can’t cut it off, it’s there but our plans are to the north of that as you are well aware.”However, Santos’ acquisition of the Hunter Gas Pipeline in August last year drew the company one step closer to doing what they never said they would do, but what farmers have long suspected, frack the pristine farmland of the Liverpool plains.The Petroleum Exploration Licences (PELs) that lie under the Liverpool plains and slopes are PELs 1 and 12. These tenements are held by a wholly owned subsidiary of Carbon Minerals, Australian Coalbed Methane (ACM).According to Carbon Minerals’ latest annual report, the PELs 1 and 12 are subject “to a Joint Venture with Santos” with ACM holding a 35% interest in the PELs and Santos holding the remaining 65%. Santos is the project operator.In April last year, the NSW government renewed the licence that Santos and ACM have over the PELs for six years until April 2028.As a part of the renewal, Santos must reactivate a multi-well pilot in the region and conduct geological studies with the joint venture partners holding a technical committee meeting on 6 June 2022 “to further discuss the planned work program and budget for on-ground activities in Petroleum Exploration Licence (PEL) 1 and PEL 12 during the calendar year 2022.”Santos and CEO Kevin Gallagher have yet to respond to queries regarding whether the group has changed his position on Santos’ plans in the Liverpool plains.Says Quince, “To state that Santos’ ‘plans are simply not to drill in the Liverpool Plains’ is simply not credible. Carbon Mineral’s Annual Financial Report for the year ended 31st December 2017, page 2 reports “The Group’s planned exploration activities are currently awaiting resolution of some of the community concerns and pending finalisation of the government regulatory framework in relation to the group’s activities.”Based on advice received by the group from the project operator (Santos) proposed exploration activity will recommence in the near future.Quince believes that Gallagher has misled his shareholders “Santos is an old Australian company and there are probably a lot of elders and retail investors who have shares in Santos and they probably support drilling in the Pilliga, not knowing the ins and outs, but they probably would be mortified to think of drilling on the Liverpool slopes and plains, Sydney’s major food bowl.”
Company fined $19,500 for oil spill, which reached Ahuriri Estuary -- A truck servicing company has been fined $19,500 for discharging oil into a drain leading to an important wetland and wildlife refuge. The penalty follows the company, Truck Stops (NZ) Ltd, having already forked out nearly $10,000 to clean up the accidental oil spill, upstream of the ecologically significant Ahuriri Estuary in Napier. It also spent $7500 to remove oil from its Napier yard and to fix valves, lines and a pump in a washdown bay. The company, through its lawyer Richard Flinn, told the Napier District Court that the spill in December 2021 was due to a systems failure stemming from “accidental, one-off events”. These were a wrongly positioned valve in a service pit, the failure of a waste pump, and significant rainfall which triggered the system to discharge into the stormwater network. The company was prosecuted by the Hawke’s Bay Regional Council. It pleaded guilty to a single charge of discharging a contaminant under the Resource Management Act. Judge Melinda Dickey said that on the morning of December 15, 2021, council staff discovered an oily sheen on the surface water of Plantation Drain at Ford Road in Napier, close to the Onekawa industrial area. The contaminants had flowed out of the drain into Purimu Stream and on to the Ahuriri Estuary/Te Whanganui ā Orotū. The estuary is designated a significant conservation area under the Regional Coastal Environment Plan, a wetland of ecological importance, and it includes a wildlife refuge. Council pollution officers put hydrocarbon-sorbent booms in place and used a specialist vacuum truck to collect the oil.They then traced the spill back to the Truck Stop yard on Ford Rd through the stormwater system, by lifting manholes on a number of industrial properties.
Qatar to buy stake in TotalEnergies' $27 billion projects - QatarEnergy is reportedly in talks to buy a stake from French multi-energy company TotalEnergies’ $27 billion cluster of energy projects in Iraq, Reuters reported, citing sources.“QatarEnergy is looking to acquire a stake of around 30% in the project, one source said,” Reuters noted.An investment from Qatar is expected to contribute an important victory for Iraqi Prime Minister Mohammed al-Sudani, who took office last year after a long period of political turmoil.French major TotalEnergies has been operating in Iraq since the late 1920s. The company currently has a 22.5% interest in the Halfaya oil field. The company also signed major multi-energy agreements in Iraq covering the construction of a new gas network and treatment units, the construction of a large-scale seawater treatment unit, and the construction of a 1 GW photovoltaic power plant, according to its website.
Iran Oil Gushes Into Global Market -- Iran’s oil exports are surging, offering solace to both Tehran and a global market fretting over the prospect of sanctions squeezing Russian supply. Much of it appears to be finding its way to China. The Persian Gulf country’s oil exports surged to about 1.3 million barrels a day in November, and last month held near the highest in four years, according to data from Vortexa Ltd. and Kpler, two well-known shipping analytics firms. The surge is a boost for global markets as sanctions on Moscow threaten to tighten oil supply from a key producer. The picture is more nuanced for the US and its allies — who want low oil prices but have also been trying to curb Iranian exports in order to restrict the Islamic Republic’s nuclear program. The increase appears to be bound for China, the world’s biggest oil importer, under the banner of shipments from Malaysia. Beijing’s intake from the Asian nation surged to a record in December, figures from China’s customs administration show. Malaysian exports to China on that scale are unfeasible. They were almost triple the average daily crude output from the Southeast Asian nation over the first nine months of 2022. The flows also surpassed those of OPEC giants Iraq and the United Arab Emirates. “China’s crude imports from Iran picked up to a new record in the last month of 2022,” Malaysian waters have long been a hub for transferring crude and petroleum products from one tanker to another, sometimes masking the origin. Barrels from Iran and Venezuela have previously been re-branded as oil from Malaysia and Oman. The official data show Malaysia as China’s third-biggest supplier of crude last month, trailing only Saudi Arabia and Russia. Shipments from Iraq were at 5.06 million tons, while flows from the UAE were at 4.95 million tons in December. Across 2022, China imported a total of 35.7 million tons of crude from Malaysia, making the Southeast Asian nation the sixth-biggest supplier, ahead of Brazil, and OPEC members Kuwait and Angola. Officially, China hasn’t imported any Venezuelan crude since 2019 and has only taken oil from Iran on four occasions since the end of 2020, the customs data show.
