US crude supplies at a 35 mo low; total supplies of oil plus products at a 6 1/2 year low; DUC well backlog at 6.7 months

US crude supplies at a 35 month low; total supplies of oil plus products made from it at a 6 1/2 year low; exports of distillates at a 28 week low; vertical drilling at an 18 month high; DUC well backlog at 6.7 months..

oil prices rose for a fifth straight week as global oil supplies tightened and U.S. crude inventories fell to a 35 month low..after rising 3.2% to $71.97 a barrel last week on ongoing hurricane impacts and on tightening supplies of crude and fuel, the contract price for US light sweet crude for October delivery opened lower Monday as a broad commodity sell-off in Asia flowed into US oil markets, and tumbled more than $2 by midafternoon as worries over the potential collapse of China property giant Evergrande dragged down global financial markets and fueled strength in the U.S. dollar before recovering to close $1.68 lower at $70.29 a barrel as traders grew more risk averse, ​thus boost​ing​ the dollar​ and making oil more expensive for holders of other currencies...however, oil prices reversed th​at drop on Tuesday, rising above Monday's opening at one point, after the US lifted travel restrictions on fully vaccinated foreign travelers from 33 countries, hence boosting the prospect for increased jet fuel demand, before settling with a modest gain of 27 cents at $70.56 a barrel, as concerns about the global demand outlook counterbalanced the struggle by big OPEC producers to supply enough ​oil ​meet that demand​,​ as trading in the October oil contract expired....with oil price quotes now referencing the contract price for US light sweet crude for November delivery, which had finished Tuesday up 35 cents at $70.49 a barrel, oil opened 36 cents higher on Wednesday, after the American Petroleum Institute reported lower inventories across the board​,​ and then surged more than 2% to settle $1.74 higher at $72.23 a barrel after the EIA reported U.S. crude stocks fell to their lowest levels in almost three years and that refin​ery demand​ had​ largely​ recovered from recent storms...the oil rally continued into Thursday on the large crude draw, as the Fed signaled it could soon start slowing the pace of its bond-buying program in a first step to withdraw pandemic-era stimulus, and settled $1.07 higher at a two month high of $73.30 a barrel, as equities rallied and the US dollar weakened, boosting the appeal of commodities priced in the currency...oil prices were up nearly 1% more on Friday on a report that global output disruptions had forced companies to pull large amounts of crude out of inventories, and settled 68 cents higher at $73.98 a barrel, as the global surge in natural gas prices was expected to force some consumers to switch to oil for heating ahead of winter...oil prices thus finished with a gain of 2.8% on the week, while the November US oil contract, which had closed last week priced at $71.82, finished 3.0% higher...

natural gas prices also rose​ again​ this week, in their case for the sixth straight week, as domestic and global supply problems outweighed the impact of bearish weather patterns... after rising 3.4% to $5.105 per mmBTU last week despite a larger than expected inventory build and cooler forecasts, the contract price of natural gas for October delivery fell 12.0 cents to a fresh one-week low of $4.985 per mmBTU on Monday on forecasts for milder weather over the next two weeks, even as gas prices in Europe and Asia soared to record highs over $25, as two US LNG export facilities remained down, one for maintenance and the other in the wake of Hurricane Nicholas...natural gas prices then fell 18.0 cents to a two week low of $4.805 per mmBTU on Tuesday as cooling weather patterns and interruptions to LNG exports portended larger additions to inventories ahead of winter draws...however, natural gas prices ended Wednesday unchanged after trading higher most of the day, despite gas prices at or near record highs of around $25 per mmBTU in Europe and near $28 per mmBTU in Asia...natural gas prices rebounded vigorously on Thursday, propelled by domestic and global supply challenges as the peak winter demand season loomed​,​ and settled 17.1 cents higher at $4.976 per mmBTU​,​ after earlier rising to $5.037 per mmBTU on an injection of gas into storage that was ​​on a par with most forecasts....natural gas prices then climbed over 3% to a one-week high on Friday as some parts of the country started to crank up heaters with the coming of cooler weather even as air conditioning power demand elsewhere declined...​and on the strength of that two day rally, natural gas contract prices managed to end with a 0.7% gain on the week, even as cash prices at most major US markets ended lower..

the EIA's natural gas storage report for the week ending September 17th indicated that the amount of working natural gas held in underground storage in the US rose by 76 billion cubic feet to 3,082 billion cubic feet by the end of the week, which left our gas supplies 589 billion cubic feet, or 16.0% below the 3,671 billion cubic feet that were in storage on September 17th of last year, and 229 billion cubic feet, or 6.9% below the five-year average of 3,311 billion cubic feet of natural gas that have been in storage as of the 17th of September in recent years...the 76 billion cubic foot increase in US natural gas in working storage this week was close to the forecast for a 75 billion cubic foot addition from a Reuters survey of analysts, ​and only a ​tad more than the average addition of 74 billion cubic feet of natural gas that have typically been injected into natural gas storage during the same week over the past 5 years, and also ​slightly ​more than the 70 billion cubic feet that were added to natural gas storage during the corresponding week of 2020…    

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending September 17th indicated that despite sizeable increases in our oilfield production and our oil imports, we still needed to withdraw oil from our stored commercial crude supplies for the 7th consecutive week, and for the 33rd time in the past forty-four weeks….our imports of crude oil rose by an average of 704,000 barrels per day to an average of 6,465,000 barrels per day, after falling by an average of 44,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 185,000 barrels per day to an average of 2,809,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,656,000 barrels of per day during the week ending September 17th, 519,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was reportedly 500,000 barrels per day higher at 10,600,000 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 total an average of 14,265,000 barrels per day during the cited reporting week…

meanwhile, US oil refineries reported they were processing an average of 15,347,000 barrels of crude per day during the week ending September 17th, 960,000 more barrels per day than the amount of oil they processed during the prior week, while over the same period the EIA’s surveys indicated that an average of 669,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 422,000 barrels per day less than what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a (+422,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed...however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as they’re published, just as they’re 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 rose to an average of 6,094,000 barrels per day last week, which was 18.9% more than the 5,125,000 barrel per day average that we were importing over the same four-week period last year…the 669,000 barrel per day net decrease in our crude inventories included 497,000 barrels per day that were pulled out of our commercially available stocks of crude oil, and 172,000 barrels per day of oil that had been stored in our Strategic Petroleum Reserve, part of an emergency loan of oil to Exxon in the wake of hurricane Ida….this week’s crude oil production was reported to be 500,000 barrels per day higher at 10,600,000 barrels per day because the EIA"s rounded estimate of the output from wells in the lower 48 states was 500,000 barrels per day higher at 10,200,000 barrels per day, while a 8,000 barrel per day increase in Alaska’s oil production to 429,000 barrels per day had no impact on the reported rounded national production total….US crude oil production had hit a pre-pandemic record high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 19.1% below that of our pre-pandemic production peak, but still 25.8% above the interim low of 8,428,000 barrels per day that US oil production had fallen to during the last week of June of 2016…

meanwhile, US oil refineries were operating at 87.5% of their capacity while using those 15,347,000 barrels of crude per day during the week ending September 10th, up from 82.1% of capacity the prior week, but still a bit below normal utilization for early autumn refinery operations…while the 15,347,000 barrels per day of oil that were refined this week were 14.8% more barrels than the 13,370,000 barrels of crude that were being processed daily during the pandemic impacted week ending September 18th of last year, they were 7.1% below the 16,513,000 barrels of crude that were being processed daily during the week ending September 20th, 2019, when US refineries were operating at what was then a near normal 89.8% of capacity…

with this week’s increase in the amount of oil being refined, the gasoline output from our refineries was also higher, increasing by 372,000 barrels per day to 9,643,000 barrels per day during the week ending September 17th, after our gasoline output had decreased by 851,000 barrels per day over the prior week.…while this week’s gasoline production was 3.5% higher than the 9,315,000 barrels of gasoline that were being produced daily over the same week of last year, it was 5.8% lower than the gasoline production of 10,240,000 barrels per day during the week ending September 20th, 2019….at the same time, our refineries’  production of distillate fuels (diesel fuel and heat oil) increased by 298,000 barrels per day to 4,454,000 barrels per day, after our distillates output had decreased by 29,000 barrels per day over the prior week…but even after this week’s increase, our distillates output was a bit less than the 4,470,000 barrels of distillates that were being produced daily during the week ending September 18th, 2020, and 10.9% below the 5,000,000 barrels of distillates that were being produced daily during the week ending September 20th, 2019..

with the big increase in our gasoline production, our supply of gasoline in storage at the end of the week increased for the tenth time in twenty-four weeks, and for the 19th time in forty-four weeks, rising by 3,474,000 barrels to 221,616,000 barrels during the week ending September 17th, after our gasoline inventories had decreased by 1,857,000 barrels over the prior week...our gasoline supplies increased this week even though the amount of gasoline supplied to US users rose by 4,000 barrels per day to 8,896,000 barrels per day because our imports of gasoline rose by 444,000 barrels per day to 1,082,000 barrels per day while our exports of gasoline fell by 13,000 barrels per day to 621,000 barrels per day…even after this week’s inventory increase, our gasoline supplies were 2.6% lower than last September 18th's gasoline inventories of 227,499,000 barrels, and about 3% below the five year average of our gasoline supplies for this time of the year…

meanwhile, even with the increase in our distillates production, our supplies of distillate fuels decreased for the sixteenth time in twenty-four weeks and for the 20th time in 40 weeks, falling by 2,554,000 barrels to 131,897,000 barrels during the week ending September 17th, after our distillates supplies had decreased by 1,689,000 barrels during the prior week….our distillates supplies fell this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 629,000 barrels per day to 4,424,000 barrels per day, while our imports of distillates rose by 20,000 barrels per day to 184,000 barrels per day and even though our exports of distillates fell by 188,000 barrels per day to a 28 week  low of 579,000 barrels per day…after sixteen inventory decreases over the past twenty-four weeks, our distillate supplies at the end of the week were 26.5% below the 175,942,000 barrels of distillates that we had in storage on September 18th, 2020, and about 14% below the five year average of distillates stocks for this time of the year…

meanwhile, with our oil refining recovering from Ida faster than our oil production has, our commercial supplies of crude oil in storage fell for the sixteenth time in eightteen weeks and for the 36th time in the past year, decreasing by 3,481,000 barrels over the week, from 417,445,000 barrels on September 10th to a 35 month low of 413,964,000 barrels on September 17th, after our commercial crude supplies had decreased by 6,422,000 barrels the prior week…after this week’s decrease, our commercial crude oil inventories were about 8% below the most recent five-year average of crude oil supplies for this time of year, but were still about 26% above the average of our crude oil stocks after the third week of September over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels....since our crude oil inventories had jumped to record highs during the Covid lockdowns of last spring and remained elevated for most of the year after that, our commercial crude oil  supplies as of this September 18th were 16.3% less than the 494,406,000 barrels of oil we had in commercial storage on September 19th of 2020, and are now 1.3% less than the 419,538,000 barrels of oil that we had in storage on September 20th of 2019, but still 4.5% more than the 395,989,000 barrels of oil we had in commercial storage on September 21st of 2018…

finally, with our inventory of crude oil and and our supplies of all products made from oil, we're also going to check the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR....we find that total inventories, including those in the Strategic Petroleum Reserve and those held by the oil industry, fell by 3,788,000 barrels this week, from 1,845,415,000 barrels on September 10th to 1,841,627,000 barrels on September 17th, which is the lowest since March 6th, 2015, and hence is a 6 1/2 year low... 

This Week's Rig Count

The number of drilling rigs active in the US increased for 45th time out of the past 53 weeks during the week ending September 24th, but they were still 34.3% below the pre-pandemic rig count....Baker Hughes reported that the total count of rotary rigs running in the US increased by nine to 521 rigs this past week, which was also 260 more rigs the pandemic hit 261 rigs that were in use as of the September 25th report of 2020, but was still 1,408 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 oil market in an attempt to put US shale out of business….

The number of rigs drilling for oil was up by 10 to 421 oil rigs this week, after they had also risen by 10 oil rigs the prior week, and there are now 230 more oil rigs active now than were running a year ago, while they still amount to just 26.1% the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations fell by one to 99 natural gas rigs, which was still up by 24 natural gas rigs from the 71 natural gas rigs that were drilling during the same week a year ago, but still only 6.2% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….in addition to oil and gas rigs, a horizontal rig that Baker Hughes classifies as "miscellaneous' continues to drill in Kern county California, while a year ago there were three such "miscellaneous' rigs reported to be active...

The Gulf of Mexico rig count was up by four rigs to eight rigs this week, which is still only a partial recovery after Gulf rigs fell from 14 rigs the week before Hurricane Ida approached, with seven of this week's rigs deployed in Louisiana waters and another drilling for oil in Alaminos Canyon, offshore from Texas...but the Gulf rig count is still down by 6 rigs from a year ago, when 12 Gulf rigs were drilling for oil offshore from Louisiana and two were deployed for oil in Texas waters….however, there are still 2 rigs drilling for natural gas off the shore of the Kenai peninsula in Alaska this week, and hence the total national offshore rig count of 10 rigs is down by just 4 rigs from the 14 offshore rigs running a year ago, when there was no drilling off Alaska or off our other coasts...

In addition to those rigs offshore, a directional rig targeting oil at a depth of over 15,000 feet returned to an inland body of water in Plaquemines Parish, Louisiana, near the mouth of the Mississippi this week, one of three such inland waters rigs that were shut down in Louisiana in the wake of Ida...last week a ​new ​rig ​had ​started drilling for oil in ​the ​Galveston Bay​ area​, so the inland waters rig count is now two, up from one from a year ago..

The count of active horizontal drilling rigs was up by 5 ro 471 horizontal rigs this week, which was more than double the 224 horizontal rigs that were in use in the US on September 25th of last year, but was just over a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….at the same time, the vertical rig count was up by 1 to an 18 month high of 30 vertical rigs this week, and those were also up by 14 from the 16 vertical rigs that were operating during the same week a year ago…..in addition, the directional rig count was up by 3 to 20 directional rigs this week, but those were still down by 1 from the 21 directional rigs that were in use on September 25th of 2020….

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 September 24th, the second column shows the change in the number of working rigs between last week’s count (September 17th) and this week’s (September 24th) count, the third column shows last week’s September 17th 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 25th of September, 2020...

Louisiana's rig count was up by four with the addition of the inland waters rig in Plaquemines Parish and the three rigs in the state's offshore waters... Oklahoma's four rig increase includes an oil rig added in the Cana Woodford and an oil rig added in the Arkoma Woodford, where a natural gas rig is already deployed, as well as three more rigs in Oklahoma basins that Baker Hughes doesn't name, while at the same time an oil rig was pulled out of the Granite Wash in the area of Oklahoma adjacent to the Texas panhandle...in Texas, the Rigs by State file at Baker Hughes shows that three rigs were added in Texas Oil District 8, which is the core Permian Delaware, while a rig was pulled out of Texas Oil District 8A, which includes the northern counties of the Permian Midland, and another rig was pulled out from Texas Oil District 7C, which includes the southern counties of the Permian Midland, thus ​netting out to the one rig increase in the Permian basin...also in Texas, we find that two rigs were added in Texas Oil District 1, at least one of which was targeting the Eagle Ford shale, while a rig was pulled out of Texas Oil District 4, which could have also been an Eagle Ford rig if both of the District 1 rig additions were targeting that basin...elsewhere, the rig pulled out of Utah had been drilling in the Uintah basin, even though it's not named by Baker Hughes, because all current drilling activity in Utah has been in that basin, while the lone natural gas rig change came as the natural gas rig that started drilling into the Marcellus shale in Cattaraugus County, New York, last week was shut down this week...

DUC well report for August

Last week saw the release of the EIA's Drilling Productivity Report for September, which includes the EIA's August data for drilled but uncompleted (DUC) oil and gas wells in the 7 most productive shale regions....that data showed a decrease in uncompleted wells nationally for the 15th month in a row, as both completions of drilled wells and drilling of new wells increased, but remained below the pre-pandemic levels...for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 248 wells, falling from 5,961 DUC wells in July to 5,713 DUC wells in August, which was also 35.3% fewer DUCs than the 8,829 wells that had been drilled but remained uncompleted as of the end of August of a year ago...this month's DUC decrease occurred as 609 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during August, up from the 577 wells that were drilled in July, while 857 wells were completed and brought into production by fracking, up from the 838 completions seen in July, and up from the pandemic hit 414 completions seen in August of last year, but still down by 31.9% from the 1,258 completions of August 2019....at the August completion rate, the 5,713 drilled but uncompleted wells left at the end of the month represents a 6.7 month backlog of wells that have been drilled but are not yet fracked, down from the 7.1 month DUC well backlog of a month ago, a ratio that is now approaching that of the year prior to the pandemic, despi​te​ a completion rate that is still a third below the pre-pandemic norm...

both oil producing regions and natural gas producing regions saw DUC well decreases in August, while none of the major basins reported ​a ​DUC well increase....the number of uncompleted wells remaining in the Permian basin of west Texas and New Mexico decreased by 130, from 2,249 DUC wells at the end of July to 2,119 DUCs at the end of August, as 270 new wells were drilled into the Permian during August, while 400 wells in the region were being fracked...in addition, DUCs in the Eagle Ford​ shale​ of south Texas decreased by 43, from 912 DUC wells at the end of July to 869 DUCs at the end of August, as 60 wells were drilled in the Eagle Ford during August, while 103 already drilled Eagle Ford wells were completed.... at the same time, there was also a decrease of 27 DUC wells in the Bakken of North Dakota, where DUC wells fell from 590 at the end of July to 563 DUCs at the end of August, as 39 wells were drilled into the Bakken during August, while 66 of the drilled wells in the Bakken were being fracked....meanwhile, the number of uncompleted wells remaining in Oklahoma's Anadarko ​basin ​decreased by 19, falling from 838 at the end of July to 819 DUC wells at the end of August, as 33 wells were drilled into the Anadarko basin during July, while 52 Anadarko wells were completed....in addition, DUC wells in the Niobrara chalk of the Rockies' front range fell by 9, decreasing from 380 at the end of July to 371 DUC wells at the end of August, as 89 wells were drilled into the Niobrara chalk during August, while 98 Niobrara wells were being fracked....

among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, fell by 16 wells, from 590 DUCs at the end of July to 574 DUCs at the end of August, as 71 wells were drilled into the Marcellus and Utica shales during the month, while 87 of the already drilled wells in the region were fracked....meanwhile, the uncompleted well inventory in the natural gas producing Haynesville shale of the northern Louisiana-Texas border region was down by four to 398 DUCs, as 47 wells were drilled into the Haynesville during August, while 51 of the already drilled Haynesville wells were fracked during the same period....thus, for the month of August, DUCs in the five major oil-producing basins tracked by this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a total of 228 wells to 4741 wells, while the uncompleted well count in the natural gas  basins (the Marcellus, the Utica, and the Haynesville) decreased by 20 wells to 972 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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Utica Shale Pumped Up Promises to Valley Landowners ---- Mel Cadle once envisioned years of lucrative royalties streaming directly into his bank account from oil and gas pumped from the two wells drilled on his property. Simply put, he wanted to get rich.“It didn’t work out like it was supposed to for me,” the 87 year-old Cadle says. “I don’t have any income from these wells. I lost five acres for nothing.” The site, dominated by six large, green storage tanks, is unkempt, strewn with weeds, and sits back on a 20-acre plot he owns along Blott Road.Cadle personifies a complicated legacy of the oil and gas industry 10 years after energy companies descended on eastern Ohio in search of reserves trapped in the Utica/Point Pleasant shale formation. The development of hydraulic fracturing and horizontal drilling made it possible – and profitable – for exploration companies to tap into tight shale formations 6,000 feet deep and extend laterals thousands of feet across these thin strata.The expectations of long-standing economic benefits to the region were enormous. Energy companies touted investments in the billions of dollars for drilling programs, leasehold contracts, processors, pipelines and support services to the industry. Companies supporting the oil and gas supply chain would also relocate, augmenting further job growth in the region.For some, drilling the Utica meant up-front lease signing bonuses between $1,000 and $6,000 an acre, and many believed the big payoff would come in the form of monthly royalty checks. Early in the play, it was estimated that landowners with a producing Utica well pad on their property could reap as much as $1,000 per acre, per month.For many landowners, though, the promise of sustained wealth remains just that

Central Corridor Pipeline: Ohio Supreme Court approves Duke Energy gas pipeline - The Ohio Supreme Court has approved the construction of Duke Energy’s controversial Central Corridor Pipeline. The pipeline runs about 14 miles through Sharonville, Sycamore Township, Blue Ash, Evendale, Reading, Amberley Village and Golf Manor.Duke says the new pipeline is necessary to replace aging infrastructure. It will reduce reliance on gas from stations south of the region and allow Duke to retire peaking plants that supply gas in cold weather. Residents in the communities on the pipeline's route have long opposed the project, saying they fear for their safety and worry the pipeline will leak or explode.Critics have said the risks outweigh the pipeline's potential benefits. For example, the pipeline will only reduce reliance on one southern station by 5%, according to a Duke consultant.Reading, Blue Ash, and Neighbors Opposed to Pipeline Extension appealed the Ohio Power Siting Board decision granting Duke a certificate to construct the pipeline. They argued the board misapplied the statutory criteria governing certificate approval, decided the case on incomplete information, misweighed the evidence, and limited their ability to meaningfully participate.The court ruled while the board failed to follow its own rule by allowing Duke to submit a proposed route without also providing a fully developed alternative route, those appealing the decision couldn’t prove they were harmed by the error.

