distillates demand rose 40.9% to a 6 month high, after teasing a 26 year low last week

oil prices fell for the 3rd time in 4 weeks last week as coronavirus related demand concerns outweighed supply disruptions and falling inventories...after rising more than 10% to $41.11 a barrel last week​ ​after hurricane Sally cut output, US oil supplies fell, and the Saudis pressured their OPEC partners to cut production, the contract price of US light sweet crude for October delivery opened lower on Monday of this week as rising COVID-19 infection rates in Europe and elsewhere prompted renewed lockdown measures, casting doubt on the economic recovery, and continued to tumble to end $1.80 lower at $39.31 a barrel on expectations that crude from war torn Libya would soon return to the market...oil prices rebounded nearly 2% early Tuesday, briefly ​regaining $40 a barrel, as the latest tropical storm in the Gulf of Mexico lost strength, but then drifted lower to settle with a gain of 29 cents at $39.60 a barrel as oil traders "struggled to assess the uncertainty of U.S. production during the last two months of hurricane season and how bad the demand outlook will get following the winter wave of the coronavirus” as trading in the October oil contract expired...with Wednesday's ​market ​reports quoting US light sweet crude for November delivery, which had risen 26 cents to $39.80 a barrel on Tuesday after falling $1.78 on Monday, oil prices rose 13 cents to $39.93 a barrel as the EIA reported that US crude inventories had decreased, but by less than was expected while they also reported larger than expected drawdowns of gasoline and distillate supplies...oil prices then opened lower and slid nearly 2% early Thursday, as a renewed wave of COVID-19 cases in Europe led to reimposed travel restrictions in several countries, but recovered late to end 38 cens higher at $40.31 a barrel buoyed by signs of tighter supplies despite persistent concerns that rising cases of COVID-19 would lead to weaker energy demand...but mounting Covid cases in the US and globally and related demand concerns cast pall over oil markets on Friday as oil prices stuggled to stay positive, ultimately settling down 6 cents at $40.25 a barrel...oil prices thus finshed 2.1% lower this week, with the November contract price falling 2.6%, amid growing concerns that another wave of the coronavirus pandemic w​ould spark tighter lockdown measures and further stifle crude demand....

natural gas prices, on the other hand, finished higher for the first time in 4 weeks​,​ after crashing to a seven week low early this week...after falling 9% to $2.048 per mmBTU last week as a bigger than expected injection into storage put gas supplies on track to go into winter at a record level, the contract price of natural gas for October delivery opened nearly 3% lower on Monday and tumbled ​more than 10% ​to a seven week low of $1.835 per mmBTU on forecasts for less demand ​​over coming weeks than was expected due to a decline in LNG exports on storm and maintenance issues....prices fell another tenth of a cent to another 7 week low on Tuesday as an expected drop in output to its lowest in two years offset a forecast decrease in LNG exports, but then rallied to rise 29.1 cents or nearly 16%, to $2.125 per mmBTU on Wednesday on storm related flooding in Texas and signs of stronger demand...natural gas prices then rose another 12.3 cents or 6% to $2.248 on Thursday on a smaller-than-expected weekly storage build, a continued decline in gas output and an increase in LNG exports, before falling 10.9 cents or 5% to $2.139 on Friday despite a drop in daily output to a 25 month low, because cash trades continued to be priced much lower than the quoted NYMEX contract price, and on forecasts for less demand over the next two weeks than was previously expected, but still finished this obviously volatile week 4.4% higher than the prior week's close...

the natural gas storage report from the EIA for the week ending September 18th indicated that the quantity of natural gas held in underground storage in the US increased by 66 billion cubic feet to 3,680 billion cubic feet by the end of the week, which left our gas supplies 504 billion cubic feet, or 15.9% greater than the 3,176 billion cubic feet that were in storage on September 18th of last year, and 407 billion cubic feet, or 12.4% above the five-year average of 3,273 billion cubic feet of natural gas that have been in storage as of the 18th of September in recent years....the 66 billion cubic feet that were added to US natural gas storage this week was somewhat lower than the forecast of a 77 billion cubic foot increase from an S&P Global Platts'' survey of analysts, and it was also much lower than the 97 billion cubic feet addition of natural gas to storage during the corresponding week of 2019, and well below the average of 80 billion cubic feet of natural gas that has been added to natural gas storage during the same week over the past 5 years...

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending September 18th showed that because of an increase in our oil exports and an decrease in our production, we needed to withdraw oil from our stored supplies for the 8th time out of the past nine weeks and for the 13th time in thirty-six weeks...our imports of crude oil rose by an average of 160,000 barrels per day to an average of 5,168,000 barrels per day, after falling by an average of 416,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 427,000 barrels per day to an average of 3,022,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,146,000 barrels of per day during the week ending September 18th, 267,000 fewer 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 200,000 barrels per day lower at 10,700,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 12,846,000 barrels per day during this reporting week...

meanwhile, US oil refineries reported they were processing 13,370,000 barrels of crude per day during the week ending September 18th, 119,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA's surveys indicated that a total of 346,000 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 178,000 barrels per day less than what our oil refineries reported they used during the week...to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+178,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a fudge factor that they label in their footnotes as "unaccounted for crude oil", thus suggesting there must be an error or errors of that magnitude in the oil supply & demand figures we have just transcribed...since last week's fudge factor was -755,000, indicating a week over week difference of 933,000 barrels per day in the line 13 balance sheet adjustment, we have to figure that our week over week comparisons of crude oil supply and demand are off by that much...but since most everyone treats these weekly EIA figures 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 published, just as they're watched & believed to be accurate by most everyone in the industry... (for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....

further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 5,125,000 barrels per day last week, which was 24.2% less than the 6,764,000 barrel per day average that we were importing over the same four-week period last year....the 346,000 barrel per day net withdrawal from our total crude inventories was as 234,000 barrels per day were being pulled out of our commercially available stocks of crude oil and 112,000 barrels per day were being withdrawn from the oil supplies in our Strategic Petroleum Reserve, space in which is now being leased for commercial use, and hence the recent SPR additions and withdrawals should really be included in our commercial supplies....this week's crude oil production was reported to be 200,000 barrels per day lower at 10,700,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states fell by 100,000 barrels per day to 10,300,000 barrels per day, while Alaska's oil production fell by 53,000 barrrels per day to 408,000 barrels per day and subtracted another 100,000 barrels per day from the rounded national total (EIA's math)....last year's US crude oil production for the week ending September 20th was rounded to 12,500,000 barrels per day, so this reporting week's rounded oil production figure was 14.4% below that of a year ago, yet still 27.0% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016...    

meanwhile, US oil refineries were operating at 74.8% of their capacity while using 13,370,000 barrels of crude per day during the week ending September 18th, down from 75.8% of capacity during the prior week, and excluding the 2005 and 2008 hurricane-related refinery interruptions, one of the lowest refinery utilization rates of the last thirty years...hence, the 13,370,000 barrels per day of oil that were refined this week were 19.0% fewer barrels than the 16,513,000 barrels of crude that were being processed daily during the week ending September 20th of last year, when US refineries were operating at 89.8% of capacity....