Envoy Says USA to Boost Pressure on China to Stop Importing Iran Oil - The Biden administration’s top Iran envoy said it will increase pressure on China to cease imports of Iranian oil as the US tries to enforce nuclear sanctions. “China is the main destination of illicit exports by Iran,” and talks to dissuade Beijing from the purchases are “going to be intensified,” US Special Envoy for Iran Robert Malley said in a Bloomberg Television interview Monday. The US reimposed sanctions on the Islamic Republic and its petroleum exports in 2018 after pulling out of an agreement aimed at containing its nuclear program. In response, Tehran has ramped up uranium enrichment activities and restricted international monitoring. Meanwhile, Iranian crude shipments have surged in recent months in defiance of Washington’s censure. Much of that flood of oil appears to be heading to China, the world’s biggest importer. The US will “take steps that we need to take in order to stop the export of Iranian oil and deter countries from buying it,” Malley said. “We have not lessened any of our sanctions against Iran and in particular regards to Iran’s sale of oil.”
Record oil supply will not meet 2023 demand surge: IEA -Oil prices continued to remain volatile at the start of 2023 and went below the $80 per barrel mark after steep declines on the first two consecutive days at the start of the year. Record oil supply of 101.1 million barrels per day in 2023 will not meet surging global demand, leading to a significant shortfall in availability by the end of 2023, according to the International Energy agency. In its latest forecast, the IEA has projected demand to rise by 1.9 million barrels per day to 101.7 million barrels per day (bpd) this year, an upgrade from its previous forecast for a 1.7 million bpd increase, and supply to increase by one million bpd to 101.1 million bpd. These compare with respective forecasts of 101.6 million bpd and 100.8 million bpd made in December. The Paris-based EIA significantly lowered its price forecast for Brent crude oil for 2023 and 2024. The agency in its short term energy outlook lowered Brent price forecast to $83.1 per barrel for 2023 versus its previous forecast of $92.3 per barrel. This compares to the 2022 average price of $100.94 per barrel i.e. a decline of 18 per cent in 2023. The forecast for 2024 was further lower at $77.57, a y-o-y decline of 6.6 per cent. In terms of monthly trend, Brent crude averaged at $80.4 during December-2022 after witnessing a monthly decline of 11.8 per cent, the biggest decline since April-2020. The decline in Opec crude basket was similar at 11.2 per cent to average at $79.7 per barrel. The IEA’s monthly Oil Market Report (OMR) forecast shows supply outstripping demand by nearly one million bpd in the current quarter and in the second quarter again marginally, before a flip. Demand in the third and fourth quarters will be 1.6 million bpd and 2.4 million bpd, respectively, above supply, it said. The IEA cautioned that the timing and pace of a Chinese demand recovery and of Russian supply resilience will affect its forecasts.
OPEC+ Set To Keep Oil Production Unchanged - The Joint Ministerial Monitoring Committee of the OPEC+ group is expected to recommend keeping the current levels of oil production when it meets next week, in a wait-and-see approach amid significant uncertainties about supply and demand in the coming weeks, OPEC+ delegates told Bloomberg on Tuesday.The JMMC is meeting online on February 1 to review the situation on the oil market and potentially recommend actions for the OPEC+ alliance to take.However, in view of the uncertainties about Chinese demand and Russian supply in February and March, OPEC+ is widely expected to keep the current production levels, which reduced target output by 2 million barrels per day (bpd) from November onwards. Yet, the actual cut is estimated to have been around 1 million bpd.In December, OPEC-13’s average December production rose by 91,000 bpd, according to the MOMR, to 28.971 million bpd, with nearly all of the gains coming from Nigeria. But December’s OPEC-10 production – the members bound by the OPEC+ pact – was still substantially below the production quota, with the group underproducing by more than 800,000 barrels per day.Going forward, OPEC, OPEC+, and market participants will look to China and Russia for the most immediate clues on global demand and supply.Analysts and the market expect Chinese oil demand to rebound after the reopening of the world’s largest crude oil importer after nearly three years of Covid-related lockdowns.Saudi oil giant Aramco expects the Chinese reopening and a pick-up in jet fuel demand to lead to a rebound in global oil demand this year, Amin Nasser, the CEO of the world’s biggest oil firm, told Bloomberg in an interview last week.On the supply side, the upcoming EU embargo on seaborne imports of refined petroleum products from Russia – beginning on February 5 – could lead to curtailments in Russian crude oil production. Moreover, Brent oil prices have recently stabilized in the upper $80s, which could mean that OPEC+ will not rush to change production policy just ahead of the EU embargo on Russian diesel and other products, analysts say.
UN: Cost is new obstacle to oil transfer from Yemen tanker - The rising cost of purchasing or leasing a vessel that can hold more than 1 million barrels of crude oil now in a rusting old tanker off the coast of war-torn Yemen is the latest obstacle to resolving the grave threat of massive environmental damage from a possible oil spill or explosion, the UN said Tuesday. UN deputy spokesman Farhan Haq said the availability of very large crude oil tankers "has decreased in the past six months, basically due to events having to do with the war in Ukraine." He said just as the UN was finally gearing up its operation to transfer oil from the FSO Safer tanker, the cost of buying a very large crude oil carrier is now about 50 per cent more than what was budgeted in the original UN plan, and the leasing cost has also increased. "So we have some additional expenses, and it's a little bit harder finding the right ships, but we're proceeding with the work," Haq said. He said donors have generously pledged more than $84 million of the funding required, and additional funding from the private sector is expected soon. Haq said more than $73 million of pledges has been disbursed and essential preparatory work has begun. "All of the technical expertise is in place to undertake the procurement for the complex operation," he said. "This includes a marine management consultancy firm, maritime legal firm, insurance and ship brokers and oil spill experts" as well as contracting a salvage company that will carry out the emergency operation which is at an advanced stage. "However, the key challenge at present is procurement of a very large crude carrier," Haq said. "The UN cannot begin the emergency operation until it is certain that a safe crude carrier will be in place to take on the oil." He said the UN is working with a maritime broker and other partners "to find a workable solution and remains confident the work can begin in the coming months." The United Nations and Yemen's Houthi rebels signed a memorandum of understanding last March aimed at resolving the environmental threat posed by the Safer tanker to the Red Sea. The Safer tanker is a Japanese-made vessel built in the 1970s and sold to the Yemeni government in the 1980s to store up to 3 million barrels of export oil pumped from fields in Marib, a province in eastern Yemen that is currently the scene of limited fighting. The ship is 360 metres (1,181 feet) long with 34 storage tanks.