Defiance County is NW Ohio's “Grand Central Station” for pipelines -Numerous underground oil and gas pipelines have been installed through Ohio farmland over the past several years. This has left many growers wondering if this installation will have lasting impacts on their soils and crops.Last fall, OSU collected soil and yield samples from 24 different farms impacted by pipeline installation in seven counties throughout Northern Ohio (Figure 1). The Rover, Utopia, and Nexus pipelines were targeted because of their recent installation, with each pipeline installed within the last 3-4 years. Grain crops like corn and soybeans were the primary focus. OSU sampled in two major zones for this study: the right-of-way (ROW) over the pipeline, also known as the easement area, as well as an adjacent, undisturbed area of the same field. Three areas of each field were sampled along a transect. This comparative cross-section of an impacted field provides a pseudo “before-and-after” viewpoint of the field.In preliminary findings, Ohio crop yields follow similar patterns to previous studies when pipelines are installed. On average, corn grain yields decreased an average of 23.8%, silage corn decreased an average of 28.8%, and soybean yield decreased an average of 7.4% over the pipeline compared with adjacent areas. Soils within the ROW had more rock fragments, lower soil moisture, and had a higher resistance to penetration which indicates lasting forms of soil compaction.

U.S. gas producer Gulfport Energy explores sale -sources – Gulfport Energy Corp., the US natural gas exploration and production company that emerged from bankruptcy earlier this year, is exploring strategic options, including a potential sale, according to people familiar with the matter. The Oklahoma City-headquartered company, which has a market value of about $1.6 billion, is working with an investment bank on its options and potential takeover interest to help with, the sources said. No deal is certain, the sources said, asking not to be identified as the matter is confidential. Gulfport declined to comment. Gulfport was pushed into bankruptcy last year as the COVID-19 pandemic temporarily decimated demand for energy and left it unable to pay its debts. Control of Gulfport was handed over in May to its creditors, many of them hedge funds, upon completion of the Chapter 11 bankruptcy process, which swapped nearly $1.2 billion of debt for shares in the company. US natural gas prices hit a seven-year high earlier this month, prompting gas producers to explore sales. Gulfport has 266,000 net acres in the Utica Shale Basin of Ohio and the SCOOP Formation of Oklahoma. It estimated in a presentation to investors in August that 90% of its 2021 production would be natural gas, with 7% being natural gas liquids. Gulfport is currently seeking to renegotiate two contracts with pipeline companies. Scraping them can help save money. The company estimated in an August presentation that annual gross transportation fees could drop 55% to $131 million if both contracts were replaced with cheaper arrangements.

Weekly Shale Drilling Permits for PA, OH, WV: Sep 13-19 - Marcellus Drilling News - A nice bump up (finally) in the number of permits to drill new shale wells in the M-U, although it’s a lot of wells for a relatively few well pads. Pennsylvania issued 19 new permits across five pads in both the northeast and southwest portion of the play, including 8 permits for a single Cabot Oil & Gas pad in Susquehanna County. Ohio issued just 3 new permits, all to Encino Energy for a single pad in Carroll County. And West Virginia issued a surprisingly high 18 permits to two drillers on three pads in two counties: Marshall and Monongalia.

API President Mike Sommers highlights role of Pennsylvania natural gas and oil --American Petroleum Institute (API) President and CEO Mike Sommers today spoke to the Economic Club of Pittsburgh where he highlighted the importance of Pennsylvania’s robust natural gas and oil industry to the nation’s efforts to provide affordable, reliable energy while continuing to reduce greenhouse gas emissions. Surrounding Climate Week NYC, Sommers underscored how natural gas and oil should be part of the solution to shaping a lower-carbon future globally. “Pittsburgh is one of the energy capitals of the world. Without Pennsylvania energy resources, America wouldn’t be the world’s top producer of natural gas and oil – reversing decades of foreign imports,” said API President and CEO Mike Sommers. “Without support from Pennsylvania natural gas, America couldn’t have reduced power-related CO2 emissions 40% in the past 15 years – outpacing coal as the top source of U.S. electricity generation. And…America wouldn’t be in a position to continue exporting environmental progress – in the form of LNG – all over the world to power both a growing population and reverse energy poverty.” As the second largest state producer of natural gas in the U.S., Pennsylvania energy production is powering local economies throughout the Commonwealth. The industry supports nearly 500,000 direct, indirect and induced jobs in Pennsylvania, and generates an additional 3.7 jobs elsewhere in the state. Natural gas and oil also contribute $78.4 billion to Pennsylvania’s GDP, or nearly 10 percent to the state’s total. “But the transformation isn’t limited to Pennsylvania. The shale revolution has spread and revitalized America. Import terminals became export terminals. America reduced its trade deficit. U.S. greenhouse gas emissions are at generational lows. We reduced our energy dependence on foreign nations and unreliable regimes. And in the process, the state’s environmental progress transformed the world. In 2019, federal estimates show that natural gas from Pennsylvania’s Marcellus and Utica Shale has been shipped out to 20 different countries,” Sommers continued. As world leaders convene this week at the United Nations General Assembly to discuss policies and actions to tackle climate change, Sommers discussed what the natural gas and oil industry is doing to provide meaningful solutions to solve this problem. He stated, “The challenge of meeting the world’s growing energy needs at the same time that we are building a lower-carbon future is massive, intertwined and fundamental. Our industry also views it as the opportunity of our time, and one we are uniquely positioned to meet with our scale and expertise, aided by smart policies and relentless innovation.”

PennEast drops plan for pipeline on public lands - PennEast Pipeline Co. has dropped a plan to use New Jersey state lands for its controversial natural gas pipeline — at least for now — dealing a major blow to the long-delayed project in the state. The company’s decision not to pursue eminent-domain claims on 42 parcels of publicly owned land was announced in an agreement with the Attorney General’s office and recorded in a brief notice sent on Sept. 20 to the Third Circuit Court of Appeals, which is overseeing the company’s claims. “The parties to these consolidated matters have agreed in principle to a stipulated voluntary dismissal of these matters,” the notice said, referring to the eminent-domain claims. In plain language, the notice means that PennEast won’t seek to seize the lands to build the pipeline, said Leland Moore, a spokesman for the AG’s office, which argued against the company’s use of public lands before the U.S. Supreme Court earlier this year. The nation’s highest court had sided with PennEast, ruling that it had the right to use eminent domain to acquire the state land it needed for the project.Pat Kornick, a PennEast spokeswoman, would not say whether the agreement means the company has abandoned its plans for the New Jersey section of the pipeline, which has twice been denied state environmental permits, and has roused strong opposition in the communities where it would be built.

Pols Call on Hochul to Revisit Rate Hike - A group of 31 state and local officials on Friday called on the governor to review a state commission decision that will result in customers paying for fossil fuel projects, including parts of a controversial pipeline in Brooklyn.Representing Brooklyn, Queens, Manhattan and Staten Island, the signatories of the letter — including Rep. Carolyn Maloney, and State Sens. Julia Salazar, Jabari Brisport, Liz Krueger and Diane Savino — ask Gov. Kathy Hochul to uphold the state’s climate law, which mandates cuts of greenhouse gas emissions in a way that provides substantial benefits to “disadvantaged communities.”“At a time when we are seeing the impacts of climate change and New Yorkers owe nearly $2 billion in unpaid debt to corporate utilities it is unconscionable to force 1.9 million customers to pay for new pipelines and other fracked gas projects,” the letter reads.The missive follows the state Public Service Commission’s August approval of a gas bill rate increase averaging about $5 per month for National Grid customers in New York City and on Long Island.The hike would pay for some of the embattled Metropolitan Reliability Project pipeline and other infrastructure upgrades, as well as programs for energy efficiency, electrification and to encourage less demand for gas, according to the approved settlement.The natural gas pipeline is slated to run nearly seven miles, from Brownsville to Greenpoint, with four of five phases already operational. The final phase is awaiting further review and approval before it’s built.

Federal judge: $53.5 million settlement precludes Ritchie County royalty claims - A federal judge has ruled in favor of one of West Virginia’s largest natural gas producers looking to block gas leaseholders from going after the company in Ritchie County Circuit Court. U.S. District Judge John Preston Bailey sided with Pittsburgh-based EQT Corp. after it asked the U.S. District Court for the Northern District of West Virginia to block gas leaseholders from proceeding with their circuit court litigation against EQT. EQT had argued that a 2019 $53.5 million class-action settlement agreement to resolve a lawsuit that alleged the company was shorting thousands of state residents and businesses on gas royalty payments prohibited further action against the company for royalty claims. In the litigation, the plaintiffs are residents Philip Williams, Timothy Williams, Diana Weiss and Mahlon Harris, who own mineral interests on 500 acres in the Clay district of Ritchie County. They sued EQT in circuit court seeking compensatory damages for alleged breach of contract and money they say was unlawfully deducted by EQT from their royalties. The plaintiffs said they were not notified about the class-action lawsuit and never had an opportunity to opt out of the settlement. But Bailey ruled Sept. 14 that due process “only requires that notice be reasonably calculated to reach” members of a class, “not that it actually succeeds in reaching every individual class member.” The judge found the effort to notify the plaintiffs of the agreement was sufficient. “[I]t is a shame that these folks won’t be able to have their day in court on the egregious actions of EQT and the way that they’ve been cheated by a large out-of-state oil and gas corporation,”

Southwest Virginia landowners still fighting pipeline's use of eminent domain -Nearly four years after the Mountain Valley Pipeline began a legal process to take private land for the project, the controversial practice is still being challenged in court. A federal appeals court ruled this week that arguments from a group of landowners “are not so clear” as to merit the immediate reversal of an lower-court opinion that favored the pipeline. However, the U.S. Circuit Court of Appeals in Washington, D.C., asked attorneys to submit additional written arguments before it makes a final decision. Cletus Bohon, who owns property in Montgomery County that the natural gas pipeline cuts through, is the lead plaintiff in a lawsuit that contends the Federal Energy Regulatory Commission should not have given a private venture the right to seize property by eminent domain. Similar legal challenges have been dismissed in the past. When a Washington, D.C., federal judge did the same for Bohon’s case in May 2020, he called it “the latest trickle in a veritable flood of litigation” against Mountain Valley. But Bohon appealed, and the case remains alive. In a brief opinion Wednesday, the appellate court asked that the next round of briefs submitted by lawyers address how the case is impacted by a recent U.S. Supreme Court decision that allowed a pipeline’s seizure of state-owned land in New Jersey. Shortly after FERC approved Mountain Valley’s request in 2017 to build a 303-mile pipeline that will pass through Southwest Virginia, the company filed suit against about 300 property owners who had refused to sell easements for the project to pass through their rural land. A federal judge in Roanoke granted Mountain Valley immediate possession of the parcels in early 2018. That cleared the way for the start of construction that continues today, and Judge Elizabeth Dillon’s ruling was upheld on appeal. An attorney for the landowners in the more recent case, who could not be reached Friday, has said earlier that they are hopeful their lawsuit will help others, even if it is too late to stop Mountain Valley. The lawsuit argues that Congress improperly delegated legislative power to FERC, which then gave Mountain Valley the power of eminent domain after determining there was a public need for the natural gas that it will deliver to markets on the East Coast. In court papers, attorneys for Mountain Valley said the landowner’s arguments were “simply a rehashing of the same flawed theories” that have been rejected in the past.

Proposed Chickahominy Pipeline map released; county officials complain about lack of information - A map of the proposed Chickahominy Pipeline through Louisa, Hanover, Henrico, New Kent and Charles City County was released this week, although officials from several counties complained they have been unable to obtain more details about the project. “We have attempted to reach out to the company’s representatives to get no response, and the only information that we have received from the company is what was required by the State Corporation Commission,” said Cari Tretina, chief of staff for Henrico County Manager John Vithoulkas. “The only way Henrico County actually received any information about the pipeline was either from our residents who made us aware and also Louisa County.” Louisa County supervisors also described a dearth of information about the proposal at a Sept. 20 board meeting. Supervisor Fitzgerald Barnes said his biggest concern was whether the pipeline would be able to exercise eminent domain. “Do they have eminent domain or not?” he asked. “That’s a huge question that has to be answered … because that’s really going to affect our citizens.” The project first came to public attention this July when residents of the five counties received letters from Chickahominy Pipeline, LLC asking for permission to enter their property to conduct surveys for a possible 24-inch gas pipeline, which shares an address and registered agent with Chickahominy Power, LLC, a subsidiary of developer Balico, LLC, which is planning a proposed 1.6-gigawatt natural gas power plant in Charles City County. Tretina said that sending letters to landowners before contacting county officials about a potential infrastructure project is “completely the opposite way that we’re used to engaging with other companies.” She estimated that if the pipeline is built, about 18 to 20 property owners in the northeastern part of Henrico would be impacted. If constructed, the pipeline would provide natural gas to the proposed Chickahominy Power plant in Charles City County, which is being developed by Balico, LLC.

U.S. natgas futures fall to one-week low on milder forecasts (Reuters) - U.S. natural gas futures fell to a fresh one-week low on Monday on forecasts for milder weather over the next two weeks. Traders noted U.S. prices fell even though gas in Europe and Asia soared to record highs over $25 per million British thermal units (mmBtu) versus just $5 for the U.S. fuel, prompting buyers around the world to keep purchasing all the liquefied natural gas (LNG) the United States can produce. The problem for Europe is, the United States is already producing as much LNG as it can. The amount of gas flowing to U.S. LNG export plants has averaged 10.5 billion cubic feet per day (bcfd) so far in September, the same as in August, according to data provider Refinitiv. That compares with a monthly record of 11.5 bcfd in April. Traders said U.S. LNG exports would have been higher this month but were reduced by a brief shutdown at Freeport LNG's plant in Texas during Tropical Storm Nicholas and the start of maintenance at Berkshire Hathaway Energy's Cove Point in Maryland on Monday. U.S. front-month gas futures fell 12.0 cents, or 2.4%, to settle at $4.985 per mmBtu, their lowest close since Sept. 10 for a second day in a row. After the U.S. front-month remained in overbought territory for much of the past two weeks, gas speculators last week cut their net long positions on the New York Mercantile and Intercontinental Exchanges for the first time since August in anticipation of the price drop that started late last week following a bigger-than-expected storage build, according to data from the Commodity Futures Trading Commission (CFTC). U.S. gas stockpiles, however, were still about 7.1% below the five-year normal for this time of year. Low inventories, like those in Europe, helped boost U.S. gas prices to their highest in seven years early last week. Refinitiv said gas output in the U.S. Lower 48 states fell to an average of 90.6 bcfd so far in September, down from 92.0 bcfd in August, due mostly to Ida-related losses along the Gulf Coast. That compares with a monthly record high of 95.4 bcfd in November 2019. About 0.6 bcfd, or 27%, of gas production in the U.S. Gulf of Mexico remained shut-in since Ida, according to government data on Friday. With the coming of milder weather, Refinitiv projected average U.S. gas demand, including exports, would fall from 86.8 bcfd this week to 83.4 bcfd next week as air conditioning use declines. This week's forecast was higher than Refinitiv expected on Friday.

Cove Point, Freeport Production Curbed as Energy Crisis Deepens in Europe — LNG Recap -- Natural gas prices continued to rise in Asia and Europe on Monday as competition intensified for limited liquefied natural gas (LNG) cargoes on the spot market with two U.S. facilities down. Freeport LNG in Texas continues to experience production issues after Tropical Storm Nicholas knocked out power last week. The facility has not fully restarted operations, a spokesperson said Monday. Just two trains are back online after a third tripped when the plant restarted over the weekend. Meanwhile, the Cove Point LNG terminal in Maryland stopped operations Monday for a 20-day stretch of maintenance. European natural gas prices continued climbing higher Monday after benchmarks in the UK and Northwest Europe broke through the $24/MMBtu mark last week. The Dutch Title Transfer Facility and UK National Balancing Point contracts again set records Monday when both finished above $25 for October. The market was squeezed further Monday when Russia did not book additional pipeline transportation capacity through Ukraine at a monthly auction. Traders also took just a small fraction of the capacity offered on the Yamal-Europe pipeline. Skyhigh power and natural gas prices prompted chemical and fertilizer producers to curb some of their output last week. Other manufacturers took similar steps. “These extortionate prices are forcing some UK steelmakers to suspend their operations during periods when the cost of energy is quoted in the thousands per megawatt hour,” said UK Steel Director General Gareth Stace. “…Even with the global steel market as buoyant as it is, these eye-watering prices are making it impossible to profitably make steel at certain times of the day and night.”

U.S. natgas futures hold at two-week low despite soaring global prices (Reuters) - U.S. natural gas futures held steady at a two-week low on Wednesday as forecasts for lower demand next week than previously expected offset continued strong interest in U.S. liquefied natural gas (LNG) arising from soaring global gas prices. Front-month gas futures remained unchanged to settle at $4.805 per million British thermal units (mmBtu), the same as on Tuesday, when the contract closed at its lowest since Sept. 7. Since hitting a seven-year high last week, the front-month has shed about 12% on growing expectations the United States will have enough gas in storage for the upcoming winter heating season. U.S. gas stockpiles were about 7.1% below their five-year normal for this time of year. Analysts said the storage situation was much worse in Europe, where prices have soared to record highs primarily because stockpiles in some countries were 20% or more below normal for this time of year. With gas prices at or near record highs of around $25 per mmBtu in Europe and near $28 in Asia, versus just about $5 in the United States, traders noted that buyers around the world were purchasing all the super-chilled gas the United States can produce. Despite reductions at several plants this month, data provider Refinitiv said, the amount of gas flowing to U.S. LNG export plants was only down to an average of 10.4 billion cubic feet per day (bcfd) so far in September from 10.5 bcfd in August. That small LNG feedgas decline came despite a three-week maintenance outage at Berkshire Hathaway Energy's Cove Point in Maryland, a brief shutdown last week at Freeport LNG's plant in Texas during Tropical Storm Nicholas and what is expected to be a brief reduction this week at Cameron LNG's plant in Louisiana. No matter how high global prices rise, however, the United States only has the capacity to turn about 10.5 bcfd of gas into LNG. Global markets will have to wait until later this year to get more from the United States when the sixth liquefaction train at Cheniere Energy Inc's Sabine Pass and Venture Global LNG's Calcasieu Pass in Louisiana will likely start producing LNG in test mode. About 0.5 bcfd, or 24%, of gas production in the U.S. Gulf of Mexico remained shut-in since Ida hit Louisiana on Aug. 29, government data showed on Tuesday.

Henry Hub prices remain higher than Northeast hubs - The U.S. benchmark natural gas spot price at the Henry Hub in Louisiana remains at a premium to Northeast natural gas hubs. The premium increased in the third quarter of 2020, as total Appalachian supply exceeded demand growth and storage levels were above average. Although storage levels fell in 2021, other factors, such as record high Gulf Coast LNG exports, winter freeze-offs in Texas and neighboring producing areas, and Appalachian pipeline outages kept the Henry Hub price premium over Northeast hubs higher than 2018-2020 annual averages in 2021.In 2020, total Appalachian supply and net imports together were 3% higher than 2019 levels, while Northeast demand remained low, partly as industrial and commercial activity fell following the onset of the COVID-19 pandemic. The natural gas that is not consumed in the region or exported out of the region is injected into storage. The Eaststorage region has about 1 trillion cubic feet of storage capacity to balance seasonal demand against supply. In the first week of September 2020, before the winter withdrawal season started, storage levels were 6% above the five-year average, at 803 billion cubic feet (Bcf). With production growth continuing throughout winter of 2020, and demand remaining muted, natural gas in storage in the East reached near weekly 2016-2020 five-year highs.While total Appalachian supply and net imports keeps rising, natural gas demand has recently increased as well. Total Appalachian supply and net imports grew by 6% to 30.8 Bcf/d during the first half of 2021, compared to same time last year. This year’s first half demand totaled 20.9 Bcf/d, or 0.8 Bcf/d higher than last year’s first half values, according to demand data from IHS Markit.With rising demand, storage levels have fallen below their five-year average and Appalachian prices have risen. For the first eight months of 2021, prices in the Eastern Gas South averaged $2.60 per million British thermal units (MMBtu), or $1.18/MMBtu higher than the same period last year. Other Northeast hubs followed similar trends. Henry Hub prices have also increased in 2021, and consequently still trades at a premium to Northeast hubs. Several factors contributed to this Henry Hub premium. In 2021, record LNG exports out of U.S. terminals located around the Gulf Coast increased South region demand. This February’s winter-freeze disproportionately increased prices in the South Central and Southeast, where processing facilities are not as well winterized as those in the Northeast. In addition, recent pipeline outages reduced southbound capacity out of the Appalachia basin.Although pipeline capacity out of Appalachia has grown, it has not kept pace with recent production growth. The 2.0 Bcf/d Mountain Valley Pipeline is scheduled to come online in 2022, but it is mostly an intra-region and may not affect basis differentials substantially.