even with the decrease in the amount of oil being refined, gasoline output from our refineries was much higher, increasing by 496,000 barrels per day to 9,315,000 barrels per day during the week ending September 18th, after our refineries' gasoline output had decreased by 111,000 barrels per day over the prior week (when refinery throughput had increased by 709,000 barrels per day)... since our gasoline production is still recovering from a multi-year low in the wake of this Spring's covid lockdown, this week's gasoline output was 9.0% less than the 10,240,000 barrels of gasoline that were being produced daily over the same week of last year....at the same time, our refineries' production of distillate fuels (diesel fuel and heat oil) increased by 67,000 barrels per day to 4,470,000 barrels per day, after our distillates output had increased by 5,000 barrels per day to 4,398,000 barrels per day over the prior week...but ​even ​after this week's increase in distillates output, our distillates' production was still 10.6% less than the 4,470,000 barrels of distillates per day that were being produced during the week ending September 20th, 2019....

even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 10th time in 12 weeks and for the 25th time in 34 weeks, falling by 4,025,000 barrels to 231,524,000 barrels during the week ending September 18th, after our gasoline supplies had decreased by 381,000 barrels over the prior week...our gasoline supplies decreased by more this week because the amount of gasoline supplied to US markets increased by 37,000 barrels per day to 8,515,000 barrels per day and because our imports of gasoline fell by 126,000 barrels per day to 474,000 barrels per day and because our exports of gasoline rose by 240,000 barrels per day to 746,000 barrels per day....after the big gasoline inventory drawdowns of recent weeks, our gasoline supplies were 1.2% lower than last September 20th's gasoline inventories of 230,204,000 barrels, but still roughly 1% above the five year average of our gasoline supplies for this time of the year... 

meanwhile, with our distillates production still near a three year low, our supplies of distillate fuels decreased for the 7th time in 25 weeks and for the 28th time in 50 weeks, falling by 3,364,000 barrels to 175,942,000 barrels during the week ending September 18th, after our distillates supplies had increased by 1,675,000 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 1,150,000 barrels per day to 6 month high of 3,959,000 barrels per day, even as our exports of distillates fell by 84,000 barrels per day to 1,128,000 barrels per day, while our imports of distillates rose by 24,000 barrels per day to 136,000 barrels per day...even after this week's inventory decrease, our distillate supplies at the end of the week were​ still​ 31.6% above the 133,685,000 barrels of distillates that we had in storage on September 20th, 2019, and about 21% above the five year average of distillates stocks for this time of the year...

finally, with the increase in our oil exports and ​the decrease in our ​oil​ production, our commercial supplies of crude oil in storage (not including commercial oil in the SPR) fell for the 10th time in the past sixteeen weeks and for the 1​7th time in the past year, decreasing by 1,639,000 barrels, from 496,045,000 barrels on September 11th to 494,406,000 barrels on September 18th...​but ​even after that decrease, our commercial crude oil inventories were still around 13% above the five-year average of crude oil supplies for this time of year, and 49.9% above the prior 5 year (2010 - 2014) average of our crude oil stocks for the third weekend of September, 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 have generally been rising over the past two years, except for during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial​ ​crude oil supplies as of September 18th were 17.8% above the 419,538,000 barrels of oil we had in commercial storage on September 20th of 2019, 24.9% more than the 395,989,000 barrels of oil that we had in storage on September 21st of 2018, and 4.6% above the 472,832,000 barrels of oil we had in commercial storage on September 15th of 2017...     

This Week's Rig Count

the US rig count rose for the 3rd time in the past 4 weeks during the week ending September 25th, but for just the 4th time in 29 weeks, and hence it is still down by 67.1% over that twenty-nine week period....Baker Hughes reported that the total count of rotary rigs running in the US rose by 6 to 261 rigs this past week, which was still down by 599 rigs from the 860 rigs that were in use as of the September 27th report of 2019, and was also 143 fewer rigs than the all time low prior to this year, and 1,668 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business....

The number of rigs drilling for oil increased by 4 rigs to 183 oil rigs this week, after decreasing by 1 oil rig the prior week, leaving us with 540 fewer oil rigs than were running a year ago, and less than a eighth of 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 increased by two to 75 natural gas rigs, which was still down by 71 natural gas rigs from the 146 natural gas rigs that were drilling a year ago, and was also less than a twentieth of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008...in addition to those rigs drilling for oil & gas, three rigs classified as 'miscellaneous' continued to drill this week; one on the big island of Hawaii, one in Sonoma County, California, and one in the Permian basin in Eddy County, New Mexico...a year ago, there only one such "miscellaneous" rig deployed...

The Gulf of Mexico rig count remained unchanged at 14 rigs this week, with 12 of those rigs drilling for oil in Louisiana's offshore waters and two drilling for oil offshore from Texas...that was 8 fewer Gulf rigs than the 22 rigs drilling in the Gulf a year ago, when all 22 Gulf rigs were drilling offshore from Louisiana...while there are no rigs operating off of other US shores at this time, a year ago there were also two rigs deployed offshore from Alaska, so this week's national offshore count is down by 10 from the national offshore rig count of 24 a year ago...also note that in addition to those rigs offshore, a rig continues to drill through an inland body of water in St Mary County, Louisiana this week, while a year ago there were no rigs drilling on inland waters..

The count of active horizontal drilling rigs was up by 9 to 224 horizontal rigs this week, which was still 528 fewer horizontal rigs than the 752 horizontal rigs that were in use in the US on September 27th of last year, and less than a sixth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014....on the other hand, the directional rig count was down by 2 to 21 directional rigs this week, and those were also down by 36 from the 57 directional rigs that were operating during the same week of last year....at the same time, the vertical rig count fell by 1 to 16 vertical rigs this week, and those were also down by 35 from the 51 vertical rigs that were in use on September 27th of 2019....

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 25th, the second column shows the change in the number of working rigs between last week's count (September 18th) and this week's (September 25th) count, the third column shows last week's September 18th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running during the count 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 27th of September, 2019...    

as you can see from those tables, most of this week's changes were concentrated in the basins around Texas...checking the rig counts in the Texas part of Permian basin, we find that 3 rigs were added in Texas Oil District 8, which is largely the core Permian Delaware, and two more rigs were added in Texas Oil District 8A, which corresponds to the northern Permian Midland, while 1 rig was pulled out of Texas Oil District 7C, which roughly aligns with the southern part of the Permian Midland, thus leaving the rig count in the Texas Permian up by four...since the national Permian basin rig count was up by two, that means that the two rigs that were pulled out of New Mexico must have been drilling in the far western Permian Delaware, in order to balance the national rig count on that basin...elsewhere in Texas, one rig was added in Texas Oil District 1, one rig was pulled out of Texas Oil District 2, and three rigs were added in Texas Oil District 4, which together account for the 3 rig increase in the Eagle Ford, a formation which stretches in a relatively narrow band across 4 Texas Oil Districts in the southeastern part of the state....one of those Eagle Ford rig additions was targetting natural gas, as were the rig addtions in Ohio's Utica and Pennsylvania's Marcellus, while at the same time a vertical natural gas rig was pulled out of a moderately shallow well in Kanawha county, West Virginia, which had not been targetting the Marcellus...