Oil Prices See Modest Gains On China Demand Hopes - Oil prices traded higher on Monday in thin trade, with many markets in eastern Asian countries closed for the Lunar New Year holiday. Benchmark Brent crude futures rose 0.3 percent to $87.89 a barrel, while WTI crude futures were up 0.3 percent at $81.85. Investor confidence has surged on hopes around China's demand recovery after the recent easing of travel restrictions. Chinese oil demand rose by nearly 1 million barrels per day (bpd) sequentially to 15.41 million bpd in November, the highest level since February, according to recent data from the Joint Organizations Data Initiative. China is the second largest importer of crude oil in the world. Executive director of International Energy Agency (IEA), Fatih Birol, had said last week that energy markets could be tighter in 2023, especially if the Chinese economy recovers and the Russian oil industry struggles under sanctions. Both OPEC and IEA mentioned Chinese demand recovery as the driving force behind oil consumption in 2023.
Oil Rally Falters as Growing Stockpiles Outweigh China Demand -- Oil prices fell slightly Monday as rising stockpiles in the US outweighed optimism that Lunar New Year festivities in China boosted demand. West Texas Intermediate dipped 2 cents to $81.62 a barrel on Monday, marking only the second time oil prices have dropped in the last 12 trading sessions. WTI’s prompt spread sold off after a build in inventories at Cushing, Oklahoma. Stockpiles at the delivery point for benchmark US crude futures rose by about 1.6 million barrels from Jan. 13-17, according to traders, who cited data from Wood Mackenzie. Oil has shaken off a weak start to 2023 as the end of China’s Covid-Zero policies have spurred the world’s largest oil importer to boost its import quotas and prompted analysts to raise their projections for demand. Expectations that the Federal Reserve is close to ending its series of aggressive rate hikes also have buoyed prices. Several measures of technical strength have bolstered crude markets as well. Brent futures crossed above their 100-day moving average for the first time since November, which could spur more buyers to enter the market. Meanwhile, net bullish bets on Brent futures surged to a two-month high last week. Russia’s seaborne crude exports dropped last week, contributing to the smallest inflow into the country’s coffers since Moscow sent its forces into Ukraine. Moscow is set to publish a decree detailing a ban on Russian firms selling oil to clients adhering to a price cap, Kommersant said. Further restrictions on Russian energy flows are due to kick in early next month as the war in Ukraine grinds on. US Treasury Secretary Janet Yellen expressed confidence at the weekend that curbs on Russian crude sales can be expanded to refined products.
Crude oil price rises slightly; focus on China demand and US outlook --Crude oil prices rose slightly in early Asian trade on Tuesday in a market focused on prospects of demand recovery from top importer China and on the global economic outlook ahead of company earnings. Brent crude had risen 5 cents to $88.24 per barrel by 0116 GMT, while U.S. West Texas Intermediate (WTI) crude rose 13 cents to $81.75 per barrel. Crude oil prices in physical markets have started the year with a rally, as China, no longer held back by pandemic controls, has shown signs of more buying and as traders have worried that sanctions on Russia could tighten supply. However, crude prices are wavering as the dollar stabilizes and over exhaustion from China-reopening headlines, according to OANDA analyst Edward Moya. In the United States, “the economy still could rollover and some energy traders are still skeptical on how quickly China’s crude demand will bounce back this quarter,” Moya wrote in a note. Demand for products has lifted the oil market and refining margins. The 3-2-1 crack spread , a proxy for refining margins, rose to $42.18 per barrel on Monday, the highest since October. Investors have piled back into petroleum futures and options at the fastest rate for more than two years as concerns about a global business cycle downturn have eased. U.S. investors are fairly certain the Federal Reserve will implement a small interest rate rise next week even as it remains committed to taming inflation, which recent data shows is slowing. This week traders are watching for more business data that could indicate the health of global economies during an earnings reporting season.
Traders Weighed Demand Expectations Following the Latest U.S. Economic Data - The oil market traded lower on Tuesday as traders weighed demand expectations following the latest U.S. economic data. S&P Global reported that U.S. business activity contracted in January for the seventh consecutive month. Also, spurring concerns of a U.S. recession, the Conference Board Leading Economic Index for the U.S. in December fell by 1% to 110.5 and by 4.2% over the six month period between June and December 2022. As seen in the accompanying chart, LEI readings at these lows are accompanied by recessions. The crude market traded mostly sideways in overnight trading before it breached its previous low and traded to $80.75. The market bounced off that level and rallied to a high of $82.22 early in the morning. However, the market erased any of its gains and sold off sharply on concerns about the economy as well as the expected builds in U.S. oil inventories, with the API and EIA weekly petroleum stock reports forecast to show a build of 1 million barrels in crude stocks. The market extended its losses to $1.96 as it sold off to a low of $79.66 in afternoon trading. The March WTI contract settled at $80.13, down $1.49 or 1.8%, the largest one-day decline since January 4th while, the March Brent contract also settled down $2.06 or 2.34% at $86.13. Meanwhile, the product markets ended the session sharply lower, with the heating oil market settling down 12.37 cents at $3.4272 and the RBOB market settling down 4.78 cents at $2.6487. Five OPEC+ sources said an OPEC+ panel is likely to endorse the producer group's current oil output policy when it meets next week. Ministers from OPEC+, meet virtually on February 1st. The panel, called the Joint Ministerial Monitoring Committee, can call for a full OPEC+ meeting if warranted. Five OPEC+ sources said the JMMC would discuss the economic outlook and the scale of Chinese demand, and was unlikely to suggest tweaks to current policy. One said oil's rebound in 2023 make any changes unlikely. At their last meeting in December, the group left policy unchanged and their next full meeting is not scheduled until June.Separately, Bloomberg reported that OPEC+ delegates said they expect an advisory committee of ministers to recommend keeping oil production levels unchanged when they meet next week amid a tentative recovery in global demand.JP Morgan raised its forecast for Chinese crude demand to 770,000 bpd but maintained its projection for a 2023 price average of $90/barrel for Brent crude. It sees prices ending the year at $94/barrel. JP Morgan analysts said "Absent any major geopolitical events, it would be difficult for oil prices to breach $100 in 2023 as there should be more supply than demand this year." Diesel imports into Europe from Asia, the Middle East and Russia are set to reach 7.2 million tons in January.