EIA Reports Build of 76 Bcf in Natural Gas Inventories - After Natural gas futures fell under $5.00 in manic trading ahead of EIA reported a build of +76 Bcf of working gas in storage. With natural gas production in the Gulf of Mexico still shut-in. Output was already trailing consumption with elevated demand from both Europe and Asia for U.S. exports of LNG. Cooling Degree Days (CDDs) came in at 60 vs 52 normal and 88 in the prior week. This week's forecast: This week, CPC predicts CDDs will hold at 60 vs 44 normal. The National Hurricane Center said over the next few months as the 2021 Atlantic hurricane season reaches its peak. The National Oceanic and Atmospheric Administration raised the number of named storms forecast to 15-21 named storms, including seven to 10 hurricanes and three to five major hurricanes, up from its May prediction for 13-20 named storms and six to 10 hurricanes, though its prediction of major hurricanes was unchanged. With storms we watch Gulf of Mexico production and the impact on demand with the increasingly tight U.S. gas market. In 2020 back-to-back hurricanes in Louisiana knocked offline the Cameron LNG facility, as well as thousands of other Gulf Coast electricity customers for about a month. Wind capacity is up more than 15 GW versus 2020, wind utilization has been below normal over the last two months, with July wind utilization realizing around 5% below normal and setting a new five-year minimum for the month. - Reic Fell of Wood McKenzie. However, it is unlikely that wind utilization would remain that far below normal over the balance of the summer. Hydro output has averaged close to 7 average GW hours below the five-year average so far this summer, according to Fell. This is being driven by a severe western drought, which has added nearly 1 Bcf/d in gas burn relative to the five-year average.

Natural Gas Futures Rebound as Supply Worries Mount - -- Natural gas futures rebounded with vigor on Thursday, propelled by domestic and global supply challenges as the peak winter demand season looms. The October Nymex contract shot up 17.1 cents day/day and settled at $4.976/MMBtu. November jumped 18.8 cents to $5.043. A day earlier, the prompt month broke even, ending a four-day losing streak that was driven by forecasts for mild weather into early October. NGI’s Spot Gas National Avg. gained 3.5 cents to $4.715. Anemic production levels and below-average gas in storage, with only a few weeks before heating demand revs up, moved to the forefront of traders’ minds Thursday, sparking a new rally. Only last week, futures touched seven-year highs above $5.00, fueled by supply crunch worries, with both Europe and Asia scrambling to fortify stockpiles and ensure ample fuel levels to power furnaces and industrial plants this winter. The U.S. Energy Information Administration (EIA), in the latest storage report Thursday, renewed concerns about domestic supplies, as well. Utilities injected 76 Bcf natural gas into underground storage for the week ended Sept. 17, EIA reported. The print was essentially on par with market expectations. However, it left supplies below historic norms at a time when global demand for U.S. exports of liquefied natural gas (LNG) is soaring ahead of winter. Prior to the report, major polls showed analysts looking for a mid-70s build. In the year-earlier period, EIA recorded a 70 Bcf injection, while the five-year average injection was 74 Bcf.

U.S. natgas futures rise on cooler weather, rising heating demand - (Reuters) - U.S. natural gas futures climbed over 3% to a one-week high on Friday as some parts of the country start to crank up their heaters with the coming of cooler weather and as near record global gas prices keep demand strong for U.S. liquefied natural gas (LNG) exports. On their second to last day as the front-month, gas futures for October delivery rose 16.4 cents, or 3.3%, to settle at $5.140 per million British thermal units (mmBtu), their highest close since Sept. 16. November futures, which will soon be the front-month, were up 16 cents to $5.20 per mmBtu. For the week, the front-month rose less than 1%, putting the contract up for a fifth week in a row. During that time the front-month gained about 30% on record global gas prices and the slow return of production after Hurricane Ida hit Louisiana in late August. With the coming of cooler weather, Refinitiv projected average U.S. gas demand, including exports, would fall from 86.2 bcfd this week to 82.7 bcfd next week as air conditioning use declines before climbing to 84.4 bcfd in two weeks as heating use rises. The forecast for next week was higher than Refinitiv expected on Thursday. With gas prices near record highs of around $24 per mmBtu in Europe and $27 in Asia versus just about $5 in the United States, traders said buyers around the world would keep purchasing all the LNG the United States could produce. Despite reductions at several plants this month, the amount of gas flowing to U.S. LNG export plants slipped modestly to an average of 10.4 bcfd so far in September from 10.5 bcfd in August, data provider Refinitiv said. That small LNG feedgas decline came despite a three-week maintenance outage at Berkshire Hathaway Energy's Cove Point facility in Maryland, a brief shutdown at Freeport LNG's plant in Texas during Tropical Storm Nicholas and a brief reduction this week at Cameron LNG's plant in Louisiana. Prices in the United States have remained much lower in part because the market expects the country to have enough gas in inventory for the winter. Stockpiles were about 7% below normal for this time of year in the United States versus over 20% below normal in some European countries. But gas prices in some parts of the United States were still expected to soar this winter. Analysts expect much higher prices in New England due to pipeline constraints and a reliance on what is now expensive LNG and in California where a severe drought, wildfires and lack of battery backup for intermittent renewable power sources has boosted the use of gas-fired power plants.

Can Higher Crude Oil Prices Revive The Tuscaloosa Marine Shale Play? --A long, long time ago — or, more precisely, in the spring of 2014, when WTI was selling for more than $110/bbl — a handful of exploration and production companies were convinced they were onto something big in southwestern Mississippi and east-central Louisiana. There, they believed, the Tuscaloosa Marine Shale (TMS) was poised to become the next Bakken, the U.S.’s premier shale play at the time, but even better for producers seeking more robust crude prices because of TMS’s very low gas-to-oil ratio — an oil cut north of 92%! –– and proximity to Gulf Coast refineries. While there had been a host of failed efforts by producers to wring out large volumes of premium-priced Louisiana Light Sweet (LLS) oil from the marine shale’s sedimentary silts and clays, the E&Ps felt in their bones that they were finally “cracking the code.” Then, at just the wrong time, came an oil price crash that set the whole industry back on its heels and activity in the TMS quickly slowed to a crawl. As we discuss in today’s RBN blog, an even smaller cadre of Tuscaloosa Marine Shale true believers is now banking on a production revival in the core of the play. As we said in our first blog on the TMS back in 2013, the sedimentary rock formation — generally only a couple of hundred feet thick — lies 12,000 to 18,000 feet below the surface of a swath of central Louisiana and southwestern Mississippi (purple-shaded area in Figure 1). A 1997 study by the Louisiana Geological Survey estimated the 8-million-acre shale play has potential reserves of 7 billion barrels of oil, which would make it among the most hydrocarbon-rich regions in the U.S. The dark gray marine shale within the formation consists of fine-grained, organic-rich sedimentary silts and clays deposited more than 80 million years ago. The Eagle Ford deposits in South Texas were formed at about the same time, but they are closer to the surface — 5,000 to 7,000 feet, typically — and the rock is more brittle and far more permeable. The sediment that washed down the Mississippi River gave the TMS a different geological composition that makes it much more difficult to recover oil from it. The depth and low permeability of the play’s soft rock and clay scared off many a driller, as did the thin layer within it that offers natural fracturing (and increased permeability).

Iberia Parish Council passes resolution in support of resuming federal oil & gas leases– The Iberia Parish Council passed a resolution at Wednesday’s meeting, in support of resuming federal off-shore leasing in the Gulf of Mexico. The council wants everyone to know, especially elected leaders in Washington, D.C., this is the lifeblood of Acadiana’s economy. “”In Iberia Parish, the oil and gas industry was the number one revenue generator. It has been for decades,” said M. Larry Richard, president of Iberia Parish. “It’s a big deal for the parish, and it still is, if we can get it back.” The Biden administration put a hold on all lease sales earlier this year. Louisiana, and several other states, the challenged the president’s moratorium in federal court. A federal judge ordered an injunction. Since then, the U.S. Government has appealed the order, and it is currently under consideration. The Department of the Interior, which runs the oil and gas land lease program, recently told congress that there was still a hold in place. The states then filed a contempt of court brief against the feds. Shortly thereafter, one lease in the Gulf was approved.

Louisiana gets judge's OK to join case over oil drilling auctions -A federal judge in Washington, D.C., is allowing Louisiana to intervene in a lawsuit if it is challenging an upcoming drilling lease auction, giving the stifling proponent of the federal oil and gas leasing program another chance to defend it in court.Last month, the Biden administration announced its intentions to comply with a court order requiring it to resume lease auctions, citing environmental advocates like Friends of the Earth. District Judge Randolph Moss of the United States on Wednesday authorized Louisiana Attorney General Jeff Landry to join the case as a defendant in the Interior Department's delegation (DOI).Brittany Miller, the spokesperson for Friends of the Earth, declined to comment. Earthjustice's lawyers represent it. Tyler Cherry, DOI's spokesperson, also declined to comment.Cory Dennis, the AG's office''Spokesman for Landry, said the decision was gratifying to the company. "Joe Biden's unlawful attempt to halt these sales only punishes hard-working Americans with higher gasoline and electric bills, and forces the Nation to depend on foreign energy," he added. Friends of the Earth and its co-plaintiffs sued on Aug. 31 to block the federal government from holding a fall lease sale that would provide almost all available, unleased blocks in oct. 90-million-acre area in the Gulf of Mexico. The lawsuit claims that the planned sale violates the National Environmental Policy Act because its authorization relies on a poor and outdated analysis of its environmental implications. Last week, Louisiana sued to enter the case, argumenting in a brief that if savagery won "contradict" revocation of federation drilling auctions in another case injunction that would halt the ostracization of federal drilling projects. The injunction is still in effect pending the final resolution of the lawsuit in Lake Charles, Louisiana, federal court, which was brought by Louisiana and 12 other states over Biden's freeze on new drilling auctions, or awaiting orders from higher courts. The administration has filed a complaint against him.

Over 16% US Gulf oil, 24% offshore natgas output remains shut in | ICIS --Over 16% of the US crude oil production and 24% of the offshore natural gas output remained shut on Wednesday, according to US Bureau of Safety and Environmental Enforcement (BSEE). The following table shows the number of platforms and rigs evacuated, including the total of oil and natural gas that have been shut in.US supply worries have persisted following the production disruption caused by Hurricane Ida in late August.The percentage of oil and natural gas production shut in has continued to slowly decrease. Crude oil has decreased .46% while offshore gas production has decreased 1.15% from Tuesday.US crude oil inventories decreased 3.5m barrels for the week ended on 17 September, according to the Energy Information Administration’s (EIA) latest report.Inventories are about 8% below the five-year average for this time of year at 414m barrels.On Monday, Shell announced that its WD-143 platform will remain offline until the end of the year due to “significant structural damage” from Hurricane Ida.Offshore oil wells account for 17% of the nation’s crude oil production, while federal Gulf of Mexico production is about 3% of total US dry natural gas production.Total working gas in storage is 3.01 trillion cubic feet (tcf), down nearly 17% from last year, said EIA in its storage report.

Oil-covered birds found after Hurricane Ida rehabilitated, released - The first two birds among dozens being rehabilitated after being stained with oil in the aftermath of Hurricane Ida were released at the Bayou Teche National Wildlife Refuge in Franklin. The Louisiana Department of Wildlife and Fisheries has documented more than 100 oiled birds with some degree of their bodies stained with oil, the department said.At least 34 birds have already been captured and are at a rehabilitation facility in New Iberia. The agency will continue its capturing and rehabilitation efforts to save the oil-coated birds, found at the Alliance Refinery in Belle Chasse days after Ida.The first two, a purple gallinule and a king rail, were released Thursday. Wildlife and Fisheries said the secretive marsh birds tend to hide under vegetation upon release. A number of oil-coated birds documented at the Alliance Refinery have been seen primarily within heavy pockets of crude oil and nearby flooded fields and retention ponds, according to Wildlife and Fisheries. They include black-bellied whistling ducks, blue-winged teal and a variety of egret species. Other wildlife, including alligators and river otters, have also been seen with some level of oiling, the agency said. Rescue efforts began with documenting birds the Sunday following the storm, with an initial visit to the refinery. That visit was implemented in partnership with the Louisiana Oil Spill Coordinator's Office, the Louisiana Department of Environmental Quality, the U.S. Coast Guard and the U.S. Fish and Wildlife Service.

Coast Guard continues Hurricane response in Ida aftermath - The Coast Guard is continuing efforts to reopen waterways impacted by Hurricane Ida in the areas of Bayou Lafourche, Houma Navigation Canal and portions of the Gulf Intracoastal Waterway.To date, 25 obstructions have been identified in the Bayou Lafourche channel, the Coast Guard said. They are mainly fishing vessels, crew vessels and offshore supply vessels.Additionally, 30 submerged targets have been identified in the Houma Navigation Canal. Fifteen of those targets in the Houma Navigation Canal have been cleared or removed, the Coast Guard said. The Coast Guard continues to coordinate operations with the U.S. Army Corps of Engineers to identify and remove waterway obstructions.The Coast Guard also continues to receive and investigate all reports made to the National Response Center, with crews working to identify and prioritize threats to the environment and navigable waterways through overflights and surface inspections of areas impacted by the storm.Coast Guard Sector New Orleans oversees 1,082 total aids to navigation in their area of responsibility. Of the 1,082 aids, 384 have been identified as damaged or as offline as a result of Hurricane Ida. Aids to navigation teams have restored or have made temporary corrections to 277 of those aids, which is 72 percent of those identified.The Coast Guard is working closely with the state of Louisiana, Environmental Protection Agency and Louisiana Department of Environmental Quality to respond to reports of pollution. As of September 16, the Coast Guard had assessed 2,259 out of 2,464 reports of pollution. Of the reports, there are:

• • 1,217 reports that have been closed or transferred to appropriate jurisdictions;
• • 326 reports where the reports were unverified as there was no remaining evidence of pollution on-site;
• • 602 reports where the Coast Guard is actively supervising the mitigation efforts that are being carried out by responsible parties; and
• • 23 reports under investigation by the Coast Guard.

These numbers will change as the environmental response teams continue to assess and reprioritize targets. Those who have uncompensated removal costs or damages resulting from an oil spill to the navigable waters or the threat of an oil spill to the navigable waters may be entitled to compensation from the Oil Spill Liability Trust Fund.

Oil refineries recovering from Ida; power outages led to so-called “stranded fuel” - Oil refineries impacted Hurricane Ida and power outages are recovering. At one point nearly a dozen refineries were offline and because of power outages they had so-called stranded fuel. Nathan McBride is Regulatory Affairs Manager for the Louisiana Mid-Continent Oil and Gas Association. “There’s really eight between Baton Rouge and New Orleans, but they brought the Krotz Springs refinery in as well because it could have an impact on the supply,” he said. McBride said most of the impacted refineries are back in operation. “I think the vast majority are back online. There are a couple that were, they’re still ongoing damage assessments and things like that. I believe it’s two of them at this point that are still undergoing damage assessments to decide, you know, how to bring them online safely,” said McBride. Professor Pierre Conner is Executive Director of Tulane University’s Energy Institute. “ Most of those nine Louisiana refineries that were shut down are back up and running and the refineries are getting back up actually sooner than production out in the Gulf of Mexico, kind of a reversal to what had happened during Katrina,” said McBride. Still, Conner said some refineries turned to the nation’s Strategic Petroleum Reserve. “A couple of the refineries did take advantage of the SPR for some ability to bring crude oil in as they were getting restarted,” he said. “Refineries had fuel in tankage on-site, even the ones who happened to lose power especially down in the New Orleans area, so there was fuel in tankage, so the first hurdle we had to clear was get power to the terminals, otherwise known as racks at the refineries so that they could pull that fuel out of tankage and dispense it into the local markets, so you may have fuel at the refinery even though your refinery is not actually running,” said McBride. “A lot of the refineries, yes they shut down for safety reasons during the storm but then they were not able to come back up because they didn’t have electricity, so it really does all come down to power supply.

Will taxpayers bear the cost of cleaning up America’s abandoned oil wells? - Oil and gas companies have a century-old bad habit of drilling wells and ditching them. And while Congress finally has a plan to plug some abandoned wells, new proposals effectively pass the fossil fuel industry’s cleanup costs on to taxpayers and may even enable more drilling.Concerned parties seem to agree on the scale of the crisis: millions of wells sit untended across the US, leaking toxins that pose public health problems along with the potent greenhouse gas methane, which contributes to the climate emergency.But powerful special interests have carved out a presence in federal well-plugging efforts – one of the most bipartisan corners of Joe Biden’s $1tn infrastructure bill, which is due for a vote later this month. Instead of requiring fossil fuel companies to cover the actual cost of drilling and cleanup, policy experts say the proposal is an additional multibillion-dollar subsidy for the industry most responsible for driving the climate crisis. Congress’ 30-page proposal does provide a much-needed plan to inventory, measure and track methane emissions and groundwater contamination associated with orphan wells – abandoned wells with no identifiable owner. But tucked inside the proposal is $2m in funding that goes directly to the Interstate Oil and Gas Compact Commission (IOGCC), an organization closely linked to the fossil fuel industry. The draft bill empowers the group to consult with the federal government as it issues billions of dollars in grants for states to plug, remediate and restore orphan wells.The infrastructure bill treats the commission innocuously, granting it duties and access to federal research and development funds as if it were a formal government entity.The trouble is, it’s not.And as recent comments from the IOGCC vice-chair, Wayne Christian, suggest, the organization’s involvement in the infrastructure negotiation process includes more explicit pocket-padding priorities.“If the bill passes, and we’re pretty close to it passing, 25 million [dollars] will be coming to Texas to clean up abandoned wells, and larger amounts than that in the future,” Christian – an avid climate change denier and head of the Railroad Commission of Texas with notoriously close ties to the oil industry – boasted on 20 August at the North American Prospect Expo, an oil industry gathering, according to a recording of the event.“So, we will be helping the energy industry to some of these trillions of dollars,” he said.

Royal Dutch Shell Is Selling Its Permian Basin Oil Holdings to ConocoPhillips - — Royal Dutch Shell sold its oil and gas production in the Permian Basin, the biggest American oil field, to ConocoPhillips for $9.5 billion in cash on Monday.The deal marks a turning point for Shell, which had put considerable effort into developing the 225,000-acre field sincebuying it from Chesapeake Energy nine years ago, expanding its production to about 200,000 barrels a day.The sale is the latest sign that Shell, like other European oil companies, is under pressure to sell off oil and gas production and move toward producing cleaner energy in response to growing concerns about climate change among investors and the general public. Shell is retreating from the Permian as American shale oil production is recovering. The Permian Basin yielded 4.7 million barrels a day in August — more than 40 percent of total American oil output and a nearly 400,000-barrel-a-day increase from January. Rising oil prices have enticed crews to return to the fields, where they use hydraulic fracturing — commonly known as fracking — to blast open shale rocks and force oil out of the ground.A wave of acquisitions in the Permian began last year with the onset of the coronavirus pandemic as companies sought to cut costs. The scale of the Shell deal is similar to Conoco’s acquisition of Concho Resources for $9.7 billion in October, a deal that made Conoco a major player in the Permian, which straddles Texas and New Mexico. In April, Pioneer Natural Resources bought DoublePoint Energy for $6.4 billion.With the acquisition of Shell’s acreage, Conoco consolidates its position as a top-tier Permian producer along with Pioneer, Occidental Petroleum, Exxon Mobil and Chevron.Shell’s sale of its West Texas Permian holdings, which provided an estimated 6 percent of the company’s global oil and gas production last year, had been expected for months. Shell recently sold its stakes in offshore oil and gas fields in Malaysia and the Philippines. Its American operations include offshore production in the Gulf of Mexico along with refineries.Shell has been talking about cutting emissions since 2017, and it has accelerated its shift to cleaner fuels over the last two years, although not enough to satisfy many environmentalists. In addition to a goal of net-zero emissions by 2050, it has set a target of reducing oil output up to 2 percent a year by 2030 through divestments and lower investments in exploration and production.