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Ohio Department of Natural Resources Cancels Mountaineer Permits — The Ohio Department of Natural Resources (ODNR) announced that it has cancelled permits Powhatan Salt Company applied for to build three solution mining wells. The solution mining wells would be used to create underground fracked gas liquids storage caverns for Mountaineer NGL Storage to then use to supply fracked gas liquids to petrochemical manufacturers, jeopardizing water supplies. Instead, Powhatan Salt Company will have to go through public notice, comment, draft permitting, and fact sheet preparation in order to receive the permits. The cancellation comes at Powhatan Salt Company’s request and reflects the demands that a coalition of clean water advocates outlined in a lawsuit against ODNR over the permits. Represented by Earthjustice, Buckeye Environmental Network, Concerned Ohio River Residents, Freshwater Accountability Project, Ohio Valley Environmental Coalition and the Sierra Club sued ODNR last month for issuing these permits without public notice or comment or preparing a draft permit, in violation with their own regulations for solution mining projects.

• “This is a huge win for the autonomy of the Ohio River Valley's people. We cannot allow companies to walk into our community and store highly explosive and toxic chemicals under our river, our drinking water, without the bare minimum of public comment,” said Alex Cole of the Ohio Valley Environmental Coalition.
• “This is a resounding victory for clean water advocates. The public deserves to have a voice, especially on projects that could have a disastrous impact on their health and water quality,” said Megan Hunter, Earthjustice staff attorney.
• “We are happy to see the permits for these wells cancelled. The site location for Mountaineer is very problematic. It is located on the banks of the Ohio River, threatening the drinking water of five million people. The proposed site is in close proximity to coal mines, fracking wells, pipelines, and is less than a mile away from Clarington and the communities drinking water wells,” said Jill Antares Hunkler, member of Concerned Ohio River Residents.
• Shelly Corbin, Ohio Campaign Representative for the Sierra Club’s Beyond Dirty Fuels Campaign said, “This unnecessary fracked gas facility shouldn’t have been proposed in the first place, but we’re glad to see that the people most impacted by it will have their chance to weigh in. The scheme to store dangerous ethane underground is one of the fracking industry's last ditch efforts to save itself. We shouldn’t be building projects that pollute the air we breathe and the water we drink.”
• Teresa Mills, Buckeye Environmental Network, claims this as a victory. “We will continue to watchdog not only the industry but also any and all agencies that are supposed to regulate the industry and fail to do so,” she said.

U.S. energy secretary talks natural gas, climate in Beaver County — U.S. Secretary of Energy Dan Brouillette on Monday met with Shell staff to talk Appalachian natural gas, petrochemical development and COVID-19’s impact on site construction. Brouillette called Beaver County’s ethane cracker plant the “future of the American economy” following a Monday tour of the petrochemical facility. Brouillette, joined by gas industry supporters and regional economic leaders, met with Shell Chemicals staff to talk Appalachian natural gas, petrochemical development and COVID-19’s impact on site construction. “This is where it all starts,” Brouillette said. “With facilities and infrastructure just like this one. It is so critical, not only to western Pennsylvania or the state of Pennsylvania, but the country and the world.” After a COVID-19 slowdown, thousands of workers are back on site constructing the $6 billion ethane cracker plant in Potter Township. Once open, the site will convert oil and gas into ethylene, used in plastics manufacturing to make a range of products from automotive parts to food packaging. It will eventually support 600 permanent jobs in the region. Brouillette echoed President Donald Trump’s comments that the economy, including natural gas, is experiencing a “V-shaped recovery,” with demand for crude oil and gas improving as nationwide business grows. Demand for products developed by cracker-like facilities is also increasing worldwide, he said, adding that policymakers sometimes forget how products such as hand sanitizer packaging and vital PPE are made. Taking a strong pro-fracking stance, Brouillette said “100% renewable energy” in America is unrealistic. “It does not work with the technologies we have today,” he said. “It's completely dependent on natural gas, nuclear and sometimes coal and hydro to produce baseload power.” When asked what President Donald Trump would do to address climate change if re-elected this November, Brouillette said the president would take an “all of the above” approach to energy production, adding “no one knows” how much of climate change can be attributed to human involvement.

Pa. shale gas production flatlines in June as producer cuts take effect - Shale gas production in Pennsylvania dropped 2% in June from May, to 18.48 Bcf/d, almost flat to the year prior, according to data from the state Department of Environmental Protection. Volume cuts by EQT Corp., the nation's largest natural gas producer, accounted for a large part of the falloff. EQT announced in May it was shutting in 1.4 Bcf/d of production, about one-third of companywide volumes. That led to an immediate 11% drop in its Pennsylvania production, followed by another 10% cut in June. EQT's Pennsylvania production fell to 2.86 Bcf/d in June, a 16% decrease year over year.EQT and other drillers, such as neighbor CNX Resources Corp., are chopping volumes in hopes of timing the gas commodities market to catch a wave of $3/MMBtu prices expected this winter, almost double current prices at the benchmark Henry Hub.While EQT said it had restored all of its production at the end of July, executives were pleased that well performance did not suffer after turning off the valves, and they may repeat the performance this fall until prices improve. CNX plans to restore the 500 MMcfe/d it has shut in by Oct. 1.None of the production cuts changed the basic outline of Pennsylvania's shale gas play. Production is still dominated by five counties in opposite corners of the state, led by Susquehanna County in the dry gas window in the northeast. Susquehanna production volumes were basically flat in June, both month to month and year over year.

The wooing of a would-be petrochemical plant - Pittsburgh Post-Gazette - It was a long shot, if a shot at all. After years of casual chitchat with ExxonMobil petrochemical executives, Pennsylvania finally detected some interest in a tour. The state Department of Community and Economic Development pounced on the opportunity, securing a date months in the future to allow for a massive herding of local officials, business groups and university leaders.  The effort culminated in a four-day trip last fall when Pennsylvania officials hosted two executives from ExxonMobil’s chemicals division — highlighting shuttered industrial sites along the Monongahela River in Washington and Greene counties that they hoped could be the home of a second major petrochemical manufacturing complex in southwestern Pennsylvania. The wooing from Sept. 30 to Oct. 3, 2019, included suite seats to a Steelers game, a visit to a plant where wet natural gas is split into marketable components, a meeting with the environmental regulators that had handled permits for the Shell petrochemical plant under construction in Beaver County, a drive-by viewing of Shell’s $6 billion project and a meeting with Carnegie Mellon University officials working on advanced manufacturing.  A spokesman for Texas-based ExxonMobil was unambiguous in a statement last week: “We have no active plans for a facility in Pennsylvania.” Still, documents obtained through open records requests by the Clean Air Council, a Philadelphia-based environmental group, reveal the alternately enticing, frantic, political and sometimes dull behind-the-scenes work that goes into attracting a major project developer like Exxon, one of the world’s largest energy companies, which state officials referred to in the emails as “our client.”   Officials assembled an itinerary designed to showcase possible locations for a petrochemical complex in Washington or Greene counties. Planned tours included the Mon River Industrial Park on the site of a former Wheeling-Pittsburgh Steel mill in Allenport and the closed Robena coal mine in Monongahela Township. They dubbed the hoped-for development, “Project West.”