WTI Holds Losses After API Reports Biggest Cushing Build Since April 2020 Oil prices traded down today after punching up to seven-week highs with WTI back to a $79 handle after weak 'soft' survey data poured more cold water on the idea of a 'soft landing'., along with disappointing results from a handful of economic-activity bellwethers, such as Union Pacific and 3M. These results have tempered optimism for the economy in the near-term. Oil prices declined on "uncertainty about how much of a demand boost we'll see, and concerns over a weakening U.S. economy constrains the upside," "With the latest PMI numbers in US, Europe and the U.K. showing signs of weakness despite lower energy prices, some doubt is creeping in around any sort of rebound in economic activity," After two crazy weeks of inventory builds (in crude and at Cushing), all eyes are on this week's data as the impact of storms and deep-freezes begins to wear off. It's the second week in a row with no release of oil from the Strategic Petroleum Reserve, "but at the same time refinery maintenance could lead to an increase in crude oil supply," There's an "expectation that we could see an increase in supply in the Cushing, Okla. delivery point," he said. However, oil products are "still very tight and the focus will be on both gasoline and diesel supplies."
- Crude +3.378mm
- Cushing +3.928mm - biggest build since April 2020
- Gasoline +620k
- Distillates -1.929mm
Crude inventories rose for the 5th straight week, but the size of the build was much more 'normal' than the last two.
WTI Rebounds On Small Crude Build; Cushing Stocks Soar Most Since April 2020 --Oil prices drifted sideways to modestly lower overnight after the notable builds reported by API, as mixed company earnings and weaker business activity spurred concerns about the US economy While there’s expectation that China’s oil demand will rise after it ditched restrictive Covid rules, there’s still uncertainty about the strength of the rebound.“After Brent found some resistance just ahead of the $90 mark yesterday, it looks like the market is taking a breather after the rally on Chinese demand optimism,” “Products seem to have settled after cracks surged earlier in the week, which had also helped drive crude up. The market will be watching Cushing inventories, due to rising inventories widening the WTI-Brent spread.” With API drains having stalled, commercial crude stockpiles have swelled by more than 27 million barrels in the prior two weeks. Today's official data:
- Crude +533k
- Cushing +4.267mm - biggest build since April 2020
- Gasoline +1.763mm
- Distillates -507k
US crude inventories built for a 5th straight week, but only a small 533k barrels (well below API and expectations). However, Cushing stocks soared 4.267mm barrels last week - the biggest build since April 2020 (up 4 weeks in a row). Distillates stocks drew down for the 4th week in a row...
Oil Mixed After EIA Data Shows Builds for Crude, Gasoline -- New York Mercantile Exchange oil futures moved mixed post-inventory trade Wednesday, with nearby-month RBOB and ULSD contracts softening in reaction to the U.S. Energy Information Administration showing commercial crude and gasoline inventories increased more than expected last week while demand for middle distillates fell back below 4 million barrels per day (bpd). U.S. commercial crude oil inventories increased by 532,000 barrels (bbl) during the week ended Jan. 20 compared with expectations for stocks to have gained 100,000 bbl. At 448.5 million bbl, nationwide crude oil stockpiles now stand 3% above the five-year average. Oil stored at Cushing, Oklahoma, hub, the delivery point for West Texas Intermediate, jumped by 4.3 bbl from the previous week to 35.7 million bbl. U.S. refiners again increased run rates by a smaller-than-expected 0.8% last week to 86.1% of capacity after utilization fell to the lowest weekly level since Winter Storm Uri in February 2021 shuttered much of the refining capacity in Texas and Louisiana. For the week, refiners processed 128,000 bpd more crude at an average of 14.981 million bpd, which is still near the lowest processing rate since late March 2021. Slow recovery in refinery runs follows a smattering of disruptions while also indicating some refiners are moving units into seasonal maintenance, which is heaviest in February. Domestic oil production, meanwhile, remained unchanged at 12.2 million bpd. In the gasoline complex, commercial stockpiles gained 1.8 million bbl in the reviewed week to 232 million bbl compared with expectations for a 1 million bbl increase. Demand for motor fuel edged up 88,000 bpd to 8.142 million bpd. Distillate demand, however, decreased by 146,000 bpd to 3.878 million bpd after consumption fell the lowest level since April 2020 when the coronavirus pandemic shuttered large chunks of the economy. Domestic distillate stocks declined by 507,000 bbl to 115.3 million bbl. Total products supplied to the U.S. market over the last four-week period averaged 18.9 million bpd, down 10.9% from the same period last year. Over the past four weeks, gasoline supplied to the domestic market averaged 7.8 million bpd, down 4.7% from the same year-ago period. Distillate fuel supplied averaged 3.6 million bpd over the past four weeks, down 13.6% from the comparable year-ago period. Near 11 a.m. EST, NYMEX WTI for February delivery advanced to $80.58 per bbl, up $0.45, RBOB February contract declined $0.0279 to $2.6208 per gallon, and front-month ULSD futures dropped $0.0671 to $3.3577 per gallon.