Shell sells off its oil and gas business in Texas’ Permian Basin, seeking to reduce its reliance on fossil fuels -- Energy giant Royal Dutch Shell sold its oil and gas business in the Permian Basin, the country’s largest oilfield, to ConocoPhillips for $9.5 billion cash on Monday.The deal is a major move for Shell, which produces more than 175,000 barrels of oil per day in the Permian Basin, as it faces pressure to reduce its oil and gas production and produce more clean energy in response to concerns from investors and the public about climate change.For Houston-based ConocoPhillips, Monday’s announcement furthers the company’s investment in the Permian Basin. Last year, the company bought large oil driller Concho Resources for $9.7 billion. Acquiring Shell’s land makes ConocoPhillips a top Permian producer alongside Chevron, Exxon Mobil and Pioneer Natural Resources, which bought DoublePoint Energy for $6.4 billion earlier this year.“The Permian Basin is not going anywhere,” Ed Longanecker, president of the Texas Independent Producers & Royalty Owners Association, said in an interview Monday. “And that’s going to continue to be the most prolific and highest [oil] producing region in the country.”But Shell and other major energy companies have faced growing scrutiny for their role in climate change and their public messaging about how fossil fuels contribute to it.Last week, the U.S. House Oversight Committee widened its inquiry into what it characterized as the oil and gas industry’s “longrunning, industry-wide campaign to spread disinformation about the role of fossil fuels in causing global warming.” The committee called on top executives from Shell, BP, Chevron and Exxon Mobil to testify before Congress next month.

ConocoPhillips bets $23 bln on U.S. shale oil as rivals retreat – ConocoPhillips Chief Executive Ryan Lance on Monday doubled down on U.S. shale and the world’s continued demand for oil with his second blockbuster acquisition in less than a year. His $9.5 billion purchase of Royal Dutch Shell (LON:)’s West Texas properties, nine months after closing a $13.3 billion deal for Concho Resources (NYSE:), puts the company’s future squarely in shale after exiting Canada’s oil sands, U.S. offshore and British North Sea fields. The strategy depends on a world thirsty for cheap oil and Conoco’s ability to extract it with less carbon emissions. While Shell, BP (NYSE:) and Equinor quit shale for renewable fuels, Lance argues oil and gas will not be soon supplanted. “We don’t believe the existential threat to this business is right around the corner,” he told analysts in June. With Shell’s assets, Conoco gets more than 10 years of output and rewards shareholders willing to stick with fossil fuels, said Lance. “We’re going to create a lot more value over the next 10 years and beyond with this acquisition,” Lance told analysts on Tuesday, promising to deliver higher returns for shareholders than paying a one-time dividend. Lance, who became CEO in 2012, joins Chevron (NYSE:) and Exxon Mobil (NYSE:) in rejecting the shift to solar, wind and batteries embraced by European oil majors. Shareholders want the company to focus on its strengths, he said. “This is what we’re good at. This is what we do really really well,” Lance said, referring to generating strong cash flow from modest investments in new oil and gas. The deal increases capital spending by $1 billion per year, but will add $10 billion to free cash flow and shareholder payouts over a decade. Shell’s more efficient assets will help Conoco reduce its carbon emissions per unit of production by as much as half its 2016 levels by 2030, he said. But the acquisition does not sit well with environmentalists, who this year pushed Conoco to address customers’ emissions from using its fuels. In May, 58% of shareholders voted in favor of a non-binding petition to set reduction targets including from products. “Buying fossil fuel assets is exactly the opposite of what investors actually want,” Mark van Baal, founder of Dutch advocacy group Follow This, said in a phone interview. “Eventually he will have to listen,” he said. Disclaimer: Fusion Media would like to remind you that the data contained in this website is not necessarily real-time nor accurate. All CFDs (stocks, indexes, futures) and Forex prices are not provided by exchanges but rather by market makers, and so prices may not be accurate and may differ from the actual market price, meaning prices are indicative and not appropriate for trading purposes. Therefore Fusion Media doesn`t bear any responsibility for any trading losses you might incur as a result of using this data.

Climate goals help drive Shell's Permian oil basin exit | S&P Global Market Intelligence - Royal Dutch Shell PLC's decision to sell all of its assets in the Permian Basin to ConocoPhillips for about $9.5 billion appeared to mark a quick shift in strategy for the Dutch energy giant that had described the business as "core" just a few months ago. But the deal disclosed Sept. 20 by both companies comes at a time when major oil and gas companies face mounting pressure from investors and regulators to curb emissions and diversify outside of fossil fuels. And for Shell, selling off its Permian business helped the company make progress on its goals of cutting its emissions that are the most difficult to reduce. The sale — one of the largest recent transactions in the U.S. shale patch — also freed Shell of an asset seen as lacking the scale needed to drive cost efficiencies that rival oil and gas giants have in the region, which is the country's most prolific in oil production. "They were in a position where they either had to grow it or get out of it, and they found a willing buyer in Conoco," Morningstar analyst Allen Good said in an interview. "The net-zero [target] on top of that certainly made it an easier decision." Shell emphasized the economies of scale as the driving force behind the sale. "Our operated position was sub-scale and needed additional materiality to reach its competitive potential," Shell spokesperson Natalie Gunnell said in an email. "In an effort to optimize value from our Permian business, we reviewed multiple strategies and portfolio options for these assets, including opportunities to increase scale. This offer emerged as a very compelling value proposition." Shell owns about 225,000 net acres in the Permian that produce about 175,000 barrels of oil equivalent per day. That is a significant acreage, but a fraction of what other oil and gas giants such as Chevron Corp. and Exxon Mobil Corp. possess in the region. Shell might not have been in a position to make an acquisition to grow its Permian business, Good said, adding that growing the Permian business might not have even been consistent with the company's overall divestment strategy and climate targets. Shell said in July that it expected its oil production to decline by 1% to 2% annually over the next decade, after peaking in 2019, as it limits upstream investment to focus more on energy transition areas such as its LNG business and renewables. Shell's Permian assets represented less than 1% of the company's carbon emissions from operations, according to the Wall Street Journal. But Shell is also attempting to cut its carbon emissions and invest more in renewable energy under a more aggressive timeline than many of its peers, after a Dutch district court in May ordered the oil and gas giant to reduce its net carbon emissions by 45% by 2030 from 2019 levels.

Shell's Big Sale of Oil and Gas Holdings Is a Climate Bait-and-Switch - Royal Dutch Shell on Monday said it was selling off all of its oil and gas assets in Texas’s Permian Basin for $9.5 billion in cash to ConocoPhillips, one of the biggest recent transactions in the industry.The sale represents 225,000 net acres of land in the Permian that produces 175,000 barrels of fuel per day, the companies said in a news release; a Shell executive told the Wall Street Journal that its employees in the Permian would join ConocoPhillips. After the sale is complete, Shell will have no remaining presence in onshore production in the Permian, one of the world’s largest oil and gas producing fields. While Shell’s announcement makes no mention of its climate or energy plans, the sale comes as Shell and other oil companies come under increasing scrutiny from climate activists and the general public for their plans to cut emissions. Shell, in particular, is facing a historic legal challenge to its business: in May, a stunning ruling from a court in the Netherlands ordered Shell to cut its emissions 45% by 2030, in line with what the Paris Agreement mandates. (The company has said it will challenge the ruling, with CEO Ben van Beurden penning a LinkedIn post to explain the reasoning.)Shell has also faced a flurry of other legal challenges in the Netherlands and the U.S. over its climate commitments. Earlier this month, another Dutch court (the Dutch legal system is really pulling its weight here) ruled that Shellneeded to stop using advertisements that claim that customers can make their purchases “carbon neutral” if they buy offsets at the pump. (This is a campaign that Shell also hired Instagram influencers to promote.) And last week, the U.S. House of Representatives said it was launching an investigation into Big Oil’s use of misinformation, calling representatives from major oil firms to testify, including Shell. The sale could be read as a sign that the industry is slowly recognizing that fossil fuels may not be a cash cow forever. The Shell executive told the Journal that the decision to sell came after the company considered acquiringnew assets in the Permian, but ultimately decided that the most profitable move for shareholders would be to sell. Shell has indicated that it seems to recognize the writing on the wall when it comes to fossil fuels: Earlier this year, the company said in a statement that it had reached peak oil production in 2019, peak emissions in 2018, and its fossil fuel production would gradually start to decrease (albeit at a rate far, far slower than what the Dutch court has ruled and what science dictates). Van Beurden also said in May that the company is “absolutely needed” for the energy transition and that people will see Shell “do the right thing.” OK, Ben!

Shell leaving Permian Basin unlikely to impact Texas workforce, climate - Midland Mayor Patrick Payton expects most people working for Royal Dutch Shell in West Texas to keep their jobs after the energy giant sold its oil and gas business in the Permian Basin to ConocoPhillips for $9.5 billion cash on Monday. Instead, Payton said, many of Shell’s oil and gas workers will likely do similar jobs for ConocoPhillips, the Houston-based company that appears to be going all-in on oil and gas in West Texas. With the sale, Conoco now owns land in the oil patch comparable to the largest players there. For Shell, the motivation for the sale was to meet the company’s goals of shrinking its carbon dioxide emissions and increasing its share of renewable energy sources, objectives made legally binding by a Dutch court this summer. The company has faced pressure to reduce its oil and gas production and produce more clean energy in response to concerns from investors and the public about climate change. But despite Shell’s climate goals, energy experts said the deal, which moves more than 175,000 barrels per day in production from one major company to another, isn’t a signal that the industry is focusing more on protecting the environment. “You’re not reducing emissions, you’re just transferring who produces them,” said Arvind Ravikumar, who leads the University of Texas at Austin’s Sustainable Energy Transitions Lab. “This is not a symbol of global movement to take climate action,” said Kenneth B. Medlock III, senior director at the Center for Energy Studies at Rice University. “This is a symbol of what two different entities viewed was in their own commercial best interest.”

Attorney: More public disclosure needed in historic natural gas price proceedings --State regulators’ refusal to dig deeper into the causes of a historic spike in natural gas prices this winter effectively shuts down the investigation, an attorney says. Prices for the largest natural gas pipeline serving Kansas rose to about 200 times their normal price this winter during a severe cold snap that pushed the electrical grid to the brink. Months later, regulators are sorting out huge spikes in energy prices caused by the storm. The total statewide is nearly $1 billion. The biggest chunk comes from Kansas Gas Service, the state’s largest natural gas utility, which paid more than $390 million in extraordinary costs when gas prices rose from less than $3 to more than $620. With carrying costs, the total comes to $451 million. Instead of recouping the total all at once, KGS customers will pay off costs from the storm for up to 10 years. Black Hills Energy incurred $87.9 million total, which will cost customers an extra $12.23 per month over five years. Evergy, which also gets energy from coal and renewable resources, plans to recoup $152.3 million over two years from its Kansas customers outside the Kansas City metro. Evergy customers on the Kansas side of the Kansas City metro will see savings because the company has far more sources to generate power in the area. But Jim Zakoura, an attorney representing the Natural Gas Transportation Customer Coalition, unsuccessfully urged Kansas regulators to require KGS release records about its natural gas purchases, including supplier names, and subpoena a national natural gas price index to investigate market dysfunction. “If you’re asking the public to foot the largest rate increase in history, $451 million for seven days of gas, everything should be made available to them,” Zakoura said.

White House pledges to fight court order on oil and gas leases, but activists want more - The Biden administration plans to appeal a federal court decision forcing the government to restart oil and gas leases that have been paused since January. But administration officials are also promising to comply in a way that takes into account the damage caused by fossil fuel development. The two-part move worries progressive activists and members of Congress, who have urged President Joe Biden to permanently shut down the federal oil and gas leasing program because of its contributions to climate change. In addition, the oil and gas industry is questioning whether there’s any intent by the government to fall in line with the court ruling, since lease sales have not been scheduled. The reactions came after the Interior Department said Monday it would comply with U.S. District Judge Terry A. Doughty’s June 16 ruling to reinstate the oil and gas leasing program while the appeal is pending. But the department reserved the right to “to conduct leasing in a manner that takes into account the program’s many deficiencies,” including its impact on climate change. An Interior spokeswoman declined to elaborate Tuesday on what the department’s compliance would mean in practice. Biden paused oil and gas leases on federal lands in a Jan. 27 executive order that also called for a comprehensive review of the program. Lease sale auctions are generally held quarterly. Louisiana Attorney General Jeff Landry, and 12 other Republican attorneys general, including those in Georgia, Missouri and Montana, sued earlier this year to stop the pause. In an interim step, Doughty ruled in favor of the states and issued an injunction forcing the federal government to resume lease sales. Interior said immediately following the ruling it would comply with it, but has not announced any new lease sales. Monday, the department again said it would comply, but added several criticisms of the oil and gas leasing program, including that it has failed to account for contributions to climate change. The statement’s emphasis on the program’s faults led some conservation activists to believe that the Biden Interior Department would approve fewer leases or otherwise curb what they see as the program’s excesses in previous administrations.

Methane fee collides with EPA rules. 'It's very unusual' - Methane emissions are in the crosshairs of Democratic climate politics like never before, creating the prospects of a collision between the oil and gas industry and simultaneous restrictions from both Congress and EPA. Democrats in the House and Senate are moving to slap a fee on natural gas vented from wellheads and storage facilities as part of their reconciliation package. At the same time, EPA is preparing to release an aggressive new suite of Clean Air Act rules within weeks that would boost requirements for the industry to find and fix leaks. Both moves will follow President Biden’s agreement with European Union leaders on Friday to cut human-made methane across the economy by 30 percent this decade. It’s a cascade of new pressures for a fossil fuel industry that only recently accepted the idea that methane regulation and carbon pricing are potential outcomes of current climate politics. And they’re crying foul. “On the one hand we have a situation where we’ve been regulated at the federal and state level on methane and are working with the Biden administration on new regulations that would capture new and existing sources,” said Frank Macchiarola, senior vice president for policy and regulation at the American Petroleum Institute.. “And then along comes this fee.” API, the largest U.S. oil and gas lobbying group, cheered former President Trump’s efforts to dismantle Obama-era methane rules in favor of laxer standards. It took that position even as some of its members from the oil industry called for tougher federal limits on leaked natural gas. Then as President Biden prepared to take office in January, API reversed itself and pledged to help the administration craft rules for new and existing oil and gas infrastructure that would target methane directly. In March, API released "principles" for the kind of carbon tax it would support as part of a Climate Action Framework. They were derided by environmentalists as “greenwashing.” Now the industry is not extending its conditional support for carbon pricing to the Democratic proposal for a methane fee — a policy Macchiarola called “duplicative” and “a punitive tax that’s just going to harm natural gas producers and ultimately add to costs throughout the system.”

Top Ad and PR Firms Exposed for Helping Big Oil Greenwash Their Climate Destruction -- On the heels of congressional Democrats callingthe heads of fossil fuel companies and industry lobbying groups to testify about their role in spreading climate disinformation, campaigners published a report Tuesdayexposing the contributions of major advertising and public relations firms.The aim of Clean Creatives' report, as its introduction explains, was to "document the many known relationships between PR, advertising, and other creative agencies and fossil fuel companies that are responsible for climate change, and compare holding company pledges for climate action with their work for polluting clients."Unveiled last year by the nonprofit Fossil Free Media, the Clean Creatives campaign pressures ad and PR agencies to ditch clients fueling the climate emergency."Fossil fuel companies are the biggest polluters, the biggest greenwashers, and the biggest opponents of life-saving climate action. There is no room for ad and PR professionals to continue promoting companies that are doing so much damage to our future," said Clean Creatives director Duncan Meisel in a statement about the report, entitled The F-List 2021The F-List 2021. “The most important step any agency can take to address the climate crisis is to rule out working with fossil fuel companies," Meisel added. "We need creatives and communications experts to bring their full energy towards ending this crisis, not extending it."The report focuses on the work of 90 agencies across three different regions—Australia, Europe, and North America—and notes that "fossil fuel industry clients include the full range of corporations involved in the business of extracting, transporting, refining, and selling fossil fuels, their trade associations, and front groups representing their interests."

Judge deems Line 5 mediation at ‘standstill' -- - The federal judge tasked with determining which court — state or federal — will determine whether Gov. Gretchen Whitmer can shut down Enbridge’s Line 5 pipeline has formally acknowledged the mediation breakdown between the parties. In a Tuesday order, Judge Janet Neff dismisses the state’s Sept. 14 motion regarding its issue with the mediator as moot while settling any doubt as to whether the mediation process is complete. “The Court determines from the parties’ filings that the formal VFM [voluntary facilitative mediation] process is at least at a standstill, although the parties remain under a continuing obligation to engage in good faith to resolve this case,” Neff wrote. The agreed-upon facilitative mediator, former Judge Gerald E. Rosen, had been working with the parties in State of Michigan v Enbridge for nearly six months. The last scheduled session on Sept. 9 ended without a settlement; but, upon notice that Rosen intended to file additional documents to potentially continue the process past that point, the state filed a complaint and asked Neff to block any further filings from him. “The mediator subsequently filed a Report Following Voluntary Facilitative Mediation (‘the Report’), indicating only that mediation is ‘continuing,’ with the date of any next session ‘to be determined,’” Neff said. But, regardless of the propriety of Rosen’s filing, Neff acknowledges that there has been an “apparent breakdown” in the mediation process that prevents it from continuing either way. “While the Enbridge Parties indicate their willingness to continue to work towards a mutually acceptable resolution, the State Parties filed a ‘response’ to the mediator’s Report indicating that they have ‘no desire to continue with the mediation process’ and requesting that the Court treat the process as ‘completed without a settlement,’” Neff wrote. “Voluntary facilitative mediation necessarily requires voluntary participation by both parties,” she added. Accordingly, Neff dismissed the state’s motion to enforce notice of appointment of facilitative mediator as moot.

Enbridge fined more than $3 million - The Minnesota Department of Natural Resources announced Sept. 16 that Enbridge Energy has been ordered to pay $3.32 million for failure to follow environmental law.The fine is related to the breach of an artesian aquifer back in June, resulting in what the DNR calls “an unauthorized groundwater appropriation during the construction of the Line 3 Replacement Project near Enbridge’s Clearbrook Terminal.” DNR’s civil enforcement orders require Enbridge to pay mitigation and penalty funds of $3.32 million. This includes a restoration order requiring $300,000 in initial mitigation funds to pay for the loss of groundwater resources, $250,000 for DNR monitoring of calcareous fen wetlands near the area of the aquifer breach and a $20,000 administrative penalty order – the maximum amount allowed under Minnesota state law.The DNR has also ordered Enbridge to place $2,750,000 in escrow for restoration and mitigation of any damage to the calcareous fen wetlands. DNR will determine what restoration and mitigation is required.The DNR’s restoration order also requires Enbridge to implement a restoration plan to stop the unauthorized groundwater flow within 30 days. The order requires the company to conduct additional groundwater and site monitoring and report the results, as well as to develop a Calcareous Fen Management Plan. Additionally, to ensure that violations haven’t occurred elsewhere, the DNR is requiring Enbridge to fund a re-inspection of any and all areas along the entire route where construction depths deviated from plans (as they did at the Clearbrook Terminal site).Separately, the DNR has also referred this matter to the Clearwater County Attorney for criminal prosecution. The DNR has determined that Enbridge Energy violated Minnesota Statute 103G.141, subdivision 1, which makes it a crime to appropriate “waters of the state without previously obtaining a permit from the commissioner.”The DNR identified the potential breach of the aquifer June 15, and started an investigation. Through Sept. 5, 2021, this violation has resulted in an estimated release of approximately 24.2 million gallons of groundwater from the aquifer. This water has been pumped from the trench, treated to remove sediment and released to a nearby wetland.