New Research Shows Fracking and Petrochemicals Create Fewer Pennsylvania Jobs than Clean Energy – While Energy Secretary Dan Brouillette toured a Shell petrochemical plant under construction in Pennsylvania today, a new analysis shows that the high-profile project will employ far less workers than promised, and that a similar investment in wind and solar manufacturing would be far more beneficial.The new Food & Water Watch research, “Cracked: The Case For Green Jobs Over Petrochemicals In Pennsylvania,” focuses on the massive Shell petrochemical ‘cracker’ plant outside Pittsburgh. While early backers of the $6 billion project predicted it would create between 10,000 and 20,000 jobs, the facility will only employ 600 workers. Factoring in the massive $1.6 billion tax break granted to the company — the largest in Pennsylvania history– means the state is essentially paying $2.75 million to create each job at the plant.The Food & Water Watch research estimates that a similar level of investment in wind and solar manufacturing would create over 16,000 jobs.  Unfortunately, state political leaders are still pushing tax breaks for fossil fuels and petrochemicals in the hopes that it will drive additional job growth. The Shell plant is emblematic of this misguided approach: Minimal job creation, increased pollution, and broken promises on using local labor and in-state materials like steel.  The Trump re-election campaign is heavily emphasizing fossil fuel and petrochemical jobs in Pennsylvania. Trump held a campaign-style rally at the facility a few months ago, and more recently falsely claimed credit for its construction. Brouilette’s two-day visit is a strong indicator that the White House will continue to emphasize the importance of fossil fuel jobs.

More spills at Lebanon County Mariner East pipeline drill site earn Sunoco more violations | StateImpact Pennsylvania - The Department of Environmental Protection last month directed Mariner East pipeline pipeline builder Sunoco to find a new path for about a mile of its 20-inch pipeline at a site in Chester County, after a drilling spill of more than 8,000 gallons closed part of Marsh Creek Lake to the public. The DEP order was the first in the troubled 43-month history of the pipeline’s construction to require a route change. It followed criticism that dozens of fines and notices of violation in response to earlier problems had done little to force Sunoco to improve construction practices. Now, a string of spills and notices of violation at a horizontal directional drill (HDD) site in Lebanon County, at Snitz Creek in West Cornwall Township, are prompting questions about whether it’s technically feasible to run the pipeline under the creek, given the fragile karst limestone geology of the area, or whether another route for the pipeline is the only realistic option. Sunoco reported five spills, or “inadvertent returns,” of drilling mud at the site between Aug. 13 and Sept. 18, according to the DEP’s Pipeline Portal, bringing to 12 the number of such incidents there since construction began in February 2017. In response, the DEP issued four notices of violation of two environmental laws, and told Sunoco that it could not restart the operation without approval from the department. DEP spokesman Jamar Thrasher said the department has no rule for the number of spills that would lead to an order to reroute the pipeline. “We generally review each site on a case-by-case basis,” he said. Chester and Lebanon counties share the karst limestone geology that creates problems for industrial projects that use underground drilling. Sunoco did not respond to a request for comment, but the Pennsylvania Energy Infrastructure Alliance, which advocates for the industry, said that any rerouting of the pipeline would mean a further delay to the already years-late project. “Any new route would require a major modification of the existing DEP permit,” said Kurt Knaus, a spokesman for the alliance. “This project is nearly complete, and these remaining drills are connecting parts of the line that are already finished and in the ground. What we need to do is get the job done.” The project already carries natural gas liquids from southwestern Pennsylvania and Ohio through 17 counties to a terminal at Marcus Hook near Philadelphia, where most of it is exported. Although not all sections of its three pipes are complete, different combinations of pipe have been carrying ethane, propane and butane eastward since December 2018.

DEP approves changes to Mariner East construction methods at three troubled sites in Delaware, Chester counties - Construction at three troubled Mariner East pipeline sites in Chester and Delaware counties will shift from the planned horizontal directional drilling (HDD) to open trench, a method that risks greater damage to the surface area but avoids further drilling mud spills and sinkholes that have plagued the project in southeast Pennsylvania.The Department of Environmental Protection approved the amended permitsproposed by pipeline builder Energy Transfer/Sunoco after construction caused several pollution events and risks to worker safety at the three sites.The company chose a route through southeastern Pennsylvania that required drilling through unstable rock formations like limestone that has caused dozens of spills, sinkholes and damage to drinking water. Following a 2017 lawsuit by environmental groups over the company’s pipeline work, an order agreed to by all parties requires the company to submit “reevaluation reports” to DEP whenever operations cause drilling mud spills, also referred to as “inadvertent returns.” Those reports are evaluated by a geologist and are open to public comment.The move is not related to a recent order by DEP to Energy Transfer to re-route a section of the pipeline to avoid further damage to Chester County’s Marsh Creek Lake. In August, drilling at nearby pipeline construction site 290 caused about 8,000 gallons of drilling mud to flow into the lake, the main attraction at Marsh Creek State Park and popular to birders, boaters and anglers. Energy Transfer has yet to agree to that order, and could still file an appeal. The three sites now approved to shift to open trench digging are in Delaware County’s Middletown Township, and Chester County’s West Whiteland and Upper Uwchlan townships.

Snubbed retiree gets back at Sunoco for canceling a Mariner East pipeline meeting -Sunoco Pipeline LP’s abrupt cancellation of a public pipeline safety meeting near Carlisle, Pa., two years ago was the final insult for Wilmer Baker, a retired steelworker who lives about a quarter-mile from the contentious cross-state Mariner East project.Baker filed a formal complaint with the Pennsylvania Public Utility Commission in 2018, alleging a litany of bad behavior by Sunoco. He demanded that the PUC order the company to improve safety measures.  This week, he got vindication of sorts when the PUC ordered the pipeline operator to schedule a public awareness meeting within 30 days in Cumberland County. A PUC administrative law judge, who had heard formal testimony last year in Baker’s complaint, chided the company for canceling a July 10, 2018, public safety meeting in Lower Frankford Township on short notice because it suspected that the media and potentially litigious residents would be in attendance.The PUC also levied a $1,000 fine against Sunoco.For Baker, a 65-year-old retired foundry worker who represented himself during the PUC’s formal legal process, the commission’s decision was a sweet victory. “Being a private citizen with no legal experience and going up against Sunoco — they had five lawyers there at the hearing and two paralegals — to be able to challenge Sunoco in court and win, I’m ecstatic,” Baker said Thursday.