Oil closes flat as refinery outages counter 16-month high in crude stocks - Oil prices closed flat on Wednesday as unplanned refinery outages faced off with crude stockpiles at 16-month highs. New York-traded West Texas Intermediate, or WTI, crude for March settled up 2 cents, or 0.02%, at $80.15 per barrel after a session high of $81.22 and low of $79.45. The U.S. crude benchmark settled down 1.8% on Tuesday after rising nearly 15% over the past two weeks on bets of a huge pickup in demand from China, which this month abandoned COVID-related restrictions that had been weighing on energy usage in the world’s largest oil importer. London-traded Brent crude for March delivery settled down 1 cent, or 0.01%, at $86.12 per barrel, after a session high at $88.71 and bottom of $85.42. The global crude benchmark fell 2.3% in the previous session after rallying 11% over the past two weeks. U.S. crude stockpiles have risen to their highest in 16 months after unplanned refinery outages led to six straight weeks of inventory builds, the Energy Information Administration, or EIA, said Wednesday. The EIA said crude stockpiles rose by 533,000 barrels in the most recent week to January 20, bringing total builds to 30.3 million since the week ended December 24. According to the EIA, which serves as the statistical arm of the U.S. Energy Department, the total crude stockpile of 820.1M barrels as of last week was the highest since September 2021. A rash of unplanned refinery outages has led to the pile-up of crude on the market. The EIA said U.S. refineries operated at just 86.1% of their capacity last week versus the above 90% run level typical for this time of year. PBF Energy, a refinery producing diesel in Chalmette, Louisiana was shut after a fire on Saturday, with Reuters reporting on Tuesday that the disruption could last at least a month. Exxon Mobil, meanwhile, announced Monday that it will perform planned maintenance on several units at its Baytown, Texas, petrochemical complex. Scheduled maintenance could be lengthier than expected this season, with many U.S. Gulf Coast refineries still running below capacity after Winter Storm Elliott disrupted some 1.5M barrels per day of refining capacity in December. A Suncor refinery in Commerce City, Colorado, has been offline since the storm. Overhauls are also delayed by legacy problems caused by the now three-year-old coronavirus pandemic, with refiners reportedly planning twice as many overhauls this spring than usual. These disruptions to normal refinery operations have restrained the rally expected in crude prices since the start of the year, with WTI trading at just around $80 a barrel versus forecasts for $85 and above. The issues have, however, worked in favor of gasoline prices as the profit margin on a barrel of the leading automobile fuel for March delivery hit $36.88 on Wednesday, up from $34.91 last week, CME data showed. The average price of gasoline at U.S. pumps has climbed to $3.481 per gallon from $3.102 a month ago, the American Automobile Association said Wednesday. On the gasoline inventory front, the EIA reported a build of 1.763M barrels for last week. Gasoline inventories have gone up by almost 10M barrels to date since 2023 began. Distillates, which are refined into heating oil , diesel for trucks, buses, trains and ships and fuel for jets, have been the strongest component of the U.S. petroleum complex lately in terms of demand. Distillate stockpiles have fallen by more than 4M barrels since the start of the year.
Oil extends rally on upbeat U.S. economy, refinery outages -- Oil’s rally extended on Thursday as upbeat U.S. economic data helped crude futures rise while lower-than-usual refinery runs pushed up retail prices of gasoline at pumps across America. New York-traded West Texas Intermediate, or WTI, crude for March settled up 86 cents, or 1.1%, at $81.01 per barrel. WTI has risen a cumulative 1.5% in the past two sessions after a weighted drop of 1.4% in the prior two days, resulting in a flat week thus far for the U.S. crude benchmark. London-traded Brent crude for March delivery settled up $1.35, or 1.6%, at $87.47 per barrel. The global crude benchmark rose a total 1.6% over the past two days after a drop of 1.7% in the preceding two, resulting in a flat week as well for Brent, just like WTI. Overall, WTI has risen about 1% for January and Brent almost 2% on bets of a pickup in demand from China, which announced at the start of this month an end to three years of COVID-related restrictions that had been weighing on energy usage in the world’s largest oil importer. The China move aside, U.S. refinery runs have also fallen below seasonal norms due to inclement weather and unplanned outages that have sent retail gasoline prices rising after dropping to a one-year low in December. Thursday’s rise in WTI and Brent came after a better-than-expected U.S. GDP number for the fourth quarter of last year, released earlier on Thursday by the Commerce Department. Q4 gross domestic product expanded by an annualized 2.9%, down from the year-on-year expansion of 3.2% in the third quarter, but still higher than Wall Street economists’ forecasts for a 2.6% growth. GDP aside, U.S. durable goods orders for December came in twice more than expected, with a 5.6% gain. Sales of new homes in the United States rose for a third straight month in December after the Fed slowed its rate hike for the first time last month after aggressive monetary tightening since June. The “better-than-expected U.S. GDP data supports the argument that the Fed could still deliver a soft-landing” to the economy versus fears of a recession, A rash of unplanned refinery outages have led to the pile up of crude on the market and boosted gasoline prices at the pump. The disruptions have caused crude inventories to swell by some 30 million barrels over the past five weeks and gasoline stockpiles to rise by around 10 million barrels, restraining the rally in both crude and gasoline futures. But they have worked in boosting pump prices of gasoline prices as the profit margin on a barrel of the leading automobile fuel for March delivery hit $36.88 on Wednesday, up from $34.91 last week, CME data showed.