‘They screwed up our lake’: tar sands pipeline is sucking water from Minnesota watersheds -Along the eastern boundary of the White Earth Indian Reservation in north-western Minnesota, Indigenous Anishinaabe wild rice harvesters Jerry and Jim Libby set down a row of wooden pallets into the mud just beyond the dock of Upper Wild Rice Lake. It was a clear day, and tight, lush clumps of green rice heads were visible across the lake’s horizon. In a typical year, the entrance to this – one of a long necklace of wild rice lakes in northern Minnesota to which the region’s Indigenous people flock every year in the late summer – would be covered in at least two feet of water. But now it is composed of suspended sediment as solid as chocolate pudding, through which the Libbys need to create a makeshift ramp simply to carry their canoe out to the waterline. Minnesota is weathering an historic drought, but there is another problem beyond the weather: Enbridge’s Line 3 tar sands pipeline has taken a substantial toll on watersheds in the region, including through a permit to pump five billion gallons of water for construction. In the case of Upper Wild Rice Lake, a road construction contractor named Knife River Construction stuck a pump directly in the lake this past June, sucking out an unknown quantity of water, which locals suspect was related to the use of heavy trucks for the pipeline. “As far as I’m concerned, Enbridge screwed up our lake, and they’re taking money directly away from our families,” Jerry Libby says. “It makes us feel anguished – this is our staple food, you know.” The Indigenous-led struggle against Line 3, which seeks to move 930,000 barrels of tar sands bitumen daily from Alberta to a shipping and refinery hub in Superior, Wisconsin, has been the biggest environmental and Indigenous land protection campaign in the US this summer. More than 900 people have been arrested opposing the pipeline, including nearly 70 who were kettled in late August during protests outside Minnesota governor Tim Walz’s residence in Minneapolis. Branded as a “replacement” project, the new pipeline would double the old Line 3’s capacity to carry tar sands bitumen. Enbridge, a Canada-based energy company, has announced it will begin sending oil through the pipeline next month. The processing and combustion of bitumen for the pipeline would release greenhouse gases equivalent to 50 coal plants, according to analysis by the nonprofit Oil Change International, thereby significantly contributing to the global climate crisis. But one of the pipeline’s most immediate impacts is on wild rice harvesters such as the Libbys, for whom the annual harvesting season began in late August and runs through much of September. Wild rice – known to many Anishinaabe people as “manoomin,” or “the food that grows on water” – is a dense, nutritional grain that grows naturally in the abundant lakes and rivers in Minnesota, Wisconsin and parts of Canada. Thousands of Anishinaabe people continue to harvest it with the same traditional methods used for generations, by propelling a canoe or small boat through the rice beds with a long pole. Indigenous people of the region believe they have a sacred covenant to protect manoomin and numerous other nonhuman beings, without which they would cease to exist as distinct peoples, notes longtime Anishinaabe rice harvester Bob Shimek. “During any kind of ceremony we do here, wild rice is involved,” Shimek says. “It’s kind of like the Anishinaabe soul food.”M

Criminal cases against Line 3 protesters stress rural Minnesota legal system | MPR News -Maya Stovall was a student at Carleton College helping organize on climate issues when she learned about the Line 3 oil pipeline. She decided to travel to northern Minnesota to join the protests against the pipeline — and kept going back. “Fighting Line 3 felt like the thing to be doing,” said Stovall, 20, who is from Illinois and majoring in political science and international relations. “We can't have new fossil fuel infrastructure like Line 3 if we're going to have a breathable planet.” In March, Stovall was arrested along with other protesters who locked themselves together surrounding a prayer lodge at a pipeline construction site in Hubbard County. She was arrested twice more at other protest actions during the summer. For the March incident, Stovall faces misdemeanor charges of trespassing, unlawful assembly and public nuisance. But after a July arrest in Pennington County, she received a more serious gross misdemeanor charge of trespassing on critical infrastructure. Stovall had to wait months to be assigned a public defender to represent her. "It's stressful — a lot of weight from not being able to move forward,” she said. “I would really like to file motions to dismiss my charges, and I cannot do that without representation.” Nearly 900 people have been arrested during protests against the Line 3 oil pipeline, which is being built in northern Minnesota. Most were cited with misdemeanors. But many, like Stovall, have been charged with gross misdemeanors, and some face felony charges. The number of legal cases is straining resources in the northern Minnesota counties where most of the protests took place. In addition to waiting for months for a public defender, some defendants also argue that the charges they're facing are unfairly severe.

As insurers retreat from oil projects, Enbridge says coverage will be harder to get - Enbridge will have a tougher time finding insurance for its controversial Line 3 pipeline as insurers increasingly limit coverage of oil and pipeline projects — particularly those tied to Canada. That was the upshot of filings Enbridge made last week with the Minnesota Public Utilities Commission (PUC). The Calgary, Alberta-based company reported that it has the coverage required by the PUC. But the insurance market has an increasing aversion to oil projects due to carbon emission concerns and the low profitability of insurers hit by pollution-related losses, according to a report done for Enbridge by Marsh, one the world's largest insurance brokerages. "As we continue to see insurers reduce participation or withdraw from the crude oil infrastructure coverage, replacing their participation will become extremely challenging, and it is unlikely that a $900 million limit will continue to be available for Enbridge and other pipeline risks in the near future," the Marsh report said. The PUC has assumed that Enbridge will maintain general corporate liability coverage of $900 million, which would backstop specific insurance requirements for Line 3. The PUC also required Enbridge to buy a specialized "environmental impairment liability" policy with aggregate annual coverage of $200 million. Getting a $200 million damage limit for that environmental impairment policy will also become "more challenging," the Marsh report said. "This is a challenge for all pipeline companies, particularly those with Oil Sands connections." Alberta's oil sands, also called tar sands, are the source of most oil exported from Canada. Extracting such oil is particularly carbon intensive, and it's often mined from open pits. In a statement, Enbridge said "it maintains significant amounts of insurance and is appropriately insured for its operations."The amount of Enbridge's general liability coverage "is at the high end of amounts carried by our peer group," the company said. "Also, like any organization, we adjust our insurance based on the evolving market conditions we face each year when we renew," Enbridge said. "As the market evolves, we make decisions to ensure we are appropriately insured." The company noted that it would be responsible for any oil spill clean-up, "regardless of the ability to later recover those expenses under an insurance policy." Enbridge's last major oil spill in Minnesota was in 2002, when Line 3 ruptured and leaked 252,000 gallons. In 2010, an Enbridge pipeline in southwestern Michigan spilled 834,000 gallons of oil into a tributary of the Kalamazoo River. The Michigan leak was one of the worst oil onshore oil spills in U.S. history and cost Enbridge $1.2 billion to clean up. A worst-case spill in Minnesota would cost $1.4 billion to mop up and remediate, according to a 2018 Enbridge analysis required by the Minnesota Department of Commerce. Environmental and Indigenous groups have been waging campaigns against the financiers and insurers of oil projects. Some have also faced pressure from their own shareholders. The efforts have had an effect: At least 14 insurance companies have pulled out of providing coverage for the Trans Mountain pipeline, which will carry oil from Alberta to the British Columbia coast.

Summit Midstream Partners pleads guilty in largest U.S. inland spill from oil drilling | Reuters -- Pipeline operator Summit Midstream Partners pleaded guilty in federal court in Bismarck, North Dakota on Wednesday to criminal water pollution charges in what prosecutors call the largest land-based spill from oil drilling. The company agreed to pay $36.3 million to settle criminal charges, as well as parallel civil charges filed by the US government and the state of North Dakota. The company acknowledged that in August 2014, 29 million gallons (132 million liters) of produced water, a waste product from fracking, spilled from its pipeline near Williston, North Dakota, contaminating groundwater as well as more than 30 miles (30 km) of water. 48.28 km) Tributaries of the Missouri River. The water produced due to this method of drilling contains saline, as well as high concentrations of oil, radioactive material and pollutants such as ammonia, aluminum and arsenic. The spread continued for five months before it was finally contained and reported to the federal government as required by the Clean Water Act. Email evidence obtained by government investigators suggests that company officials and contractors were aware of several explosions while the pipeline was being pressure tested, with an inspector saying at one point that the company was less-recommended. was using test pressures. “What is known is that the installation was negligent and that the breakdown was consistent with the negligent establishment,” the government wrote in the court filing.

Company agrees to pay hefty fine in large oil spill case (AP) — The company responsible for the largest oil field spill in North Dakota has pleaded guilty to criminal charges after reaching an agreement with the federal government to pay $15 million in fines. Summit Midstream Partners entered the pleas in federal court Wednesday. Summit was charged for negligently discharging oil and for failing to immediately report the spill, which occurred north of Williston over a period of five months in 2014 and 2015. A pipeline leaked 700,000 barrels, or 29 million gallons, of produced water, which is highly saturated saltwater that comes up in wells along with oil and gas. Produced water can contain oil, the Bismarck Tribune reported. Some of the wastewater reached Blacktail Creek, which eventually flows into the Missouri River. The U.S. Department of Justice said the $15 million will go toward the federal Oil Spill Liability Trust Fund, which can be used to clean up oil spills. Summit also has agreed to take steps to prevent future spills by implementing better training, installation, operating and testing requirements. The company said it has spent $75 million on those improvements and spill cleanup.

Dakota Access asks court to reverse decision requiring environmental review - The Dakota Access Pipeline is asking the Supreme Court to review a lower court determination finding that it needs additional environmental review. At the start of the year, a federal appeals court upheld a lower court’s decision that the federal government needed to conduct a rigorous environmental review called an Environmental Impact Statement for the pipeline. The appeals court also upheld a decision to vacate a permit for the now-operational pipeline, while the review is conducted. In its new filing, the company asks the high court to consider whether the appeals court was wrong to vacate the permit under environmental laws. It also takes issue with the appeals court’s assertion that it was judging whether the federal government had “convinced the court that it has materially addressed and resolved serious objections to its analysis.” Dakota Access, in the new filing, also asks the high court to weigh whether the U.S. Army Corps of Engineers, which issued the approval, needed to also “‘resolve’ those criticisms to the court’s satisfaction.” In the meantime, the pipeline will continue to operate without the permit, after the Biden administration and a federal court declined to shut it down. A Justice Department lawyer said at the time that whether or not to shut down the pipeline was a matter of “continuing discretion,” and, in its new filing, the company argued that the court decision leaves the pipeline “at a significant risk of being shut down.” This is not the first time the company has asked the Supreme Court to review the case, previously trying to get the court to take a look at it in April.

Dakota Access review 'gravely off track,' tribes say in calling for fresh start - The head of the Standing Rock Sioux Tribe says the federal agency tasked with overseeing an ongoing environmental review of the Dakota Access Pipeline “is already gravely off track,” and he wants the process to start over. Chairman Mike Faith and leaders of other tribes fighting the pipeline sent a letter Wednesday to a top U.S. Army Corps of Engineers official, taking issue with the contractor the agency has tapped to complete the review over its ties to the oil industry. Tribal leaders say the Corps is working with Environmental Resources Management, a London-based company with offices in 40 countries including the United States. One of the tribes’ concerns is that the company is a member of the American Petroleum Institute, a trade group that lobbies for the oil industry and has submitted court briefs supporting Dakota Access. The tribes also point to testimony an Environmental Resources Management worker offered to South Dakota regulators in 2015 after reviewing the proposed pipeline, concluding that it “is not likely to pose a threat of serious injury to the environment.” “In essence, ERM is an agent of DAPL, rather than a neutral party,” reads the tribes’ letter, which they sent to Jaime Pinkham, acting assistant secretary of the Army for civil works. The tribes say the Corps’ selection of the company “compromises” the integrity of the environmental review process. Environmental Resources Management declined to comment on the letter. Opponents of the Keystone XL project raised similar concerns regarding a potential conflict of interest in the mid-2010s when the U.S. State Department used the company to complete the environmental review of that proposed oil pipeline. A federal judge ordered the new, more thorough environmental study of Dakota Access last year and revoked a permit for the pipeline’s crossing under the Missouri River just upstream from the Standing Rock Reservation. Tribal members are concerned about a potential oil spill. The pipeline developer has long maintained that the line is safe. The review process began one year ago and is expected to wrap up next September. It will be instrumental in the Corps’ decision on whether to reissue the permit.

Latest bout over North Dakota royalties goes to oil industry (AP) — The latest bout of legal wrangling over the collection of North Dakota oil and gas royalties has been won by the energy industry, over a bill it promoted and was passed by the 2021 state Legislature. A state judge on Thursday ruled in favor of the law that limits how much interest companies have to pay for unpaid oil and gas royalties and sets a statute of limitations on how far back they have to pay. The decision came after a state agency argued that the legislation is unconstitutional. McKenzie County Judge Robin Schmidt is unlikely to have the last word, however. Fargo attorney Joshua Swanson, who has successfully represented clients over oil and gas mineral rights in North Dakota, said when the law was challenged in court last month that the issue is likely headed to the state Supreme Court regardless of Schmidt’s opinion. A brief filed on Aug. 6 on behalf of the Board of University and School Lands, referred to as the Land Board, complained that the legislation violates the U.S. Constitution because it harms the obligation of previously agreed-upon contracts. The board said it will cost the state hundreds of millions of dollars that mostly go to schools. Few of the key players in the long-running dispute are talking. State Land Commissioner Jodi Smith did not immediately return a phone message Monday seeking comment. A spokeswoman for state Attorney General Wayne Stenehjem, who filed the motion challenging the constitutionality of the law, first referred all questions to the Land Board, of which Stenehjem is a member, and then directed inquiries to Smith. Republican Gov. Doug Burgum, a member of the Land Board, and David Garner, an attorney for Smith and the board, did not immediately respond to email requests by The Associated Press. The law approved earlier this year by the Republican-led Legislature and signed by Burgum states that the Land Board cannot collected royalty payments from before August 2013. It also reduces the amount of interest the state can charge companies for unpaid oil and gas royalties, from 30% to 15%. The state Supreme Court sided with the Land Board two years ago in the debate that started with a lawsuit filed by an operator in 2018 after the state determined that companies were taking improper deductions.

Eighth Circuit reverses dismissal of Andeavor trespassing case -The legal battle will continue for Andeavor’s Tesoro High Plains crude oil system for the foreseeable future, after the Eighth Circuit Court of Appeals reversed a lower court decision dismissing a class action suit filed by landowners over claims of trespass. The High Plains system carries about one-third of the Bakken’s crude oil to a refinery in Mandan, and it has been embroiled in a legal quagmire since 2013, when negotiations to renew its right of way leases fell apart. On Monday, the U.S. Court of Appeals reversed a lower court decision in the 2018 class action suit, which seeks both compensatory and punitive damages for ongoing trespass and injunctive relief requiring the pipeline to be dismantled. The Eighth Circuit agreed that the outcome of the Bureau of Indian Affairs administrative process would be an important turning point for the case, but disagreed that it lacked jurisdiction until after that administrative process is completely exhausted, especially given the back and forth in the Bureau’s decisions with new administrations coming on board. Instead of a dismissal, they granted a stay, to give the BIA more time to finish its current administrative process under the Biden administration. It also remanded the case back to the lower court for further consideration in light of its ruling. Individual landowners control 66 of the 90 acres in question for the pipeline’s right of way, and the MHA Nation controls 24. The individual landowners rejected their offers after learning that MHA Nation had been offered substantially more per acre than they had been. They filed suit to try and force the pipeline to pay them more per acre or sun down. Marathon had partially shut the system down in 2020, after an order from the Bureau of Indian Affairs, amid claims that the pipeline has been trespassing on Native American land for seven years. Marathon was also fined $187 million in damages in connection with the BIA order under the Obama administration. The Trump administration later reduced that to $4 million.

Encinitas just banned natural gas in new buildings, including homes -- The Encinitas City Council passed a sweeping building electrification ordinance late Wednesday that, with just a few exceptions, will eliminate installing natural gas infrastructure on new residential and commercial construction within the city limits. The ordinance, which passed on a 5-0 vote, is similar to other measures adopted by 49 other communities in California in the past couple of years but most of those municipalities are located in Northern California. The Encinitas ordinance is the most comprehensive ordinance passed by a community in San Diego County. “We’re really excited because we’re doing our part, we care about climate change, we want to be a more environmentally committed city and we’re doing everything we can to get there,” said Encinitas Mayor Catherine Blakespear. The exceptions are quite narrow and are reserved for emergency buildings that are deemed essential facilities as defined by the California Health and Safety Code and construction in extreme scenarios for projects that would need significant utility upgrades. Restaurants that demonstrate they need to cook with a flame also could qualify for an exception. Examples include eateries that use woks, pizza ovens and barbecue-themed restaurants. However, if an exception is made, the restaurant must employ methods that will reduce the gas-fueled appliance’s greenhouse gas impacts. When an exception is made to the ordinance, the new construction must be wired so it can transition to be electric-ready in the future. The ordinance also applies to accessory dwelling units, more commonly called granny flats.

Progressives push for fossil subsidy repeal in spending bill --A group of House progressives is renewing a push for Democrats’ multi-trillion spending bill to repeal certain fossil fuel subsidies that have been on the books for years. In a new letter to congressional leadership, six top members of the Congressional Progressive Caucus, including Chairwoman Pramila Jayapal (D-Wash), said that they were “dismayed” that the House’s current version of the legislation didn’t include such measures. “There is no reason that the fossil fuel industry deserves special privileges over other businesses,” they wrote. Specifically, they call to end certain benefits for “intangible” costs like wages, repairs, supplies and another that lets some companies deduct as much as 15 percent of the revenue they get from a well.While Senate committees haven’t yet released their versions of the spending bill, Senate Majority Leader Chuck Schumer’s (D-N.Y.) office has indicated that the package is expected to address fossil fuel subsidies. The upper chamber’s finance committee put forward legislation earlier this year tackling the subsidies.

Top Democrat says he'll push to address fossil fuel tax breaks in spending bill -Senate Finance Committee Chairman Ron Wyden (D-Ore.) said Wednesday that he’s pushing for legislation to address fossil fuel tax breaks to be included in Democrats' $3.5 trillion spending bill. “President Biden, to his credit, in the campaign, said that there should not be special tax breaks — his words, not mine — for fossil fuels. Clean Energy for America meets that campaign pledge,” he told reporters, referring to a bill advanced by his committee. “We’re going to push for it in the reconciliation bill as well,” he added during a press conference. Such provisions have not been included in the House version of the reconciliation bill — sparking criticism from some progressives. During Wednesday's press conference, Sen. Jeff Merkley (D-Ore.) said the eventual Democratic bill “may well have” provisions like a carbon tax to encourage the transition to clean energy. “Will any of these be in it? Well, we will see, but I wanted to mention that they are part of the conversation at this point,” he said, also referring to a methane fee and a carbon border fee. But, the future of the entire reconciliation package remains uncertain amid doubts from moderates in the caucus, including Sen. Joe Manchin (D-W.Va.), over the price tag. Democrats can't lose any votes in the Senate given the 50-50 split and the unified GOP opposition to the spending package, which contains much of President Biden's domestic agenda. Manchin has raised concerns about the cost of the bill as well as a provision in which utilities would be paid to switch their power to clean sources. Asked about Manchin's remarks, Sen. Patty Murray (D-Wash.) on Wednesday said lawmakers are making the climate case to all of their fellow Democrats. "The inaction is not something we can tolerate, or live with, or wait another year. We are making that case to every member of our caucus," she said.

Alaska lawmakers seek allies to save ANWR drilling - Alaska’s Republican senators say they are actively exploring avenues to ensure the still-in-flux reconciliation bill does not restrict drilling in the Arctic National Wildlife Refuge. Sens. Lisa Murkowski and Dan Sullivan are preparing to go on offense as House Democrats grow increasingly more vocal in their demands that the drilling prohibition, which was included in the House Natural Resources Committee’s portion of the reconciliation package, remains in play amid negotiations with the Senate. Sullivan told E&E News yesterday that he and Murkowski’s teams “have been working on it,” while Murkowski said in a separate interview on Capitol Hill that she was “working to build our allies” on the issue. Their most likely ally at this point is Sen. Joe Manchin, the moderate West Virginia Democrat and critical swing vote who chairs the Senate Energy and Natural Resources Committee, which has jurisdiction over the ANWR issue in the reconciliation process. In 2017, the Republican-controlled Congress put language in the Tax Cuts and Jobs Act — which was passed and signed into law through the reconciliation process — to lift the ban on oil and gas drilling in ANWR’s coastal plain. Manchin supported it. Asked specifically about Manchin, Sullivan said “those conversations are in the works.” Murkowski said earlier this week, “I’m talking to my friend Senator Manchin about everything, all the time, whatever it may be.” While Manchin backed ANWR drilling four years ago, it’s not clear whether he would maintain this stance today as he prepares to negotiate over dozens of other provisions, large and small, especially the inclusion of the Clean Energy Payment Program. He’s also currently a holdout on the entire reconciliation bill as it currently stands (Energywire, Sept. 16). He has not yet commented on this specific line item in the context of this political fight. Sullivan and Murkowski acknowledged they were skittish about the potential to see their 2017 victory dashed. “I’m not sure what the fate of reconciliation is writ large,” said Murkowski, “but obviously I’m very concerned that our efforts to advance ANWR, as we’ve been able to do, could be really thwarted if reconciliation is advanced.”

British energy firms fear collapse as Europe’s gas crisis sees prices surge 250% - --Britain's energy industry could be headed for a significant shake-up, industry insiders have warned, as countries all over Europe grapple with an unprecedented crisis in the power sector.Wholesale gas prices have spiked across the region, with the U.K. being hit particularly hard.The front-month gas price at the Dutch TTF hub, a European benchmark for natural gas trading, gained on Monday to trade at 73.150 euros ($85.69) per megawatt-hour, hovering close to the record high seen last week.Since January, the contract has risen more than 250%.In the U.K., day-ahead energy prices for Monday reached an average of 291.18 euros per megawatt-hour, according to energy analysis firm LCP Enact. However, the maximum price for the U.K. on Monday could be as high as 1,083.78 euros per megawatt-hour, LCP Enact's analysis showed.Robert Buckley, head of relationship development at Cornwall Insight, told CNBC that the crisis was being caused by a "cocktail of pretty potent things" that were outside of suppliers' control.These included strong competition for natural gas deliveries between Europe and Asia, some outages at U.S. production facilities, and a tightening of EU carbon market rules, as well as various other factors."All suppliers will be finding it very tough at the moment," Buckley said. "Some of them are bigger and more resilient than others. But scale doesn't automatically equal resilience."He added that "it looks like it's going to get worse before it gets better" in terms of suppliers leaving the British electricity and gas market."[Suppliers are] caught between this rapture of the rising energy price wholesale market and the default tariff cap, and depending on who you believe, this is anywhere up to £200, £250 [$273, $341] below what a market-related cost would be at the moment, so that's 20% of the total bill," he said, referring to a cap on consumer energy prices in Britain. "That's -20% of gross margins. Very few [companies] can sustain that for any length of time."Meanwhile, Bill Bullen, founder of U.K. supplier Utilita Energy, warned that surging wholesale prices would inevitably lead to more insolvencies in the energy sector."We're heading back to an oligopoly at this rate and going backwards," he said in an email Monday.