The Revolution pipeline, two years since it exploded, is back under construction in Beaver County | Pittsburgh Post-Gazette - Two years and two weeks after the Revolution pipeline slid down a steep hill in Center Township and burst into flames, its owner has begun the process of repair.Texas-based Energy Transfer Corp. got approval from state environmental regulators to reroute part of the 24-inch natural gas pipeline onto flatter ground near the area of the explosion. The company told nearby residents that it is felling trees this week and plans to be done with construction in about 45 to 60 days.The pipeline explosion Sept. 10, 2018, was preceded by a heavy rainfall and a history of landslides in that part of Beaver County. The Revolution pipeline had been operational for only a few days before the rupture, and that part hasn’t operated since.The project is considered a gathering pipeline — it is meant to collect gas from wells starting in Beaver and Butler counties and ferry it to an Energy Transfer gas processing plant in Washington County. Although the company at first advised investors and clients that the Revolution pipeline would be back up and running within a few weeks, then months, regulators put a halt to those plans.In the summer, Energy Transfer revealed what residents of nearby Ivy Lane had long suspected after the company bought out two landowners. It would seek to change the route of the pipeline to avoid the steel hill that failed to hold it. That is what the state Department of Environmental Protection recently approved. Energy Transfer’s plan to stabilize the hillside that slipped two years ago was also approved this week, the DEP said.Construction on the pipeline was permitted to begin Thursday. Ivy Lane resident Karen Gdula had a feeling things were about to ramp up.“They’ve been doing a ton of stabilization all over Center Township,” she said, watchful, as ever, of the comings and goings of Energy Transfer’s contractors and large equipment.There’s so much activity on the ground, “it’s like they’re coming in and doing an entire new pipeline,” she said.It’s not clear when the pipeline will be put back into service or which company’s gas will be flowing through it then.The two major shippers for Revolution in that area were EdgeMarc Energy, which declared bankruptcy allegedly because of the explosion, and PennEnergy Resources, which is involved in a contentious lawsuit against Energy Transfer over the pipeline rupture. Among other things, PennEnergy has charged that the pipeline company orchestrated a cover-up to keep from voiding its contract with the driller. A trial in that case is scheduled to begin in March.

Transco Pays Pennsylvania Nearly $1M for Atlantic Sunrise Violations - Natural Gas Intelligence  Transcontinental Gas Pipe Line Co. LLC (Transco) has agreed to pay nearly $1 million in penalties and environmental donations for violations that occurred during the construction of its Atlantic Sunrise expansion project, Pennsylvania regulators said Tuesday.  The state Department of Environmental Protection (DEP) said it has collected a civil penalty of $736,294 from Transco for construction violations in Columbia, Lancaster, Lebanon, Luzerne, Lycoming, Northumberland, Schuylkill, Susquehanna and Wyoming counties in the eastern part of the state. The company has also agreed to provide $100,000 to fund two water quality improvement projects in Northumberland County. DEP said the violations included failure to properly maintain erosion and sedimentation best practices, inadvertent returns of drilling fluids and sediment discharges into waters of the state. The agency said it would take $680,000 of the civil penalty, while the remainder would go toward the county conservation districts that helped inspect the project during its construction. Transco parent Williams said severe weather events during construction caused “erosion-related issues that were quickly addressed once identified.” The company added that it notified regulators promptly, “who were kept informed until the issues were resolved.” The Atlantic Sunrise expansion entered full service in 2018 to move 1.7 Bcf/d of natural gas from the Marcellus Shale in Northeast Pennsylvania. The expansion came online in phases beginning in 2017 with Brownfield portions first entering service until the 186-mile stretch of greenfield pipeline was finished. Atlantic Sunrise moves gas into Transco, a 10,000-mile pipeline system that spans a large chunk of the East Coast.

A new tool can show if your water is polluted by fracking - - Penn Medicine researchers have created an interactive tool, called WellExplorer, that allows community members and scientists to find out which toxins may be lurking in their drinking water as a result of fracking. You just have to type your ZIP code in the website or the app and look at the fracking sites near you, with information on the chemicals used at each of them.In a recent study, the researchers behind the interactive tool found worrying data on some of the wells. For example, Illinois, Ohio, and Pennsylvania use a high number of ingredients targeting testosterone pathways. Meanwhile, Alabama uses a disproportionately high number of ingredients targeting estrogen pathways.“The chemical mixtures used in fracking are known to regulate hormonal pathways, including testosterone and estrogen, and can therefore affect human development and reproduction,” Mary Regina Boland, one of the researchers behind the project, said in a statement. “Knowing about these chemicals is important, not only for researchers but also for individuals.”The US already has a central registry for fracking chemical disclosures called FracFocus but the researchers believed it’s not user-friendly for the general public. It also doesn’t have information about the biological action of the fracking chemicals that it lists. That’s why they developed WellExplorer, starting by cleaning and shortening the data from FracFocus to use it in their own interactive tool.The researchers integrated data from the Toxin and Toxin Target Database (T3DB) in order to obtain the toxic and biological properties of the ingredients found at the well sites. They also extracted toxicity rankings of the top 275 most toxic ingredients from the Agency for Toxic Substances and Disease Registry, as well as a list of ingredients that were food additives. Boland explained that the use of chemicals at a fracking site may not necessarily mean that those chemicals would be present in the water supply, which would be dependent on other factors, such as the depth of the hydraulic fracturing. Nevertheless, she said WellExplorer was a very good starting point for residents that may be dealing with symptoms and want to have their water tested.

NRC says gas pipeline rupture wouldn't pose a danger to Indian Point - Indian Point’s owners concluded this year that it could take as many as eight minutes to cut off the flow of natural gas if a pipeline near the nuclear power plant ruptured, five minutes longer than they said it would take in 2014, federal safety regulators said on Tuesday. But officials with the Nuclear Regulatory Commission said Entergy’s revised timeline did not alter their 2015 assessment of the hazards posed by an expansion of the Algonquin Incremental Market Pipeline that brought it closer to Indian Point’s border. “Whatever assumptions they used, whatever calculational methodology they used, we did an independent review and did not identify any concerns relative to our overall conclusion, that the pipeline was not an undue hazard to the Indian Point plant,” said Ray Lorson, the NRC’s deputy regional administrator, during a video-conference on Tuesday. “That was true in 2015 and it’s true today as well.” Lorson’s comments came ahead of the NRC’s annual safety performance hearing for Indian Point, scheduled to take place by video conference on Tuesday at 6 p.m. It will be the last such hearing before the Buchanan plant closes in late April when its last working reactor — Unit 3 — powers down after generating electricity for Westchester County and New York City for more than four decades. The plant received passing grades from the NRC for its 2019 safety performance.