WTI Tops $81 After US Macro Data Eases Recession Fears - Oil futures nearest delivery on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange settled Thursday's session higher, propelled by another round of U.S. economic data showing the broader economy is still underpinned by solid growth momentum despite some pockets of weakness, raising hopes for a so-called "soft-landing" -- a scenario where inflation is easing without a recession. Thursday's round of macroeconomic data in the United States showed more evidence that the economy could still avoid recession, which would be supportive for the short-term demand outlook. For starters, the U.S. economy closed out 2022 in solid shape even as gross domestic product slowed to 2.9% in the final three months of the year, according to data released this morning by the Bureau of Economic Analysis. Economists mostly expected a softer reading of 2.6%. Further details of the report revealed the increase in real GDP was broad-based, driven by gains in private inventory investment, consumer spending, and federal and local government spending. Personal income increased $311 billion in the fourth quarter compared with an increase of $283.1 billion in the three months ending in September 2022. The gain primarily reflected increases in compensation led by private wages and salaries, government social benefits, and personal interest income. That could be supportive of consumer discretionary spending this year should the national unemployment rate remain near historically low levels. In the labor market, weekly unemployment claims dropped again last week, suggesting demand for labor is still plentiful even as some large employers announce job cuts. Initial jobless claims, a proxy for layoffs, fell 6,000 to 186,000 last week, with several large states, including California, Texas, New York, and Michigan, reporting large declines in jobless claims. There were 10.5 million job openings in November, down from the peak of 11.9 million in March, but far exceeding the number of unemployed Americans seeking work, a mismatch that continues to fuel competition for workers. Despite some encouraging macroeconomic data, demand for refined fuels that is closely tied to industrial activity and consumer spending remains weak, according to data from the U.S. Energy Information Administration. Distillate fuel oil supplied to the U.S. market -- a proxy for demand -- fell below 4 million bpd last week, some 678,000 bpd or 14% below last year's consumption rate. Middle distillate demand closely correlates with economic activity, with the middle of the barrel mostly consumed in industrial and commercial sectors, including construction, trucking, farming and for heating. Manufacturing conditions in the U.S. deteriorated significantly at the start of the year, hit by rising interest rates and a lack of consumer demand. A combination of weak fuel demand along with a slow recovery in refinery run rates pushed U.S. crude oil inventories to the highest level since June 2021. At 448.5 million bbl nationwide, crude oil stockpiles now stand 3% above the five-year average. At settlement, West Texas Intermediate futures for March delivery advanced to $81.01 bbl, up $0.86 on the session, and Brent March futures on ICE rallied $1.35 bbl to $87.47 bbl. NYMEX RBOB February contract advanced to $2.6121 gallon, and front-month ULSD futures gained $0.0352 to $3.3965 gallon.
ULSD Falls as G7 Mulls $100 Cap for Russian Diesel Exports - New York Mercantile Exchange oil futures and Brent crude traded on the Intercontinental Exchange declined in afternoon trade Friday, with the February ULSD contract falling as much as 4% in reaction to reports the G7 coalition is considering a price cap of $100 bbl for the Russian diesel exports -- a level that will allow Moscow to continue fuel shipments to the global market with minimum interruptions. The Group of Seven nations along with European partners on Friday began intense negotiations on price limits for Russian fuel exports, which include gasoline and middle distillates ahead of an EU embargo on Russian fuel imports. The embargo comes into full force on Feb. 5. Earlier reports suggested the discussed price cap in the $100 to $110 bbl range is rather generous. For context, diesel futures in northwest Europe are currently trading at about $130 bbl, according to ICE Futures Europe data. Russian supplies have been recently trading at a large discount to those from elsewhere, with diesel roughly in the $100 bbl range, meaning the impact on Russian producers may not be as disruptive as previously feared. The blueprint for the price cap follows a similar measure already applied to Russian crude exports that have so far resulted in little interruption in the global oil market while the revenues to Kremlin coffers fell sharply at the start of 2023. While the $100 cap may not be too impactful, the EU's imports ban could be, according to analysts. At the start of 2023, Europe continued to source more than a quarter of its diesel imports from Russia, according to tanker-tracking data. Finding a replacement for these volumes would not be an easy task. A Swiss bank expects Russian oil output to fall below 9 million bpd in 2023 from around 10 million bpd last year. The U.S. Energy Information Administration estimates the impact of Western sanctions might be deeper, with Russian daily crude output forecast to average 8.5 million bbl this year. Moscow admitted in recent days that Western sanctions will likely reduce its refinery operations but free up more crude oil to sell. At settlement, West Texas Intermediate futures for March delivery declined below $80 bbl to $79.68 bbl, down $1.33 on the session, and Brent March futures on ICE fell $0.81 to $86.66 bbl. NYMEX RBOB February contract dropped back $0.0235 to $2.5886 gallon, and front-month ULSD futures plummeted $0.131 to $3.2655 gallon.