Rising gas prices threaten a “winter of discontent” in Britain - The British media is filled with warnings that the huge rise in global gas prices will provoke a “winter of discontent” due to the desperate situation confronting millions of working people. According to trade association Oil & Gas UK, the price of wholesale gas has more than quadrupled since this time last year. It has jumped by 250 percent since January and 70 percent since August. The natural gas price hike is due to a combination of global events. Gas storage is low in most countries, particularly in Europe, and this has been exacerbated by the reopening of economies. Moreover, there is increased demand for gas in Asia, especially China, which has been moving away from coal and becoming more reliant on gas-fired power plants. These shortages have attracted the attention of the financier parasites in the imperialist countries, who have made a killing in the natural gas futures markets. Investors have been slow to unwind speculative positions they developed previously amid supply bottlenecks, driving up gas prices. This orgy of speculation is driven by the multi-trillion pandemic bailouts by the Fed, European Central Bank, Bank of England, et al. A growing narrative in the media pins the blame on the Putin administration in Russia. Typical was a Financial Times article on Monday headlined, “Why some see the hand of Russia in Europe’s gas price crisis”. The Guardian also referred to “Russian gas games” and complained, “As shipments of gas have turned from Europe towards China, flows of pipeline gas to Europe from Russia have failed to make up the shortfall.” The situation in Britain is particularly acute, with its energy market overexposed to the gas shortage. Less than 1 percent of Europe’s stored gas is held by the UK—which has among the lowest gas storage capabilities in Europe. Gas shortages have raised the spectre of a shutdown of large sections of the UK economy, including its food and drink sector, due to the crisis at fertiliser producer CF Industries. Its plants produce most of the carbon dioxide (CO2) used in food production and cold storage. Moreover CF's CO2 is used by nuclear power stations for cooling, and in the National Health Service for procedures including invasive surgery and endoscopy.

The ‘Big Lie’ of Blue Hydrogen Starts With Ignoring Basic Economics - As the oil and gas industry achieves success in pushing the world towards widespread adoption of methane-based blue hydrogen, some unexpected voices are calling out the industry on its deception of selling blue hydrogen as an affordable and clean source of energy.In August, Chris Jackson resigned as head of the UK Hydrogen and Fuel Cell Association, calling blue hydrogen an “expensive distraction.”To support his argument against blue hydrogen, Jackson accused the oil and gas companies pushing blue hydrogen of making false claims about the fuel’s true costs, noting that the UK Treasury has “been told that blue hydrogen is cheap.”A recent opinion piece at oil industry publication OilPrice.com, noting Jackson’s comments on the high cost of blue hydrogen, ran with the title “Exposing The Blue Hydrogen Lie.” The two biggest false claims about blue hydrogen are that it is clean energy and that it is economically viable. By misleading the public about these facts, the oil and gas industry, along with partners like investment banking company CitiGroup, hope to get billions in public money to pursue blue hydrogen without having to worry about its economic viability.As DeSmog reported, industry-backed lobbying efforts to sell the world on the promise of blue hydrogen are succeeding. These efforts include false claims but also often ignore the existing facts about blue hydrogen and the carbon capture technology that it required for its production.There are several ways to produce hydrogen, but almost all of it currently in production uses methane (natural gas) as the feedstock, with non-renewable energy powering that production. This process is called steam reforming, and breaks down methane into hydrogen and carbon dioxide. The result is what is known as “gray hydrogen,” or, if technology is used to capture the carbon dioxide emissions released during production, it becomes known as “blue hydrogen.”Columbia University Center on Global Energy Policy (CGEP), which is primarily funded by the oil and gas industry, is actively pushing blue hydrogen as clean energy. In April, CGEP released a paper advocating for large investments in the U.S. natural gas pipeline system, arguing that in the future the pipelines could be repurposed for hydrogen, thereby making it part of the climate solution.Then in August, CGEP held a presentation on what they call “Zero-C hydrogen” — the ‘C’ representing carbon. The panel was moderated by Adam Sieminski, senior advisor to the board of trustees for the King Abdullah Petroleum Studies and Research Center. Sieminski was part of a heavy Saudi presence for the event, joined by Khalid Abuleif, chief negotiator for climate agreements for the Kingdom of Saudi Arabia and Dr. Aqil Jamal, chief technologist for the carbon management research division at Saudi Aramco, the state owned oil and gas company. Such heavy representation by Saudi Arabia on a panel about hydrogen inevitably implied widespread industry support for blue hydrogen. Saudi Aramco’s CEO has told investors the company has big plans for blue hydrogen.The panel did not include any members who were critical of blue hydrogen.

How the natgas crisis emulates the Northern Rock crisis -- Izabella Kaminska - Britain’s natural gas shortage, and fears of a possible winter of discontent featuring 70s-style rolling blackouts, have been driving headlines all week. But a fact largely missing from the coverage is just how closely the structural situation resembles the one that drove the collapse of Northern Rock in 2007, and which later catalysed the wider financial crisis of 2008.Before we set out how, though, it’s worth stressing that the natgas shortage is not solely a UK phenomenon. Europe is suffering too. Significantly.The shortages themselves are the product of a perfect storm of global issues. These include under-stockpiling during the summer period in Europe due to more competition for LNG (liquid national gas) supplies from Asia; uncertainty related to delays in the launch of the Nord Stream 2 pipeline from Russia; and colder-than-expected weather in many parts of continental Europe, including Russia itself.While it may feel like the natgas price hike is particularly acute in the UK relative to Europe, where prices have at times been significantly lower, this is not outside the norm. Because the UK is a net importer, it often has to attract supplies from Europe via its Interconnector system by paying a premium. Bar a few transitory spikes every now and then the two markets, however, tend to trade very closely together.Another under-appreciated point is that the natgas market as a whole — not dissimilar to its close cousin the power market — has a historical susceptibility to extreme price moves and volatility. This is a function of there only being so much pipe and long-term storage in the system, and of a market incentive to never pay for expensive storage or excess reserves if it can be avoided. In recent years the rise of the LNG spot market, and the capacity to ship in volumes in an ad hoc manner from beyond the core pipeline system, has tempered some of that volatility. UK prices were remarkably stable throughout 2015-2019 as a result.But a big part of this crisis is related to the unexpected removal of that LNG buffer due to the additional demand from Asia. Prices are therefore reverting to their historically spikey norms. But even then, advocates of market-based solutions would not call that a problem. There is no better cure for high prices than high prices in their eyes. They see the market’s capacity to ease unexpected shortages by way of sudden but short-lived price hikes as a feature of the system, not a bug. This is because a finely balanced market needs very strong incentives to divert supplies to Britain when they are needed most, as well as extremely costly penalties for oversupplying when there are sudden collapses of demand. One important factor is that Britain was until recently an energy-independent nation, which made it very complacent about market-based risks. The other is more than a decade’s worth of efforts to liberalise the UK natgas market and make it increasingly dependent on real-time wholesale supplies.By 2017, such efforts had successfully driven consumer prices down relative to wholesale costs by increasing competition in the UK market from the incumbent Big Six players to as many as 70 organisations. Many of these new providers were happy to gain market share by undercutting rivals and offering below-cost deals to consumers.But the competition also had a downside. It made investing in critical infrastructure incredibly unappealing for any player still managing legacy assets.It was on the back of such market conditions that one of the UK’s largest natgas suppliers, Centrica, decided to close its Rough natural gas storage facility — the biggest in the country — in 2017. The facility was coming to the natural end of its life anyway, and would have needed a significant investment to modernise and revive it. But also, the chances of ever achieving a return on that investment were becoming increasingly negligible — especially in the context of ESG trends that risked making the underlying asset become stranded in the long term too.As a result, a vital reserve mechanism that had helped the UK stockpile gas in the summer for release in the winter months for many decades — smoothing supply and demand price shocks shocks in the process — was permanently lost.

It's all connected: The natural gas market and its casualties - Natural gas was supposed to be the so-called bridge fuel to the low-carbon renewable energy economy. It was abundant, cleaner to burn than oil and coal, and more and more available to anyone who wanted it as a global market in liquefied natural gas (LNG) blossomed and boomed.But this season it is looking increasingly like that metaphorical natural gas bridge is going to come up short. And, the effects are starting to ripple throughout the economy, not only in the natural gas markets themselves, but also in the electricity and agricultural markets.First, there are the obvious signs in the natural gas market. In both North America and Europe natural gas prices have bounded upward. In Europe gas import prices have zoomed up more than 400 percent in the last year from $2.86 per million BTUs (MMBtu) to $15.49 per MMBtu. In the United States the levitation is not as dramatic, but that may change once the cold weather sets in. U.S. natural gas futures prices were around $2.90 per mcf a year ago and closed Friday at $5.10 per mcf for the October contract. But the U.S. natural gas price was only about $3.90 per mcf just before Hurricane Ida knocked half of the natural gas production from the U.S. portion of the Gulf of Mexico offline. The other cause for rising natural gas prices is the surge in demand worldwide as economies boom in the wake of record fiscal stimulus and low interest rates in response to the pandemic. It wasn't supposed to be this way, we were told a decade ago. Natural gas from newly available shale deposits was going to provide the United States and the world with ample gas supplies for decades. Skeptics of this claim (myself included) thought we had a few years or at best a decade of incrementally better supply, but only if investors kept throwing money at the shale gas drillers despite ongoing losses—which investors did. Now, seven of the 10 major shale gas basins in the United States are in decline. The spike in U.S. prices is partly due to reduced drilling as investors finally pulled back from throwing good money after bad. The other problem is that drillers have exploited many of the sweet spots and soon will have to move on to gas that is harder to get and that will cost more to extract. In electricity markets the natural gas price spike had, well, electrifying effects, and not in a good way.Electricity prices in Europe have climbed 250 percent since January owing in part to the rise in the price of natural gas which now powers an increasing number of electric generating plants. In the United Kingdom electricity prices traded near all-time highs. The culprit once again was the price of natural gas and the fuel's expanded role in electricity generation. In the United States, the ability of power plant operators to switch between natural gas and coal may keep electricity prices from spiking there. But that's if U.S. coal prices don't continue to rise dramatically as they have all year. The effects on agriculture may also be dramatic because nitrogen fertilizers are made largely from natural gas. Two fertilizer factories closed in the U.K. recently because of high natural gas prices. It is an irony that high fossil fuel energy prices increase the cost of fertilizer which, in turn, increases the cost of growing biofuel crops such as soybeans and corn. Soybean and corn prices are soaring this year as their use for food competes against their use as feedstocks for fuels such as biodiesel and ethanol.A second irony is that just at this moment American consumers would be glad to have extra natural gas supplies and thus lower prices. They heard natural gas producers promise growing natural gas production far into the future. Investors heard that, too, and financed liquefied natural gas export terminals in the United States to send the excess production abroad.

Europe’s green ambitions could be hit as gas prices reach record highs - The European Union could struggle to advance its green agenda as gas prices soar across the bloc, according to experts who warn against slowing down investment into the sector.The European Commission, the executive arm of the EU, has vowed to become carbon neutral by 2050, presenting a concrete plan to reduce greenhouse gas emissions by at least 55% from 1990 levels by the end of this decade.However, these ambitions could be hit as a natural gas shortage on the continent drives prices higher. The front-month gas price at the Dutch TTF hub, a European benchmark, has risen more than 250% since the start of the year. It traded at about 74 euros ($87) a megawatt-hour on Tuesday — just shy of its record high of 79 euros it hit last week.The recent spike is already having a tangible impact. Spain, for instance, has announced emergency measures to limit the profits that energy companies can make from gas alternatives, including renewables. The government is also hoping to cap what consumers are paying for their electricity."Soaring energy prices have hit economies across Europe, and if Madrid's actions are imitated elsewhere as governments prioritize cheap energy over the green transition, the EU's credibility in advancing global climate action could take a hit," Henning Gloystein, director of energy at the consultancy firm Eurasia Group, said in a note Friday.Spain is not the only country to cap energy price increases, with France and Greece making similar moves. But the plan in Spain has been the subject of some criticism.Iberdrola, a Spanish energy firm with a focus on renewables, said the move "would undermine investor confidence in the country" at a time when the nation needs private money to achieve its climate ambitions."The risk to climate policymaking lies perhaps mostly in a loss of credibility ahead of the global COP26 climate talks in Glasgow later this year," Gloystein told CNBC via email."If wealthy countries in the EU are seen subsidizing energy for households that is in part supplied by fossil fuels, then the EU can hardly tell poorer countries to stop subsidizing household fuel consumption supplied by fossil fuels," Gloystein added.There is a wider problem, however: Some European leaders and lawmakers have blamed the EU for the energy price increases.Polish Prime Minister Mateusz Morawiecki, for instance, said earlier this month that "Polish power prices are tied to the EU's climate policies," according to Politico.When asked if comments like these could hurt the E U's green ambitions, Kirkegaard said: "There's absolutely that risk because clearly the Polish government want to extract more money from the EU for the green transition."

European carbon trade drives up global gas prices, by design - RBN Energy -- Global gas and LNG prices are currently at record high levels. If we sound like a broken record, it’s because this epic bull run that started in the spring, has been roaring in recent weeks and showing little sign of slowing down. European prices have hit new post-2008 or all-time highs more than 25 times since late June, and prices in Asia, which had been at seasonal all-time highs for most of the spring and summer, finally last week also topped its previous all-time record from last January. A confluence of bullish factors, including high global demand, low storage inventories, weather events, and supply outages, have all contributed to the surge in gas prices. While many of these are near-term drivers and will eventually flip in the other direction, there is one bullish driver of global gas demand — European carbon prices — that will remain a constant in the years to come. That is by design because the carbon market is meant to serve as an incentive for the industry to seek greener solutions over fossil fuels. In today’s RBN blog, we look at the European Union’s Emission Trading System (EU ETS) and how it interacts with the global gas market. Europe has the world’s oldest and largest carbon trading system. We’ll start with its origins to get a better understanding of how it works. The market, which now covers all the countries in the EU as well as Iceland, Liechtenstein and Norway, was established in 2005 to regulate emissions from power generation, manufacturing and some airline operations. Together, the sectors that fall under the ETS regulations account for about 40% of the EU’s total greenhouse gas (GHG) emissions. The EU ETS is a cap-and-trade system, meaning that there is an annual limit or “cap” on the total allowable GHG emissions from each of the roughly 10,000 installations covered by the ETS regulations. Each of the installations (say, a power plant or factory) receives a certain number of emissions allowances for a year. If an installation emits its exact allowance, then it is all set, but if it has extra allowances or needs more, that’s where the “trade” portion of cap-and-trade comes in. If an installation has extra allowances, it can bank them for the following year or sell them using the ETS and, if it needs more allowances, it has to purchase them. The open trading of emissions allowances provides a financial incentive for participants to go green and does it in a least-cost-first way. Basically, those who can reduce emissions cheaply, do so and then sell credits, and those who can’t, buy them. Either way, the overall market is capped, guaranteeing that the emissions don’t go over that level even though individual participants may emit more or less than what they were allotted.

The natural gas crisis is a much-needed reality check -- As energy ministers of major gas-producing nations and top executives of the world’s largest gas companies and commodity traders gathered in Dubai for the start of Gastech this week, natural gas prices in Europe continued to surge amid a very tight market. Demand is surging ahead of the winter heating season, but gas stocks are at multi-year lows, and supply cannot catch up with demand. Weather in northern Europe in recent weeks has reduced wind power generation, forcing utilities to turn to more gas and even coal – despite the EU’s green ambitions – to keep the lights on and industrial activities running. Consumers are feeling the pinch, and so are industries, some of which are curtailing operations. The gas and power price spikes threaten to knock back the post-COVID recovery in European economies. Governments are forced to intervene to help lower-income consumers and smaller power providers, and all political leaders are wary of higher energy costs for consumers (voters). Norway, Europe’s second-largest gas supplier after Russia, will boost deliveries this winter season, as Equinor was allowed to raise gas exports from the Oseberg and Troll fields. But Russia is not rushing to book additional capacity via Ukraine, leaving the European gas market very tight. Europe’s push for greener energy sources is the right thing to do, but not by putting the cart before the horse, according to Claudio Descalzi, CEO at Italy’s oil and gas major Eni. “You cannot cut supply without also reducing demand,” Descalzi told the Financial Times. “This is not something that is for a limited time, it’s structural,” the executive told FT, referring to the gas price spike. Investment in supply is needed and will be needed in the future, regardless of calls for no more investment in fossil fuels, according to the world’s top liquefied natural gas (LNG) exporter, Qatar, and to the head of OPEC

Enabled by Biden, Putin declares energy war on Europe -- Former President Donald Trump's delusional deference to Vladimir Putin was generally limited to his statements .President Joe Biden has no such excuse. Punishing Biden's appeasement of his energy blackmail policy, Putin is now waging an energy war on Europe. Biden only has himself to blame. Abandoning Trump administration and congressional sanctions, Biden approved Putin's Nord Stream 2 Gazprom pipeline . Facing fierce criticism, Biden then reached a Monty Python-esque deal with Germany. That agreement was supposed to ensure that Russia wouldn't use Nord Stream 2 to cut off Ukraine's access to billions of dollars in energy transit fees and extort European political appeasement in return for stable energy supplies. The deal was always a complete joke.Because Putin has now rewarded Biden with a delivery of farcical vengeance to make the great Russian satirist Nikolai Gogol proud.As energy reserves run short and the cold winter beckons, Russian energy giant Gazprom is withholding gas supplies to Europe. On Monday, Gazprom was offered the opportunity to book additional gas flows through pipelines feeding Europe (including Britain). Instead, Gazprom booked only a third of available capacity through Poland and roughly a tenth of available capacity through Ukraine. This has sent energy prices soaring even higher, now above $900 per 1,000 cubic meters. Gazprom's move follows similar supply cuts earlier this summer.There should be no illusions as to who is responsible for the cuts.Gazprom CEO Alexey Miller is a Putin puppet risen from the Russian leader's old guard in St. Petersburg. The political, versus business, character by which Gazprom ultimately operates is well known to the U.S. intelligence community. Indeed, Miller was sanctioned by the *cough* Trump administration *cough* back in 2018. Miller is following Putin's directives.This is also a KGB goodbye present to Angela Merkel.Set to leave office next week, the German chancellor has been Putin's greatest enabler (even openly hosting GRU chemical weapons facilities on her soil). Putin is telling Merkel how much he appreciates her weakness. There is a distinctly Russian message at play here. Literally and figuratively, Putin is presenting himself as the God of ice and fire.In that sense, this is also a message to Biden. The Russians want Washington to look weak and the Europeans to feel dependent on Moscow. Putin is letting everyone know that the only way Europe will ever stay warm is if Europe bows before Nord Stream 2 — Poland, the Baltics, and Ukraine be damned.But don't worry, as in Afghanistan, Biden's adults are now in charge.