Mountaineer Gas Pipeline Explosion in Martinsburg West Virginia -A Mountaineer Gas pipeline in Martinsburg, West Virginia exploded this afternoon at about 3:15 p.m. on the Sentz family property on Salvation Road.   Anne and Benjamin Sentz were working from home and watching workers dig a trench for a new pipeline that was running by an old pipeline that had gas in it. “We were standing in our kitchen looking out our window watching them dig. We kept an eye on the people doing the work ever since they started. We happened to be watching them dig. They were digging really deep. We heard a bang like they hit metal. All of a sudden there was a loud explosion. Pressurized gas shot up 80 to 100 feet into the air. Six or seven workers just scattered.”  “My husband grabbed me and said – we need to get out of here. I grabbed one dog and he grabbed the other. We just ran to our car. While we were on our way to our car, a worker came to the front of our house and said we needed to go. We just left. I left the door open. We were out of there in 30 seconds. We just drove away. We didn’t know if our house was going to explode or what. We kept on driving. I drove all the way to Shepherdstown.”  “I called 911. They had already received a call about the incident. They put me through to the fire department. I talked to someone from the fire department. They told me they would give me a call when it was safe to come back to the house.  It’s 5:30 and we are still not back. We haven’t received the call yet that it is all clear.”  “I’ve been watching this operation for a while,” Sentz said. “I am trying to figure out what is going on. The gas company hasn’t been as transparent as they should be to the property owners and neighbors and people affected by this.”  “I was just at the site at 5 p.m. and could still smell the gas,” said Tracy Cannon. “I’ve been watching the pipeline construction in the Eastern Panhandle closely for two years now. I’ve often been concerned about what I saw. Mountaineer Gas Company has been installing new pipeline on Salvation Road without removing the old pipeline first.  I was worried that something could go wrong, but I’m still shocked that this happened. Thankfully no one was injured.”“This incident is an example of the careless manner in which Mountaineer Gas is installing the gas pipeline to Rockwool,” said Christine Wimer, President of Jefferson County Foundation. “We have again and again tried to get Mountaineer Gas to have the pipeline appropriately permitted, but they have refused to do so. The regulators are all too happy to oblige Mountaineer Gas’s obfuscation of the regulatory requirements. The regulators have abandoned their post of protecting the public. This cannot be tolerated.”

Mountain Valley seeks to resume construction of pipeline - After a winter hiatus in construction that stretched into the spring, summer and fall, builders of the Mountain Valley Pipeline say they are ready to return. In a letter filed with the Federal Energy Regulatory Commission late Tuesday, an attorney for the joint venture of energy companies requested that a stop-work order issued last Oct. 15 be lifted. Matthew Eggerding asked FERC to act by Friday “so that Mountain Valley can maximize final restoration and complete as many activities as possible before winter,” he wrote in the letter. Since work began in early 2018, litigation has caused cost overruns and construction delays for Mountain Valley. Not long after FERC issued its stop-work order, the company said it expected to be back on the job by April. But Mountain Valley still lacks two sets of key permits that were set aside after a federal appeals court sided with conservation groups, who argued that building a 303-mile natural gas pipeline through West Virginia and Virginia was causing widespread environmental harm. A third suspended permit was reissued earlier this month by the U.S. Fish and Wildlife Service, which found that construction would not likely jeopardize protected species. That in turn led Mountain Valley to request that it be allowed to resume “all construction activities permitted by law.” All work except for erosion control and stabilization was ceased a year ago by FERC, after the 4th U.S. Circuit Court of Appeals stayed the original biological opinion pending a legal challenge that has not gone away. The buried pipeline cannot cross nearly 1,000 streams and wetlands until the U.S. Army Corps of Engineers grants new permits. And construction of a 3.5-mile passage through the Jefferson National Forest requires a separate approval from the U.S. Forest Service. In a letter to FERC on Wednesday, the Sierra Club maintained that construction cannot commence until all federal authorizations are obtained. A start to construction at this point would raise the risk of “bureaucratic momentum,” in which agencies that have yet to make a decision might be pressured to go along, senior attorney Elly Benson wrote in a letter co-signed by other environmental groups. The letter also contains the first official hint of additional litigation that could derail any movement forward for Mountain Valley.

West Virginia joins coalition seeking to protect pipeline construction (WV News) — West Virginia has joined a 17-state coalition in asking a federal appeals court to reverse a lower court ruling that brought pipeline construction to a halt nationwide, Attorney General Patrick Morrisey says.The coalition’s brief, filed late Wednesday, argues a federal district judge inappropriately transformed a case challenging one project into a nationwide injunction that affected new oil and gas pipelines in every state — no matter the project’s length, purpose or minimal environmental effect.The coalition won a stay in July at the U.S. Supreme Court. Now its member states seek ultimate reversal of the lower court ruling.“Such overreach by a federal district judge cannot stand,” Morrisey said. “Aside from the ruling being overly broad and deeply flawed as a matter of fairness and court procedure, it presents serious consequences for our national economy and causes unnecessary instability and disruption for the dedicated pipeliners of West Virginia, as well as those who depend upon their success.”The original lawsuit focused upon a permit the U.S. Army Corps of Engineers used to authorize the Keystone XL pipeline. The coalition argues the district court order inappropriately used that issue to strike down all projects that employed the same permitting process nationwide.That decision led to the cancellation of the Atlantic Coast Pipeline — an announcement that came days before the Supreme Court’s stay.The coalition contends the district court ruling, if allowed to stand, would make needed infrastructure projects significantly more costly and time-consuming — and potentially render some completely unfeasible, thus eliminating an untold number of jobs. The West Virginia- and Texas-led brief carries support from attorneys general in Alabama, Alaska, Arkansas, Georgia, Indiana, Kansas, Kentucky, Louisiana, Mississippi, Nebraska, Ohio, Oklahoma, South Carolina, South Dakota and Wyoming.

Industrial sector consumption of natural gas falls amid slowing economy - Natural gas consumption in the U.S. industrial sector declined from 25.4 billion cubic feet per day (Bcf/d) in January 2020 to 20.1 Bcf/d in June 2020, according to the U.S. Energy Information Administration’s (EIA) Natural Gas Monthly. Industrial natural gas consumption in June 2020 was nearly 1.0 Bcf/d lower than its year-ago level. The decline in industrial sector natural gas consumption compared with the previous year began in March 2020, amid responses to the coronavirus disease (COVID-19) that resulted in a global economic slowdown. Industrial sector consumption reached its lowest point in May 2020, falling by 8% compared with 2019 levels. May 2020 consumption of natural gas by U.S. industry marked the largest year-over-year decline since July 2009, during the 2007–2009 recession. Before this year, average U.S. industrial natural gas consumption grew 5.4% in 2018 and was relatively flat (growing 0.1%) in 2019.Beginning in March 2020, efforts to mitigate COVID-19 began in the United States. Responses to the virus, including stay-at-home orders and temporary closings of nonessential businesses, contributed to a slowing U.S. economy. According to the Bureau of Economic Analysis (BEA), the value of goods and services produced in the United States, known as gross domestic product (GDP), decreased by 9.1% in the second quarter of 2020 compared with the same quarter a year ago. A slowing economy as a result of COVID-19 mitigation efforts also affected GDP in the first quarter of 2020, which grew 0.3%. Last year, the U.S. economy grew 2.2%. According to the September 2020 Short-Term Energy Outlook, EIA expects annual consumption of natural gas by U.S. industries to decline by 4.4% in 2020 and then grow 1.1% in 2021. EIA forecasts U.S. industrial natural gas consumption to increase in 2021 because of expected growth in the overall economy and the natural gas-weighted industrial production index. The index reflects the growth of the underlying manufacturing subsectors and the relative importance of those subsectors to total natural gas consumption.