Oil ends lower ahead of OPEC+ committee meeting, EU ban on Russian oil products - Oil futures declined on Friday, with U.S. prices below $80 a barrel and settling at their lowest in more than a week, as uncertainty over the outlook for the market climbed ahead of an OPEC+ committee meeting and European Union ban on Russia oil products. Prices for oil had gained in early dealings, buoyed by improving demand prospects driven by China’s economic reopening and expectations that the U.S. economy could achieve a “soft landing” and avoid a recession later this year. West Texas Intermediate crude for March delivery fell by $1.33, or 1.6%, to settle at $79.68 a barrel on the New York Mercantile Exchange, down from an intraday high of $82.48. Based on the front-month contract, prices settled 2.4% lower for the week, at their lowest since Jan. 18. according to Dow Jones Market Data. March Brent crude the global benchmark, lost 81 cents, or 0.9%, to $86.66 a barrel on ICE Futures Europe, for a weekly decline of 1.1%. April Brent the most actively traded contract, fell 88 cents, or 1%, to $86.40. Back on Nymex February gasoline shed 0.9%, to $2.5886 a gallon, with prices down nearly 2.2% for the week, while February heating oil fell 3.9% to $3.2655 a gallon, posting a 5.8% weekly loss. February natural gas tacked on 5.6% to settle at $3.109 per million British thermal units. The contract, which expired at the settlement, ended down 2.1% for the week. March natural gas the new front-month contract, added less than 0.1% to $2.849 per million BTUs. Oil traders aimed to book profits ahead of the end of month and took a “safe position” ahead of the an OPEC+ committee meeting and the Federal Reserve’s monetary policy decision both on Feb. 1, and the European Union’s ban on imports of Russian oil products on Feb. 5, said Phil Flynn, senior market analyst at The Price Futures Group. Oil prices posted losses for the week, but that’s after posting two consecutive weeks of gains. Market analysts pointed to several factors for the recent rise in crude-oil prices, including a U.S. economy that’s holding up stronger than expected, China’s reopening after lifting COVID restrictions, and the expectation that the Organization of the Petroleum Exporting Countries and its allies won’t boost production. The OPEC+ Joint Ministerial Monitoring Committee (JMMC), which reviews the oil market and has no ability to make official production policy decisions, will meet on Feb. 1. The next full meeting of the policy-setting OPEC+ is scheduled for June. Traders will also weigh the impact of the EU ban on imports of Russian oil products, and an expected price cap on Russia oil products on Feb. 5. The coming price cap on Russian refined products proposed today of $100 per barrel on premium oil products and $45 per barrel on low value products “relieved fears of a major constraining impact set to follow from this coming price cap,” Meanwhile, natural-gas futures saw a strong rebound on Friday, the front-month contract’s expiration day, after settling Thursday at the lowest since May 2021. Prices still fell for the week, and trade over 30% lower year to date. “Mild weather forecasts, elevated production levels, and healthy inventory levels are all contributing to the sharp downtrend right now,” analysts at Sevens Report Research wrote in Friday’s newsletter. “Futures remain oversold and a potentially violent short-covering rally is possible near term, but there is no sign of a bottom forming in the natural-gas market yet.”
Mass protests grow against Israel’s far-right government -- The third round of mass protests against Prime Minister Benjamin Netanyahu’s plans to give his fascistic government absolute powers and neuter the judicial system saw increased numbers of people participating across Israel’s main cities. Around 120,000 people took part in demonstrations in Tel Aviv Saturday evening, including several thousand attending one called by the Jewish-Arab activist group Standing Together. At least 7,000 rallied opposite the President’s Residence in Jerusalem, more than 6,000 in Haifa, 1,500 in Be’er Sheva and hundreds in Herzliya and Rosh Pina. The numbers testify to the anger and concern over the trajectory of the most right-wing government in Israel’s history that took power at the end of last year. However, the leading lights of the former “government of change” and its supporters are seeking to maintain control of the movement, prioritizing the government’s plans to weaken the High Court over other broader social, economic and political issues that are also animating the movement. The new government, made up of Netanyahu’s Likud party, the fascistic and racist parties Religious Zionism, Jewish Power and Noam, and the reactionary religious parties Shas and United Torah Judaism, is committed to Jewish supremacy and apartheid rule as embodied in the 2018 Jewish Nation-State Law. This includes the permanent seizure of the Palestinian territories; Jewish prayer at the al-Aqsa Mosque; the rollback of already circumscribed anti-discrimination measures through sweeping changes to Israel’s legal system; and stepped-up police and military repression against the Palestinians and workers, Jewish and Palestinian, in Israel itself. The economic costs of implementing such an agenda mean the gutting of education, health and what remains of Israel’s public services, under conditions where 21 percent of the population live in poverty and 28 percent of children suffer from food insecurity. Implementing this agenda is bound up with Justice Minister Yariv Levin’s plans to curtail the High Court’s ability to strike down laws and allow parliament to override any such rulings. As well as appointing judges, the government would abolish the post of attorney general. This would pave the way to end Netanyahu’s trial on charges of bribery, fraud and breach of trust in three separate cases and the prospect of a lengthy prison sentence. More importantly, it would speed up settlement construction in preparation for annexing much of the West Bank.
Nine Palestinians killed in Israeli raid in Jenin - - Nine Palestinians have been killed during an Israeli military raid in the occupied West Bank - the deadliest in years - Palestinian officials say. A woman aged 61 was reported among the dead in the flashpoint town of Jenin. The Israeli military said its troops went in to arrest Islamic Jihad "terror operatives" planning "major attacks". The Palestinian presidency accused Israel of a "massacre" and later announced it had ended co-ordination with Israel on security matters. A 10th Palestinian was meanwhile shot and killed during a confrontation with Israeli troops in the town of al-Ram, near Jerusalem, as residents protested against the Jenin raid, Palestinian officials said. Tensions have recently risen in the West Bank, as the Israeli military continues what it describes as an anti-terrorism offensive that began last year following a series of deadly attacks in Israel. Heavy gunfire and explosions echoed across the crowded, urban Jenin refugee camp, as fierce battles between Palestinian militants and Israeli forces raged for three hours on Thursday morning. The Palestinian health ministry identified three of those killed as Magda Obaid, 61, Saeb Izreiqi, 24, and Izzidin Salahat, 26. Twenty people were also wounded, four of them seriously, it said. The Israel Defense Forces (IDF) said its troops entered Jenin to arrest an Islamic Jihad "terror squad", who it accused of being "heavily involved in planning and executing multiple major terrorist attacks on Israeli civilians and soldiers". It said forces surrounded a building and that three armed suspects were "neutralised" after they opened fire, while a fourth suspect surrendered. The IDF said troops were shot at by other Palestinian gunmen and returned fire, hitting targets. It added it was looking into "claims regarding additional casualties".