The European Energy Crisis Is About To Go Global - It was only a matter of time, really. In a globalized world, energy crunches can hardly remain regionally contained for very long, especially in a context of damaged supply chains and a rush to cut investment in fossil fuels. The energy crunch that began in Europe earlier this month may now be on its way to America. For now, all is well with one of the world’s top gas producers. U.S. gas exporters have enjoyed a solid increase in demand from Asia and Europe as the recovery in economic activity pushed demand for electricity higher. According to a recent Financial Timesreport, there is a veritable bidding war for U.S. cargos of liquefied natural gas between Asian and European buyers—and the Asians are winning.Coal exports are on the rise, too, and have been for a while now, especially after a political spat had China shun Australian coal. But supply is tightening, Argus reported earlier this month. In July, according to the report, U.S. coking coal exports dropped by as much as 20.3 percent from June. The report noted supply was constrained by producers’ limited access to funding and a labor shortage that has plagued many industries amid the pandemic.All this should be good news for U.S. producers of fossil fuels. But it may easily become bad news as winter approaches. The Wall Street Journal’s Jinjoo Lee wrote earlier this week high energy prices could be the next hot import for the United States. Lee cited data showing gas inventory replenishment was running below average rates for this season, and gas in storage in early September was 7.4 percent below the five-year average.Coal inventories are also running low because of stronger exports, with prices for thermal coal three times higher than they were a year ago. According to calculations from the Energy Information Administration cited in the WSJ report, coal inventories in the United States could fall to less than half last year’s inventory levels by the end of the year. Last year, energy demand was depressed because of the pandemic. This year, the U.S. economy is firing on all cylinders once again.No wonder electricity prices are already going up.In a way, the events in Europe could be seen as a trailer of what might happen in the United States. It is a trailer because it shows all the worst bits. The United States is much more energy independent than, say, the UK, and that’s a big plus. Yet exports bring in revenues, and it would require government intervention to make gas producers cut exports.In an alarming move, such intervention was requested last week by a manufacturing industry group. Industrial Energy Consumers of America, an organization representing companies producing chemicals, food, and materials, asked the Department of Energy to institute limits on the exports of liquefied natural gas in order to avoid soaring prices and gas shortages during the winter, Reuters reported on Friday. Opinions seem to differ on whether rising LNG exports are in fact hurting U.S. consumers. But the fact is that gas prices are already double what they were a year ago. According to the IECA, they are not, however, high enough to motivate a ramp-up in natural gas production. Therefore, in order to stockpile enough gas for the winter, the U.S. government must force a reduction in exports. “Buyers of LNG who compete for natural gas with U.S. consumers are state-owned enterprises and foreign government-controlled utilities with automatic cost pass through,” Paul Cicio, president of IECA, said, as quoted by Reuters. “U.S. manufacturers cannot compete with them on prices.” Traders are already getting jittery, and this will likely contribute to price uncertainty; regardless of how the fundamentals situation develops. Again, Europe is at the heart of the uncertainty – or rather the certainty that prices have higher to climb. But now, China has added to concern about gas supply and the potential for shortages.

Baker Hughes CEO lays out 'hard truths' behind the energy transition as gas prices surge - The CEO of energy technology firm Baker Hughes has outlined what he feels are key points related to the energy transition amid deepening concern about rising gas prices and the knock-on effects this could have in the months ahead.In an interview with CNBC's Dan Murphy at the Gastech conference in Dubai, United Arab Emirates earlier this week, Lorenzo Simonelli was asked whether soaring gas prices were likely to be transitory or if he expected wider implications for consumers, markets and the broader economy."I think a lot of people are seeing what's happening in Europe and it's bringing to light the important discussion around the energy transition, and the importance that we have around gas as well," he said.It was still early to see if prices would remain high or if this rise was transitory, he said. Benchmark European gas prices have jumped over 250% since the start of the year, Reuters reported this week.The reasons for the spike are varied. The influential, yet typically conservative, International Energy Agency said on Tuesday that surging European gas prices had "been driven by a combination of a strong recovery in demand and tighter-than-expected supply, as well as several weather-related factors." "These include a particularly cold and long heating season in Europe last winter, and lower-than-usual availability of wind energy in recent weeks," it said.IEA Executive Director Fatih Birol said given that the reasons behind the price rise were multifaceted, it would be "inaccurate and misleading to lay the responsibility at the door of the clean energy transition."Birol's statement would appear to contrast views expressed by figures such as OPEC Secretary General Mohammed Barkindo. Barkindo told CNBC on Tuesday that soaring gas prices were the cost of the attempted shift to renewable energy sources."I have talked about a new premium that is emerging in the energy markets that I term the transition premium," Barkindo said. The effect of the gas price rise is already being felt on the ground. In the U.K., for example, it has caused a number of small energy suppliers to go bust. “We need energy security," Baker Hughes' Simonelli said. "And look, there's plenty of gas around the world, there's plenty of energy available," he added. "It's a question of bringing it to the market."On the energy transition — a term referring to a move from fossil-fuel based sources to ones such as solar and wind — Simonelli sought to highlight a number of issues he felt were important."We think there's three hard truths," he said. "Firstly, we've got to work together, accelerate the move towards decarbonization and also eliminating emissions.""Secondly, hydrocarbons are here to stay … and natural gas, in fact, is a key element. And thirdly, we've got to do it together, collaborate and actually adopt the new technologies that are available."Burning fossil fuels, such as oil and gas, is the chief driver of the climate emergency. And despite policymakers and business leaders repeatedly touting their commitment to net zero strategies, the world's fossil fuel dependency is expected to get even worse in the coming decades.

'We need to stop': Inside the world's first diplomatic alliance to keep oil and gas in the ground — Costa Rica and Denmark are spearheading efforts to build the world's first diplomatic alliance to manage the decline of oil and gas production. The co-leaders of the initiative, known as the "Beyond Oil and Gas Alliance," are seeking to establish a deadline for the end of oil and gas production that would get countries aligned with the 2015 Paris Agreement. This legally binding treaty aims to limit global heating to below 2 degrees Celsius above pre-industrial levels — and preferably to 1.5 degrees Celsius. Meeting the conditions of the agreement is widely recognized as critically important to avoid an irreversible climate crisis.The Beyond Oil and Gas Alliance is expected to formally launch at U.N.-brokered climate talks in early November, a summit known as COP26.Until then, Costa Rica and Denmark are seeking to persuade as many countries and jurisdictions as possible to join them in bringing an end to oil and gas production.It comes at a time when policymakers are under intense pressure to meet the demands of the climate emergency. Burning fossil fuels, such as oil and gas, is the chief driver of the climate crisis, and yet the world's fossil fuel dependency is expected to get even worse in the coming decades.Speaking on Thursday during an online webinar hosted by the International Renewable Energy Agency, Dan Jorgensen, minister for climate, energy and utilities for Denmark, said: "The science is clear. We cannot negotiate with nature.""There is no scenario in which we burn all the oil and gas that we can find and in which we stay below 2 degrees — and definitely not 1.5. It is just not possible, so we need to stop."

Fears remain oil still inside X-Press Pearl ship - Fears remain that there maybe oil still inside the sunken ship, X-Press Pearl, despite various assurances given earlier, officials said. Darshani Lahadupura, the Chairperson of the Marine Environment Protection Authority (MEPA) told Daily Mirror that foreign experts believe that there is no bunker oil remaining in the ship. However, she said the ship owners have been informed that the wreckage can be removed only once there is 100 percent confirmation that there is no bunker oil remaining in the vessel. She said that divers will need to go inside and conduct a physical inspection and give an assurance that there is no oil left. “If there is oil left they will need to transfer it to another tanker before removing the wreckage. It’s a must,” she said. Lahadupura said that the wreckage continues to be monitored, including through the use of drones, to detect any possible oil spill. She said that a thin sheen of an oil slick which emerged after the ship sank, is still visible but has reduced. Asked if it was confirmed that the thin sheen was oil and not any other material as was claimed by some authorities earlier, Lahadupura insisted that it was oil but not bunker oil. She also said that Sri Lanka is keen to have the ship and containers which are in the seabed removed at the earliest. “We want to remove this as early as possible. Coastal fishing is banned mainly because of these sunken containers,” she said. She said that a caretaker company has deployed divers to conduct underwater surveys of the containers. Lahadupura said that the ship owners have called for tenders to remove the wreckage and a number of companies, including those from Sri Lanka have expressed interest. Meanwhile, MEPA said that samples of the plastic nurdles from the ship have been sent to overseas labs for testing. Lahadupura said that some samples have been sent to London for testing while others will be sent to other foreign labs to identify the hazardous material in the plastic.

China Risks Winter Energy Crunch -- China is at risk of the same energy-crunch chaos seen in Europe, with a state-run newspaper warning that coal-fired power plants will struggle to keep the lights on this winter. The nation’s coal-based power producers, which account for more than 70% of the country’s electricity generation, are unable to buy enough fuel after prices surged, state-run China Energy News said in a report dated Sept. 18. Officials at those plants say they have little coal in inventories, and it’s “almost impossible to buy” the fuel right now, the paper said. Many are struggling with deep operation losses, and some have even turned off their boilers to save costs, the report said. Energy markets across the world are being rocked by soaring fuel prices, with power companies clambering to secure supplies of everything from coal to gas to fuel oil. Europe has borne the brunt of the crunch, though the U.S. hasn’t been spared either, with electricity prices for the winter soaring to a seven-year high. In China, the situation has been exacerbated by President Xi Jinping’s ambitious climate goals that discouraged dirty coal mining. A lack of power to supply the world’s second-biggest economy could throw millions of factories and households into chaos, especially when consumption for heating is about to increase during winter. China’s power producers have such low inventories that some have even warned they only have about a week’s worth of coal left, the Chinese energy newspaper said, without identifying the officials or their plants. The paper, a mouthpiece of the state-run People’s Daily, used to be run by the National Energy Administration, the country’s top power regulator. Chinese power generators are prioritizing procuring enough coal at the moment and are willing to pay whatever the freight costs, the newspaper said, citing an unnamed official at a plant in the Northeastern region. Traders from the factory were hunting for supplies across the country, only to find out rivals in the Southwestern province of Guizhou, a major coal producing region itself, were competing with them, the newspaper said. Prices of coal, China’s principal source of energy, have leapt to unprecedented levels after a trade spat with Australia led Beijing to halt imports from the producer. Meanwhile, a spate of fatal accidents in China led to safety inspections earlier this year that curbed domestic output. The most-traded thermal coal futures in Zhengzhou closed at 1,057.8 yuan ($164) per ton on Friday, up 76% in the past year.

The future of China’s gas demand - After a pandemic slowdown last year, China’s demand for gas appears to have returned stronger than before. In H1 2021, China’s gas demand saw a 16% year-on-year increase, led by strong power and industrial demand. Underperforming hydropower in southwest China, tight coal supply coupled with high coal prices across the country, and high summer temperatures supported gas-fired power generation. Export-led economic growth and domestic consumption recovery benefited overall energy demand, including natural gas. So far, China’s gas demand has exceeded expectations and we now expect gas demand to increase by 13%, or 42 billion cubic metres (bcm), year-on-year in 2021. But how far can it go and how could carbon neutrality impact the role of gas in China? There are many reasons to believe gas demand still has vast room to expand above current levels. Natural gas fits into China’s strategies to diversify the coal-dominated energy mix, improve air quality, and pursue low-carbon development. To meet its rising demand, China has been boosting domestic production, debottlenecking infrastructure, diversifying import sources and introducing market-oriented reforms. In our base case, we expect demand to grow at 5.5% a year on average between 2020 and 2030. Post-2030, growth will decelerate but by 2050 China’s gas demand could reach around 660 bcm. The demand increase comes with structural changes. Historically, gas use in the industrial sector (as fuel and feedstock) dominated overall gas demand in China, contributing to about 50% of the market. The share dropped to 42% in 2020. Industrial gas demand will continue to grow as the potential for coal-to-gas switching in the coastal regions remains significant. Governments in coastal provinces are targeting the sector to reduce coal consumption and improve air quality. However, the growth rate will slow as China’s industrial energy demand peaks. In inland provinces, gas will struggle to increase its share where coal is the main pillar of local economies. By 2050, industrial gas demand will account for 34% of total gas demand. Residential, commercial and space heating (RCH) demand is fast catching up. Coal-to-gas switching in RCH has already magnified China’s winter demand peaks. The trends of urbanisation, higher affordability, gas distributors building new city gas projects and winter clean heating requirements will provide gas access to a broader population. Gas storage facilities and flexible supply sources like LNG will be key for peak shaving. By 2050, RCH gas demand could account for 40% of total gas demand.

Oil Down With China Demand Concerns - Oil declined amid growing concerns over the health of China’s economy that have triggered massive losses in equities. U.S. crude futures slid 2.3% to settle at the lowest level in more than a week as worries mounted over a possible implosion in the Chinese property sector that could impact the Asian giant’s appetite for crude. A stronger U.S. dollar is also making commodities priced in the currency less attractive. “China is the global swing demand center,” said John Kilduff, a partner at Again Capital LLC. “If we lose China, we will lose much of the recent oil price gains.” Crude prices have fared well so far this month -- U.S. oil futures are up about 4% in September -- in part due to lingering supply disruptions from storms that have swept through the U.S. Gulf of Mexico. Royal Dutch Shell Plc said some critical U.S. Gulf of Mexico oil-production assets for Mars crude supply will be out of service for the rest of this year. While oil fundamentals are pointing to higher prices, a planned U.S. Federal Reserve meeting this week could signal the central bank is moving toward scaling back asset purchases, possibly weakening global crude oil benchmarks. West Texas Intermediate for October delivery dropped $1.68 to settle at $70.29 a barrel in New York. Brent for November settlement fell $1.42 to settle at $73.92 a barrel. Investors are also continuing to monitor the energy crunch in Europe amid talk of switching from gas to oil. There are expectations diesel demand will expand in Asia during winter, while the use of oil to generate power in the U.S. may jump.

Oil falls 2% on risk aversion, dollar strength - Oil prices fell 2% on Monday as investors grew more risk averse, which hurt stock markets and boosted the U.S. dollar, making oil more expensive for holders of other currencies. Brent crude fell $1.42, or 1.9%, to settle at $73.92 a barrel after sinking to a session low of $73.52. U.S. West Texas Intermediate (WTI) declined $1.68, or 2.3%, to end at $70.29 after falling to as low as $69.86. The dollar, seen as a safe haven, rose as worries about Chinese property developer Evergrande's solvency spooked equity markets and investors braced for the Federal Reserve to take another step toward tapering this week. "As the U.S. dollar is usually a safe haven, its exchange rate against other currencies strengthens, a development that supplements the risk aversion environment and affects commodity prices, especially oil," Rystad Energy's oil markets analyst Nishant Bhushan said. "Oil gets more expensive for non-dollar markets and prices get a hit as a result, a bearish move backed by the stock market itself in an environment of risk aversion." Still, oil drew some support from signs that some U.S. Gulf output will stay offline for months due to storm damage. Brent has gained 43% this year, supported by supply cuts by the Organization of the Petroleum Exporting Countries and allies, and some recovery in demand after last year's pandemic-induced collapse. Losses on Monday were limited due to supply shutdowns in the U.S. Gulf of Mexico due to two recent hurricanes. As of Friday producing companies had just 23% of crude production offline, or 422,078 barrels per day. Crude pared its decline on Monday after Royal Dutch Shell said it expects an installation in the Gulf of Mexico to be offline for repairs until the end of 2021 due to damage from Hurricane Ida. The facility serves as the transfer station for all the output from the company's assets in the Mars corridor of the Mississippi Canyon area to onshore crude terminals. Rystad Energy analyst Artem Abramov estimated the lost production will remove 200,000 to 250,000 barrels per day (bpd) of Gulf of Mexico oil supply for several months. The Gulf contributes about 16% of U.S. oil production, or 1.8 million bpd.

Oil Futures Reverse Higher as US Lifts Travel Restrictions - -- Following Monday's selloff triggered by concerns over China's economic growth and prospects for the U.S. Federal Reserve to taper pandemic-era monetary stimulus, oil futures nearest delivery on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange reversed higher in overnight trade as investors turned their attention to an improved outlook for global oil demand in the fourth quarter after the United States lifted travel restrictions on fully vaccinated foreign travelers from 33 countries, boosting the prospect for increased international air travel and global jet fuel demand. Near 7:30 a.m. ET, NYMEX October West Texas Intermediate futures advanced $0.73 to trade just above $71 per barrel (bbl) ahead of the contract's expiration this afternoon, and next-month delivery November WTI traded at a $0.15 discount. Brent crude for November delivery added $0.68 to $74.60 bbl. NYMEX October ULSD futures surged 2.34 cents to $2.1824 gallon, and front-month RBOB futures gained 1.12 cents to $2.1264 gallon. The White House announced on Monday it would ease travel restrictions on all noncitizens visiting the U.S. willing to show proof of vaccination and/or a negative COVID-19 test within three days of departure. The changes will take effect in early November, which analysts believe would spur holiday bookings this year. Biden Administration has been reluctant to reopen U.S. airspace for noncitizen travels despite United Kingdom and European officials having lifted entry bans for U.S. and other visitors since vaccines became widely available this spring. Monday's announcement came after the peak summer travel season boosted domestic gasoline demand but a recovery in jet fuel consumption has long been elusive absent international travel. Average jet fuel consumption in August was more than 1.5 million barrels per day (bpd), nearly 400,000 bpd higher than in March, while still well still below pre-pandemic levels of 1.8 million bpd in August 2019, according to the U.S. Energy Information Administration. Airlines have been using some of their biggest planes, normally reserved for international trips, for domestic routes, a trend that is now expected to change if demand from abroad rises with the new rules. Allowing more international travelers into the U.S. would also have a wide-ranging affect for domestic leisure, retail, and travel industries.

Oil edges up, as investors worry about global demand (Reuters) - Oil prices rose modestly in a see-saw session on Tuesday, as concerns about the global consumption outlook counterbalanced the struggle by big OPEC producers to pump enough supply to meet growing demand. Both benchmarks were at one point up by $1 per barrel, but Brent crude pared gains and settled just up 44 cents at $74.36 a barrel, after falling by almost 2% on Monday. The October West Texas Intermediate (WTI) contract, which expired on Tuesday, rose 27 cents to settle at $70.56 a barrel, after dropping 2.3% in the previous session. The more active November contract rose 35 cents a barrel to $70.49. Brent and the November WTI contract earlier reached session highs of $75.18 a barrel and $71.48 per barrel, respectively. "It seems to be a very nervous trade today," said Phil Flynn, senior analyst at Price Futures group in Chicago. "It's a little bit of ongoing concerns about the potential impact of demand going forward." The TASS news agency said Russia believes global oil demand may not recover to its 2019 peak before the pandemic, as the energy balance shifts. However, the Organization of the Petroleum Exporting Countries and its allies including Russia (OPEC+) struggled to pump enough oil in August to meet current consumption as the world recovers from the coronavirus pandemic. Several countries appeared to have produced less than expected as part of the OPEC+ agreement - suggesting a supply gap could grow. Investors across financial assets have been rocked by fallout from the China Evergrande crisis that has harmed asset values in risk markets like equities. "Traders worried that it could trigger a domino effect in China’s major debt-driven companies, and a rollover bearish effect for stocks and commodity prices," said Nishant Bhushan, oil markets analyst at Rystad Energy. "However, given that all Chinese major banks and lending institutions are controlled by the government, there is a ray of hope in the market that the second biggest economy in the world would be able to absorb shock waves from the Evergrande." In addition, the U.S. Federal Reserve is expected to start tightening monetary policy, which could cut investor tolerance for riskier assets such as oil. Fed policymakers began a two-day meeting Tuesday. U.S. oil production is still recovering from hurricanes that hit the Gulf Coast region. Royal Dutch Shell, the largest U.S. Gulf of Mexico oil producer, said on Monday that damage to offshore transfer facilities from Hurricane Ida will cut production into early next year. About 18% of the U.S. Gulf's oil and 27% of its natural gas production remained offline on Monday, more than three weeks after Ida. U.S. crude oil, gasoline and distillate inventories fell last week, according to market sources, citing American Petroleum Institute figures on Tuesday, as numerous refineries and offshore drilling facilities remained shut following Hurricane Ida.

WTI Extends Gains After Across The Board Inventory Draws - Oil prices managed gains today, rebounding off an ugly tumble back below $70 (WTI) around the US cash equity open, as supply constraints trumped any Evergrande or Delta related demand concerns.The rise came as "the oil market will remain tight" for as long as demand concerns do not materialize, Carsten Fritsch, energy analyst at Commerzbank Research, said Tuesday in a note."U.S. oil production in the Gulf of Mexico is likely to remain hampered for considerably longer than previously anticipated," he said. Algos' eyes wil be on API tonight and the official data tomorrow to see just how lasting the effects of Hurricane Ida will be. API

• Crude -6.108mm (-3.8mm exp)
• Cushing -1.748mm
• Gasoline -432k
• Distillates -2.72mm

Analysts expected crude stocks to drop for the 7th week in a row as the effects of Ida continue, and they were right as API reported a much bigger than expected 6.108mm barrel crude draw (and draws across products and at Cushing)... WTI hovered around $70.60 ahead of the API print.Some of the volatility in Tuesday’s trading session may have stemmed from traders adjusting positions ahead of the expiration of Nymex October crude futures. “There are supply issues all around the market,” Notably, U.S. stockpiles of the so-called big 4 - crude oil, gasoline, distillate, and jet fuel - are combined, below 2018 levels now, according to data compiled by HFI Research.