You've Got Your Troubles, Part 3 - Seasonal Demand Declines, Production Curtailments Hit Appalachian Gas Market - As U.S. natural gas spot and futures prices retreated in the past week, the price of gas at Appalachia’s Dominion South hub fell as low as $0.735/MMBtu, the lowest since fall 2017, before partially rebounding yesterday to about $1.10/MMBtu, according to the NGI daily gas price index. Moreover, the forwards market indicates sub-$1/MMBtu prices are in store for October as well. The regional supply hub didn’t weaken quite as much as prices at the national benchmark Henry Hub, which collapsed in recent days on demand losses — from cooler weather, storm-related power outages, and disruptions to LNG exports — and storage levels in the Gulf Coast region that are well above average and approaching peak capacity levels. The relative support for prices in the Northeast is in part due to a second round of production shut-ins by EQT Corp., which took effect September 1. But seasonal demand declines are underway; the Dominion Energy Cove Point LNG facility in Maryland just went offline for its annual fall maintenance, placing additional pressure on already-packed storage fields and takeaway pipelines; and pipeline maintenance events are reducing outflow capacity and curtailing production. Altogether, that signals more volatility ahead. Today, we provide an update on the fundamentals driving the Northeast gas market. When we last checked in on the Northeast gas market in late July (see You’ve Got Your Troubles Part 1 and Part 2), there already were signs of trouble. Following a mild winter and despite pandemic-induced demand disruptions, Appalachian producers had managed to eke past the low-demand spring season without a price meltdown by shutting in production and increasing flows out of the region. But by late July, LNG cargo cancellations were in full swing. Production shut-ins led by EQT from mid-May through mid-July were roaring back online. Appalachian production volumes, after almost flattening out to year-ago levels in June, had surged back to 2020 highs that surpassed pre-shut-in levels and were approaching the region’s all-time highs seen in late 2019. Northeast demand was also strong and setting records. But storage and takeaway capacity fears were brewing for fall shoulder season as storage levels were already high and reflecting surpluses to prior years after the mild winter, and pipeline capacity utilization for routes moving gas out of the region also was running higher than in previous years. These factors combined signaled the likelihood of pipeline takeaway constraints and a price meltdown this fall, including the potential for a second round of production shut-ins.

You've Got Your Troubles, Part 4 - More Northeast Gas Production Curtailments --U.S. natural gas production in recent days has plunged more than 3 Bcf/d. While some Gulf of Mexico offshore and Gulf Coast production is still offline from the recent tropical storms, the bulk of these declines are happening in the Northeast, where gas production has dived 2 Bcf/d in the past week or so to about 30.2 Bcf/d, the lowest level since May 2019, pipeline flow data shows. Appalachia’s gas output was already down earlier in the month, as EQT Corp. shut in some volumes starting September 1. But with storage inventories soaring near five-year highs, a combination of maintenance events and demand constraints are forcing further curtailments of Marcellus/Utica volumes near-term. Today, we provide an update of Appalachia gas supply trends using daily gas pipeline flow data. As we discussed on Wednesday in Part 3 of this blog series, the Northeast gas market has been volatile lately. Appalachian supply prices in the spot market earlier this week fell to three-year lows, despite production shut-ins being in effect. A confluence of factors influenced the downturn, including low weather-driven demand, pipeline outages that are restricting outflows, and the start of an annual fall maintenance event at Dominion Energy’s Cove Point LNG facility that took another 700 MMcf/d or so of export demand out of the market. What’s making all of that worse is that storage levels are soaring, not just in the Northeast but also in downstream markets, reducing flexibility to navigate supply congestion and forcing production curtailments. In the past couple of days, cash prices have strengthened again as production has pulled back.  We’re going to delve into the specifics of the latest production pullback using daily pipeline flow data from our good friends at Genscape next. Before we get into the production trends, though, let’s first review a bit about the data itself. The pipeline flow dataset comprises the daily gas volumes nominated by market participants to either be received or delivered at thousands of individual meters along natural gas interstate pipelines across the U.S. The meter volumes are then aggregated by type of connecting facility (i.e., gathering systems and processing plants that represent production, and power plants, industrial plants or distribution companies that represent demand); these pipeline flows provide critical insights into supply and demand trends on a daily basis. How much of the market flow this data captures can vary widely by region, but in the Northeast, it provides a high degree (~95%) of transparency into the region’s supply and demand picture. However, note that initial volumes for the most recent gas day can get revised based on final nominations reported for that day. The data discussed in today’s blog is as of the evening cycle for gas day Thursday, September 24. (See Sooner or Later and One Step Closer for more on flow data. We’ll also be demonstrating how to use flow data to track the Northeast gas market in our upcomingSchool of Energy Virtual on October 20-21, 2020.)

U.S. natgas futures drop over 10% to 7-week low as LNG exports slide  (Reuters) - U.S. natural gas futures plunged over 10% on Monday to a seven-week low on forecasts for less demand over the next two weeks than previously expected due to a decline in liquefied natural gas (LNG) exports. Gas flows to LNG export plants dropped because of planned maintenance at Dominion Energy Inc's Cove Point in Maryland, the continued outage at Cameron in Louisiana and as some ships steer clear of Tropical Storm Beta, which is expected to lash the Texas and Louisiana coasts this week. Front-month gas futures fell 21.3 cents, or 10.4%, to settle at $1.835 per million British thermal units (mmBtu), their biggest one-day percentage drop since January 2019 to their lowest close since July 31. That drop puts the front-month down 33% since hitting an eight-month high of $2.743 per mmBtu on Aug. 28 and boosted the premium of November futures over October NGV20-X20 to a record high of 89 cents. Despite the recent drop in the front-month, gas speculators last week increased their net long positions on the New York Mercantile and Intercontinental Exchanges for the seventh time in eight weeks to their highest since May 2017 on expectations energy demand will rise as the economy rebounds once state governments lift more coronavirus-linked lockdowns. Those added long positions came despite expectations stockpiles will hit record highs by the end of October, which should remove lingering concerns about price spikes and gas shortages this winter. Data provider Refinitiv said the amount of gas flowing to U.S. LNG export plants was on track to slide to a two-week low of 5.2 bcfd on Monday from a four-month high of 7.9 bcfd last week. LNG feedgas has averaged 5.6 bcfd so far in September. That was the most in a month since May as global gas prices rise, making U.S. gas more attractive.