Palestinian teacher shot while giving first aid to militant - BBC News -Israeli forces shot dead a 57-year-old Palestinian teacher who went to give first aid to a fatally wounded militant, according to paramedics and the man's family. Jawad Bouaqneh, a father of six, was killed outside his family home in Jenin refugee camp. It came during a night of Israeli army raids in the occupied West Bank. His death raises the number of Palestinians killed this month to 17, including civilians and militants. The Israel Defense Forces (IDF) said its troops had come under heavy fire from Palestinian gunmen and they responded with live fire. It said it was aware of a report that a civilian was killed "in the area of the exchange of fire" and the incident was being "reviewed". Mr Bouaqneh's son Farid said they heard a man - later confirmed to be the fatally wounded militant - calling for help outside their home. "My father went out to help the man, to provide first aid," he said. "We dragged him inside and... they shot my father in the upper body and I moved him inside as he was covered in blood," he told Reuters news agency, standing at a doorway with a blood-stained floor. Palestinian paramedics said Mr Bouaqneh and a medic were both approaching the wounded militant outside the house."At that moment the Israeli soldiers shot high velocity bullets at them and a bullet hit the teacher... in the chest while he was trying to help the injured," the Palestinian Medical Relief Society (PMRS) said in a statement to the BBC. "[The medic]... was wearing a clear first aid vest when the shooting happened," it said, adding both the men who were shot were declared dead at hospital.
Israel, Gaza fighters trade fire after deadly West Bank raid (AP) — Gaza militants fired rockets and Israel carried out airstrikes early Friday as tensions soared following an Israeli raid in the occupied West Bank that killed nine Palestinians, including at least seven militants and a 61-year-old woman. It was the deadliest single raid in the territory in over two decades. The flare-up in violence poses an early test for Israeli Prime Minister Benjamin Netanyahu’s far-right government and casts a shadow on U.S. Secretary of State Antony Blinken’s expected trip to the region next week. Of the five rockets fired at Israel, three were intercepted, one fell in an open area and another fell short inside Gaza, the military said. It said the airstrikes targeted an underground rocket manufacturing site for Hamas as well as militant training areas. The rockets set off air raid sirens in southern Israel but there were no reports of casualties on either side. Both the Palestinian rockets and Israeli airstrikes seemed limited so as to prevent escalation into a full-blown war. Israel and Hamas have fought four wars and several smaller skirmishes since the militant group seized power in Gaza from rival Palestinian forces in 2007. Thursday’s deadly raid in the Jenin refugee camp was likely to reverberate on Friday as Palestinians gather for weekly Muslim prayers that are often followed by protests. Hamas had earlier threatened revenge for the raid. Raising the stakes, the Palestinian Authority said it would halt the ties that its security forces maintain with Israel in a shared effort to contain Islamic militants. Previous threats have been short-lived, in part because of the benefits the authority enjoys from the relationship and also due to U.S. and Israeli pressure to maintain it. The Palestinian Authority already has limited control over scattered enclaves in the West Bank, and almost none over militant strongholds like the Jenin camp. But the announcement could pave the way for Israel to step up operations it says are needed to prevent attacks. On Thursday, Israeli forces went on heightened alert as Palestinians filled the streets across the West Bank, chanting in solidarity with Jenin. President Mahmoud Abbas declared three days of mourning, and in the refugee camp, residents dug a mass grave for the dead. Palestinian Authority spokesman Nabil Abu Rudeineh said Abbas had decided to cut security coordination in “light of the repeated aggression against our people.” He also said the Palestinians planned to file complaints with the U.N. Security Council, International Criminal Court and other international bodies. Barbara Leaf, the top U.S. diplomat for the Middle East, said the Biden administration was deeply concerned about the situation and that civilian casualties reported in Jenin were “quite regrettable.” But she also said the Palestinian announcement to suspend security ties and to pursue the matter at international organizations was a mistake.
US military kills senior Islamic State official in Somalia (AP) — U.S. special operations forces have killed a senior Islamic State group official and 10 other terrorist operatives in remote northern Somalia, the Biden administration announced Thursday. The operation carried out on Wednesday targeted Bilal al-Sudani, a key financial facilitator for the global terrorist organization, in a mountainous cave complex. “This action leaves the United States and its partners safer and more secure, and it reflects our steadfast commitment to protecting Americans from the threat of terrorism at home and abroad,” Defense Secretary Lloyd Austin said in a statement. President Joe Biden was briefed last week about the proposed mission, which came together after months of planning. He gave final approval to carry out the operation this week following the recommendation of Austin and the chairman of the Joint Chiefs of Staff, Army Gen. Mark Milley, according to two senior Biden administration officials who briefed reporters on the operation on the condition of anonymity. Al-Sudani, who has been on the radar for U.S. intelligence officials for years, played a key role in helping to fund IS operations in Africa as well as the ISIS-K terrorist branch operating in Afghanistan, Austin said.
US-Backed Kurdish Delegation Meets With Assad Govt In Damascus - A Kurdish delegation representing the Syrian Democratic Forces (SDF) concluded a visit to Damascus on Friday after meeting with several representatives of the Syrian government over the prior few days, Lebanese newspaper Al-Akhbar reported. The delegation was headed by the foreign relations chief of the Autonomous Administration of North and East Syria (AANES), Badran Jia Kurd, and arrived in the capital on January 17. According to the report, the last few meetings did not result in anything significant, but the "prevailing impression" is that both sides are willing to continue along the path of dialogue, despite US warnings. "These are preliminary understandings between the two sides, on things such as Syrian territorial integrity, the national flag, and the presidency of Bashar al-Assad," it states. It adds that Washington has repeatedly warned the SDF "not to engage in bilateral dialogue with the Syrian government [and not to] think of any military solutions with it," even if the reconciliation process fails. This is based on the "realization that any military solution [between the two] may turn into a war of a civil and ethnic nature," it adds, which could be referring to a potential outbreak of direct clashes between Turkish and Kurdish ground forces, or even Syrian and Turkish ground forces. Nonetheless, sources have told the newspaper that the overall atmosphere of the visit to Damascus and the Kurdish-Syrian talks were "positive," particularly for the SDF, which reportedly appreciated Syria’s firm position not to go forward with reconciliation until there is a clear and official Turkish intent to withdraw its military forces from the country. "There is a consensus between the two sides on the need to maintain the course of dialogue while searching for points of convergence to take advanced steps in the future," the sources were quoted to have said. In the aftermath of the 18 January meeting between US Secretary of State Anthony Blinken and Turkish Foreign Minister Mevlut Cavusoglu, the SDF has expressed renewed fear over Turkey's long-promised ground offensive.
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