WTI Surges on Large Crude Draw Ahead of FOMC Announcement - Nearby delivery oil futures on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange pushed higher in pre-inventory trade Wednesday after preliminary data from the American Petroleum Institute showed U.S. commercial crude oil inventories once again fell above consensus last week amid ongoing production outages in offshore Gulf of Mexico, while global financial markets moved to risk-on sentiment following a reported deal between China's Evergrande and private creditors on more than $36 million in loan payments to fuel additional buying interest. Near 7:30 a.m. ET, NYMEX November West Texas Intermediate advanced $1.09 to $71.58 per barrel (bbl) and Brent crude for November delivery added $1.02 to trade back above $75 bbl. NYMEX October ULSD futures surged 2.55 cents to $2.1993 gallon, and front-month RBOB futures gained 2.62 cents at $2.1314 gallon. Early morning gains in the oil complex underpinned by the bullish inventory report released by the API Tuesday afternoon showing U.S. commercial crude oil inventories decreased 6.108 million bbl in the week-ended Sept. 17, more than twice calls for a draw of 2.4 million bbl. If confirmed in government data this morning, larger-than-expected crude draw would press oil inventories some 8% below the five-year average. Domestic crude stockpiles remained in a destocking pattern since the first week of August, drawing down more than 20 million bbl over the past two months. Data also showed stocks at the Cushing, Oklahoma hub dropped 1.748 million bbl. Gasoline stockpiles declined 432,000 bbl in the profiled week, below estimates for a 1 million bbl decrease. DTN's Refined Fuels Demand data revealed total U.S. gasoline demand softened 1.3% compared to the same week in 2019, after being down 2.4% from 2019 levels in the prior week. API data show distillate inventories dropped 2.720 million bbl, surpassing an estimated decline of 190,000 bbl. Diesel demand was up 2.3% relative to the same week in 2019, according to DTN's Refined Fuels Demand data, weakening slightly after being up 2.8% compared to 2019 levels in the prior week. Separately, Organization for Economic Cooperation and Development on Tuesday revised lower its 2021 global and U.S. growth projections, citing severe disruptions to global supply chains and higher-than-expected inflation across G20 countries.

WTI Slides After Surprise Gasoline Build, Smaller Than Expected Crude Draw - Oil prices are extending yesterday's gains this morning following a bigger than expected crude draw reported by API, and optimism from China as Evergrande pays a tiny coupon on a tiny yuan bond, and China injecting a metric fuckton of liquidity also. “Oil prices are gaining today as the API inventory forecasts show draws above what the market expects, while the supply side of the equation looks tight in the U.S. and at a global level,” according to Louise Dickson, senior oil markets analyst at Rystad Energy. DOE

• Crude -3.481mm (-3.8mm exp)
• Cushing -1.476mm
• Gasoline +3.474mm
• Distillates -2.554mm

This is the 7th straight week of crude draws (prior to this, we saw 8 straight weeks of draws during May-June-July when the pull from refiners preparing for a surge in summer demand along with relatively stable output sent volumes lower), but we note that the official draw was less than API reported and smaller than expected. Cushing crude stocks are now sitting seasonally below the 10-year average after a long stretch of declines. Gasoline stocks surprised with a build...US Crude production remains significantly impacted by Hurricane Ida shut-ins still (just this week, Shell announced that some of its offshore Gulf production would stay offline through the end of this year because of damages)... Crude prices have increased this month after extreme weather disrupted U.S. supplies, and as a rally in natural gas spurred expectations consumers may switch to oil.

Oil prices rise on U.S. stocks draw, rising fuel demand --- Oil prices climbed more than $1 on Wednesday after U.S. crude stocks fell to their lowest levels in three years as refining activity recovered from recent storms. Despite recent wobbles from U.S. economic figures, overall demand for fuel has rebounded to pre-pandemic levels. Product supplied over the last four weeks has come in at nearly 21 million barrels per day, not far from 2019's peak. U.S. crude inventories last week fell by 3.5 million barrels to 414 million barrels, lowest since October 2018, the U.S. Energy Information Administration said on Wednesday. "Crude oil prices remain supported as demand recovers around the world and inventories continue to draw," said Andrew Lipow, president of Lipow Oil Associates in Houston. U.S. West Texas Intermediate (WTI) crude futures settled $1.74, or 2.47%, higher at $72.23 per barrel. Brent crude futures climbed $1.54, or 2%, to $75.89 a barrel. Oil facilities in the Gulf of Mexico continue to return to production, with weekly output rising 500,000 bpd in the most recent week to 10.6 million bpd, the EIA said. BP on Wednesday said all four of its offshore facilities in the region have resumed operations after Hurricane Ida, brought back online and producing as of Sept. 12. Also supporting prices has been difficulties by OPEC members struggling to raise output. Rising prices in other markets like natural gas have also supported oil, with energy market shortages causing a supply crunch in Europe and Asia. "Given the variety of supportive factors in the energy space, notably sky-high natural gas prices ... dips in prices right now are likely to be short-lived," said Jeffrey Halley, an analyst at brokerage OANDA. The U.S. Federal Reserve, which began a two-day policy meeting on Tuesday, is expected to start tightening monetary policy, which could cut investor tolerance for riskier assets such as oil.

Oil Rises Again With Brent At Three Year High - Brent crude futures settled at the highest level in almost three years as supplies shrink at a time when a global energy crunch makes it increasingly likely oil will be tapped for power generation. The global benchmark crude rose 1.4% on Thursday to close at the highest level since October 2018, while U.S. crude futures advanced 1.5%. U.S. equities rallied and the dollar weakened, boosting the appeal of commodities priced in the currency. Oil inventories are rapidly tightening. Supplies in the U.S. are at the lowest since 2018 with output levels weaker after recent U.S. Gulf Coast storms, while stockpiles at a key hub in Europe remain below average levels for the time of year. Some of the world’s largest oil traders and banks are predicting crude prices to surge even higher this year. Vitol Group sees oil rising above $80 a barrel, partly as surging gas prices boost demand for crude in power generation. Goldman Sachs Group Inc. said crude may top $90 if the coming winter in the northern hemisphere proves colder than normal. Crude futures have steadily climbed higher this month as traders weigh the impact of a tightening natural gas market on the broader energy complex over winter. The focus has led to cross-commodity flows across the oil and gas markets, some of which have been unwound in recent days, which had helped to push crude higher. “We’re still not seeing a very robust recovery in U.S. production levels, so we have a situation where demand is deemed to look a little bit better and the supply side is at risk of not delivering what we thought,” said Bart Melek, head of commodity strategy at Toronto Dominion Bank. Prices: West Texas Intermediate for November settlement advanced $1.07 to settle at $73.30 a barrel in New York, the highest level since July Brent for the same month added $1.06 to end the session at $77.25 a barrel Oil is most likely headed above $80 a barrel, partly as higher gas prices boost demand, Vitol Chief Executive Officer Russell Hardy said in an interview from London on Thursday. That could force OPEC+ producers to add more supply into the market, he said.

Oil Closes On Five Week Win Streak - Oil prices rose for a third week in a row to a near three-year high on Friday as global output disruptions have forced energy companies to pull large amounts of crude out of inventories. The rally was slightly dampened by China's first public sale of state crude reserves. Brent futures rose 84 cents, or 1.1%, to settle at $78.09 a barrel, while U.S. West Texas Intermediate (WTI) crude rose 68 cents, or 0.9%, to settle at $73.98. That was the highest close for Brent since October 2018 and for WTI since July 2021, both for a second day in a row. It was the third week of gains for Brent and the fifth for WTI mostly due to U.S. Gulf Coast output disruptions from Hurricane Ida in late August. New York Harbor Ultra Low Sulfur Diesel (ULSD) futures also closed at their highest since October 2018. "As oil prices are on track to close another week of gains, the market is pricing in a prolonged impact of supply disruptions, and the likely storage draws that will be needed to fulfill refinery demand," said Louise Dickson, senior oil markets analyst at Rystad Energy. Some disruptions could last for months and have already led to sharp draws in U.S. and global inventories. U.S. oil refiners were hunting to replace Gulf crude, turning to Iraqi and Canadian oil, traders said. India's crude imports rose to a three-month peak in August, rebounding from July's near one-year low. Some members of the Organization of the Petroleum Exporting Countries and their allies, known as OPEC+, have struggled to raise output due to under-investment or maintenance delays during the pandemic. Russia said it will remain a reliable supplier of energy to global markets. Russian gas giant Gazprom had been accused of doing too little to increase its natural gas supplies to Europe, where prices have soared. Iran, which wants to export more oil, said it will return to talks on resuming compliance with the 2015 Iran nuclear deal "very soon", but gave no specific date. Edward Moya, senior market analyst at OANDA, said: "Extra Iranian barrels of crude seem unlikely to be a 2021 story," noting negotiations "will be a long drawn-out process." Kazakhstan's biggest oil producer, Chevron-led Tengizchevroil (TCO), will delay components of its $45.2 billion expansion project by three to seven months. In the United States, drillers added 10 oil rigs this week, putting the oil and gas rig count up for a 14th month in a row. Brent could hit $80 by the end of September due to stock draws, lower OPEC production and stronger Middle East demand, UBS analysts wrote. China's first public sale of state oil reserves capped crude price gains. PetroChina and Hengli Petrochemical bought four cargoes totaling about 4.43 million barrels, sources said. Analysts also noted indebted China Evergrande remains a risk to oil prices after the company's electric car unit warned it faced an uncertain future unless it got a swift injection of cash.

Oil hits highest in almost 3 years as supply tightens - Oil rose for the fifth straight week with the global energy crunch set to boost demand for crude as stockpiles decline from the U.S. to China. Futures in New York gained 2.8% this week. The global benchmark Brent settled at the highest in nearly three for the second day in a row. Global onshore crude supplies sank by almost 21 million barrels last week, led by China, according to data analytics firm Kayrros, while U.S. inventories are near a three-year low. The surge in natural gas prices is expected to force some consumers to switch to oil, tightening the market further ahead of the northern hemisphere winter. “The market is pricing in a prolonged impact of supply disruptions, and the likely storage draws that will be needed to fulfill refinery demand,” said Louise Dickson, oil markets analyst at Rystad Energy, in a note. In terms of oil demand, “no new lockdowns in Europe, robust recovery in China road activity, and the U.S. nixing its ban on foreign travelers from November 2021, all lift prospects for upside in the coming quarters.” Oil has steadily climbed higher this month after a period of Covid-induced demand uncertainty, with some of the world’s largest traders and banks predicting prices may climb further amid the energy crisis. Global crude consumption could rise by an additional 370,000 barrels a day if natural gas costs stay high, according to the Organization of Petroleum Exporting Countries. Various underlying oil market gauges are also pointing to a strengthening market. The key spread between Brent futures for December and a year later is near $7, the strongest since 2019. That’s a sign traders are positive on the market outlook. Money managers increased their bullish ICE Brent bets positions to the most in six months, indicating many believe there’s yet more room for crude prices to climb. West Texas Intermediate for November delivery rose 68 cents to $73.98 a barrel in New York. Brent for November settlement climbed 84 cents to $78.09 a barrel, the highest since October 2018. At the same time, the premium options traders are paying for bearish put options is the smallest since January 2020, another indication that traders are less concerned about a pullback in prices.

Oil Futures Settle Notably Higher For The Session, Gain 2.8% In Week - Crude oil prices climbed on Friday and front-month WTI oil futures contracts recorded gains for a fifth straight week amid tighter supplies. Recent data showing a drop in U.S. crude inventories and output disruptions in the Gulf of Mexico due to the impact of two hurricanes supported oil prices. The public auction of state crude reserves by China limited oil's advance . According to reports, PetroChina and Hengli Petrochemical bought four cargoes totaling about 4.43 million barrels in the auction. West Texas Intermediate Crude oil futures for November ended higher by $0.68 or about 0.9% at 73.98 a barrel. WTI Crude futures gained about 2.8% this week. Brent crude futures posted a third straight weekly gain. The contract was up $0.72 or 0.93% at $77.97 a barrel a little while ago. A few members of the Organization of the Petroleum Exporting Countries and their allies, collective known as OPEC+, are reportedly finding it tough to increase output due to the pandemic and a lack of funds. According to the data released by Baker Hughes, the number of active U.S. rigs drilling for oil climbed by 10 to 421 this week. The total active U.S. rig count, including those drilling for natural gas, climbed by 9 to 521, the data said.

New Iranian president calls for resumption of nuclear talks in UN speech - Recently elected Iranian President Ebrahim Raisi called for a resumption in nuclear talks in a pre-recorded address given at the United Nations General Assembly on Tuesday."The Islamic Republic considers the useful talks whose ultimate outcome is the lifting of all oppressive sanctions," Raisi said, as Reuters reported.Nuclear talks among Tehran negotiators and world powers in Viennaadjourned in June. The U.S. has so far not reengaged directly with the negotiations, instead participating indirectly through allies.Washington wants Tehran to reenter into the terms of the deal before moving forward, but the Iranians counter that U.S. sanctions must be lifted before they will be willing to return to the Obama-era accord.Raisi won the Iranian presidential election shortly the talks were adjourned. The state of ongoing negotiations was left up in the air following his election. The new Iranian president is known for being an ardent critic of the West and has been sanctioned by the U.S. for alleged human right abuses when he was a judge.Earlier this month, Raisi had indicated that Iran was prepared to rejoin nuclear negotiations."The Westerners and the Americans are after talks together with pressure ... What kind of talks is that? I have already announced that we will have talks on our government's agenda but not with ... pressure," Raisi on state television."Talks are on the agenda ... We are seeking goal-oriented negotiations ... so unjust sanctions on the Iranian people are lifted ... and their lives can flourish," he added.When reached for comment by The Washington Post, a State Department official said the U.S. does not "have a timetable" on rejoining negotiations, but added that "our position is that we’re ready to go back."However, the State official warned that eventually restarting negotiations "won’t be possible any more, because their nuclear advances will become irreversible, and it simply will not be feasible to go back the deal."

Yemen, devastated by war, now faces a Covid surge, a nonprofit says. -War-torn Yemen, where the overwhelming majority of the population is unvaccinated, is seeing coronavirus cases multiply and deaths soar, according to a report this week by the charity Oxfam. Oxfam, which describes itself as a global anti-poverty and humanitarian group, found that Covid deaths had increased by more than fivefold in the past month and that recorded Covid cases had tripled. The charity said actual figures were likely to be much higher, with many unregistered cases and deaths. The official Covid death toll is about 1,658, and recorded cases have reached 8,789. But the situation in the country of about 30 million is hard to gauge. “Countless” others have died in their homes or have not been diagnosed because of scarce tests and hospital beds, Oxfam said. Yemen is still embroiled in a war that began in 2014 when Iran-backed rebels know as the Houthis seized the country’s northwest, including the capital, Sana, sending the government into exile. The government has effectively collapsed, and tens of thousands have died. The country already faced many health challenges before the coronavirus emerged. Hunger is widespread, medicines are hard to find and there have been outbreaks of cholera and other diseases. The pandemic has only exacerbated the situation, and rights groups say that it is adding to the burden of an already wrecked health care system. “Covid has made life even worse for people across the country,” Abdulwasea Mohammed, Oxfam’s policy and advocacy lead for Yemen, said by phone from Sana. Some relief could come with vaccines, but fewer than 1 percent of Yemenis have so far received a single vaccine dose, and only 0.05 percent are fully vaccinated, according to Oxfam. The country is relying on vaccines from the global Covax program. But Covax is struggling to meet its global supply target, and only half a million out of a promised 4.2 million doses have reached Yemen so far, Oxfam said.

Amnesty International accuses Taliban of killing civilians, blocking humanitarian aid - Amnesty International on Monday detailed alleged human rights abuses being carried out by the Taliban about a month after the militant group took over the Afghan government. Dinushika Dissanayake, Amnesty International's deputy director for South Asia, said in a statement, "In just over five weeks since assuming control of Afghanistan, the Taliban have clearly demonstrated that they are not serious about protecting or respecting human rights. We have already seen a wave of violations, from reprisal attacks and restrictions on women, to crackdowns on protests, the media and civil society." The international human rights organization said the Taliban have already gone back on their promises of amnesty for government officials and protection for journalists. Based on Amnesty International's research on the situation in Afghanistan, the Taliban have begun targeting Afghan police officers, including reportedly killing one who was pregnant at the time. The Taliban also allegedly kidnapped popular Afghan comedian Nazar Mohammad, a former police officer, from his home and had him killed. "While it is now almost impossible to carry out any human rights work, attacks on human rights defenders have reportedly been on the rise without any sign of abating," Amnesty International said. "Since 15 August, the Taliban and armed groups have engaged in large-scale door-to-door searches, forcing human rights defenders into hiding, and moving clandestinely from one place to another." One Afghan female human rights activist named only as Kobra said in Amnesty's briefing that she was questioned by Taliban sympathizers in the weeks before Kabul fell. She left the country about four days after Kabul was overtaken and said Taliban fighters went to her home on the day she left and questioned her neighbors. "Today, for what sin did we have to leave our homeland, our loved ones, and our life and for which sin we suffered such hardship at the gates to enter the Kabul airport," Kobra said.

Afghanistan’s Health System Is on the ‘Brink of Collapse,’ W.H.O. Says - Dr. Tedros Adhanom Ghebreyesus, the W.H.O. director general, warned of an “imminent humanitarian catastrophe” as the country’s health care system struggles with a loss of foreign funding and dwindling supplies. Over the past 20 years, significant health gains have been made in Afghanistan in reducing maternal and child mortality, moving towards polio eradication, and more. Those gains are now at severe risk with the country’s health system on the brink of collapse. There has been a surge in cases of measles and diarrhea. Almost 50 percent of children are at high — at risk of malnutrition. The resurgence of polio is a major risk, and 2.1 million doses of Covid-19 vaccine remain unused. Unless urgent action is taken, Afghanistan faces an imminent humanitarian catastrophe. Health workers are leaving, creating a brain drain that will have consequences for years to come. We visited a hospital where we met some nurses who have stayed. My heart broke when they told me they have not been paid in three months. The focus of our efforts now is to support and sustain the Sehatmandi Project, which is the backbone of Afghanistan’s health system, providing care for millions of people through 2,300 health facilities, including in remote areas. But a funding pause by major donors — only 17 percent of these facilities are fully functional. And two-thirds have stockouts of essential medicines.

Taliban hang body from crane in city square - The Taliban hung a body from a crane in the main square of Herat city, a witness to the incident told The Associated Press on Saturday.Wazir Ahmad Seddiqi, who runs a local pharmacy, told the AP that four bodies were brought to the square and three bodies were taken to other areas of the city for public display. According to Seddiqi, the Taliban said the men were taking part in a kidnapping and were killed by police.A Taliban-appointed police chief in the city later claimed that kidnappers had abducted a father and son, adding the pair were rescued after a gunfight that killed all four alleged kidnappers, the AP reported.The Taliban rapidly seized control of Afghanistan in mid-August and have since set out to earn international legitimacy, despite concerns that the militant group would return to its former brutality.Under previous Taliban rule, the Taliban shot murderers dead and cut off hands and feet from alleged thieves and highway robbers.Mullah Nooruddin Turabi, one of the Taliban’s founders, told the APearlier this week that the group has said executions and amputations will return as punishments for crimes. “No one will tell us what our laws should be," Turabi told the AP. "We will follow Islam and we will make our laws on the Quran.”

In Kabul, a Former American Citizen Keeps Running the City Under Taliban Watch – WSJ —After attending the funeral of a fellow United Airlines pilot who was killed in the Sept. 11, 2001 attacks, Daoud Sultanzoy decided to return to his native Afghanistan and help build its post-Taliban government. These days, the 66-year-old mayor of Kabul is the most prominent official from the fallen Afghan republic to remain in his job after the Taliban returned to power on Aug. 15.Every morning, Mr. Sultanzoy, saluted by the municipality’s uniformed guards, runs up the staircase to the same spacious office he now shares with a senior Taliban official.“I’m not involved in any of their politics but I am here because I am responsible to the people of Kabul, and I’ve decided to stick to it,” Mr. Sultanzoy says, seated at his desk as municipality staff pass him paperwork to sign. “This is a responsibility that you cannot throw away frivolously because you just say, ‘Oh, I don’t like these people’. A day after the fall of the Afghan republic, as thousands of desperate members of the former government tried to escape via the U.S.-controlled airport, the Taliban contacted Mr. Sultanzoy to tell him that they guaranteed his security.His return to office ensured that some vital municipal services in the capital, such as trash collection and sanitation, remained uninterrupted.The mayor’s unusual and precarious position exposes the complexities of Afghanistan’s transitional period, as well as the Taliban’s attempts to move from a brutal rural insurgency to a government that can manage a country of 40 million and run its modern cities such as Kabul, home to one in eight Afghans.Asked whether his continuing service helped the Taliban shore up their legitimacy, Mr. Sultanzoy scoffs.“I am not helping. I was assigned to serve this city, and I am still serving this city,” he says. When people think of the Taliban, they think of the past and are shaken, he adds. “But I find them more tolerant. I am not saying I’ve met everybody, I am sure there are other elements. But the ones I have met are very polite, very understanding.” The Taliban’s new caretaker administrator of Kabul who shares Mr. Sultanzoy’s office, Hamidullah Nomani, served as the Afghan capital’s mayor and a cabinet minister in the Taliban regime before the 2001 U.S. invasion. Mr. Sultanzoy first came to America in the 1970s, to study aviation at the University of Miami, at the time when Afghanistan’s national airline, Ariana, was an affiliate of Pan Am, and he later became an American citizen. After participating in the 2001 Bonn conference that charted Afghanistan’s political future, he returned to the country to represent his family’s region, now part of the southeastern Ghazni province, in the new Afghan parliament.