U.S. natgas holds near 7-week low as output drop offsets fall in LNG exports (Reuters) - U.S. natural gas futures held near a seven-week low on Tuesday as an expected drop in output to its lowest in two years offset a forecast decrease in liquefied natural gas (LNG) exports. Front-month gas futures fell 0.1 cents, or 0.1%, to settle at $1.834 per million British thermal units (mmBtu), their lowest close since July 31 for a second day in a row after the contract dropped over 10% in the prior session. Traders said futures, which were down about 33% since hitting an eight-month high in late August, were mostly following the spot market lower. Next-day gas at the Henry Hub NG-W-HH-SNL benchmark in Louisiana plunged to an 11-year low of $1.331 per mmBtu for Tuesday, putting it down almost 50% since it hit a nine-month high in late August. Data provider Refinitiv said output in the Lower 48 U.S. states was on track to fall to 83.9 billion cubic feet per day (bcfd) on Tuesday, its lowest since August 2018, as Tropical Storm Beta swirls along the Texas Coast. That drop occurred even though producers said they did not expect much damage from Beta. With prices expected to remain relatively low, Refinitiv projected demand, including exports, would rise from 81.4 bcfd this week to 83.7 bcfd next week as electric generators burn more gas instead of coal to produce power. That, however, was below Refinitiv's forecasts on Monday due mostly to reduced LNG exports. The amount of gas flowing to LNG export plants was on track to slide to a two-week low of 3.9 bcfd on Tuesday from a four-month high of 7.9 bcfd last week due to planned maintenance at Dominion Energy Inc's Cove Point in Maryland, the continued outage at Cameron in Louisiana and as some vessels steer clear of Beta.

Natural-gas futures rally on storm-related disruptions and signs of stronger demand - Natural-gas futures rallied Wednesday, to settle at their highest in a week. Prices found support amid production slowdowns tied to recent storms as well as facility maintenance, and as flooding along the coast of the Gulf of Mexico that reportedly led to disruptions at export facilities, analysts said. The flow of natural gas to major hubs Sabine Pass and the Freeport LNG export facilities in Texas remains “greatly reduced” as Tropical Storm Beta unleashed flooding in the Houston area and inched toward Louisiana. Beta made landfall as a tropical storm late Monday in Texas. By Wednesday, it was downgraded to a post-tropical cyclone, but flash flood watches are in effect across southeast Texas and southern Louisiana, the National Hurricane Center said Wednesday morning. This year marks only the second time that the Greek alphabet has been used to name storms, reflecting that the regular list of 21 names, ended with Tropical Storm Wilfred, have been exhausted. Deliveries of feed gas, which is natural gas that comes from field production, has seen a significant decline in recent days, Natural Gas Intelligence reported on Tuesday.. It also said the Cameron, Corpus Christi, Freeport and Sabine Pass export terminals were in Beta’s path as the storm neared land.   Luke Jackson, team lead, North America natural gas at S&P Global Platts, meanwhile, attributed the rally in natural gas to easing worries about stocks in the Gulf Coast hitting capacity. Production in the Northeast U.S. fell 1.5 billion cubic feet per day Wednesday, compared with the September month-to-date average, he told MarketWatch. “That drop is partly maintenance related, but also likely a function of the region’s own storage congestion and lack of demand, which is forcing prices lower and causing production to shut.” On Wednesday, the front-month October natural gas contract rose nearly 16%, or 29 cents, at $2.125 per million British thermal units on the New York Mercantile Exchange, for the biggest one-day percentage rise since early August, according to FactSet data. The settlement was the highest for a front month since Sept. 16. Export demand prospects “have a silver lining,” as well, with traders estimating that less than five U.S. cargoes have been cancelled for November loading, said Redmond. Given that, and “assuming that Gulf LNG export terminals or their surrounding power grids do not sustain substantial damages from Beta, feedgas demand should ramp up again quickly following the storm and could run near full capacity in October,” she said.

US working natural gas volumes in underground storage rise 66 Bcf on week: EIA -The amount of natural gas in US underground storage facilities increased by 66 Bcf to 3.680 Tcf in the week ended Sept. 18, according to data released by the US Energy Information Administration Sept. 24. The injection was much less than an S&P Global Platts' survey of analysts calling for a 77 Bcf build. The estimate was also a shocking departure from the prior week's build of 89 Bcf. The EIA's Weekly Natural Gas Storage Report is a survey, not a census, and the many storm-related logistical difficulties in the South Central region for the first half of September potentially caused sampling errors or discrepancies between the storage fields in the EIA's sampling frame and those outside of it, according to S&P Global Platts Analytics. It is likely the EIA overestimated net injections for the week-ended Sept. 11. The injection measured less than the 97 Bcf build reported during the same week last year as well as the five-year average gain of 80 Bcf, according to EIA data. Storage volumes now stand 504 Bcf, or 16%, more than the year-ago level of 3.176 Tcf and 407 Bcf, or 12.4%, more than the five-year average of 3.273 Tcf. After briefly trading up 21 cents the morning of Sept. 24, the prompt-month NYMEX Henry Hub contract settled back down to a roughly 9 cent/MMBtu gain day on day, driven by a much smaller-than-anticipated storage build reported by the EIA. The price strength did not extend far into the strip, with November trading just 2 cents higher, and the rest of the winter contracts through March 2021 trading about 1.5 cents higher on the day. Platts Analytics' supply and demand model currently forecasts a 67 Bcf injection for the week ending Sept. 25. This would lower the surplus to the five-year average by 11 Bcf as about seven net injections remain before the flip to the winter withdrawal season. Total supplies are trending 1.2 Bcf/d lower this week compared with the week ended Sept. 18, driven by a 900 MMcf/d drop in onshore production, the vast majority of which stems from the Northeast region, where output has slid nearly 2 Bcf/d in the past few days due to weak prices and infrastructure constraints. The ICE end-of-season EIA inventory estimate was 5 Bcf lower on Sept. 24, with markets narrowing in on an expected 3.97 Tcf end-of-summer carryout to begin the winter demand season in November. This would be about 250 Bcf more than the five-year average of 3.75 Tcf.

U.S. natgas futures jump 6% on small storage build, rising LNG exports  (Reuters) - U.S. natural gas futures jumped almost 6% on Thursday on a smaller-than-expected weekly storage build, a continued decline in output and an increase in liquefied natural gas (LNG) exports. The U.S. Energy Information Administration (EIA) said U.S. utilities injected just 66 billion cubic feet (bcf) of gas into storage in the week ended Sept. 18. That was well below the 78-bcf build analysts forecast in a Reuters poll and compares with an increase of 97 bcf during the same week last year and a five-year (2015-19) average build of 80 bcf. Front-month gas futures rose 12.3 cents, or 5.8%, to settle at a one-week high of $2.248 per million British thermal units. The market has already been extremely volatile this week - prices fell over 10% on Monday and jumped almost 16% on Wednesday - as traders roll out of front-month October contracts, which expire on Sept. 28, and into much higher priced November futures. Data provider Refinitiv said output in the Lower 48 U.S. states was on track to fall for a second month in a row to 86.9 billion cubic feet per day (bcfd) in September from 87.5 bcfd in August. That is well below the all-time monthly high of 95.4 bcfd in November. Refinitiv projected demand, including exports, would rise from 82.6 bcfd this week to 85.3 bcfd next week as LNG exports increase. The amount of gas flowing to LNG export plants was on track to reach 5.7 bcfd on Thursday from a two-week low of 3.9 bcfd on Tuesday as vessels returned to Gulf Coast terminals after Tropical Storm Beta dissipated. Traders said the Cameron LNG export plant in Louisiana will likely return to service around Oct. 8 when the Army Corps of Engineers expects to finish dredging the Calcasieu Ship Channel after Hurricane Laura.

US natgas futures fall with cash prices on lower demand forecasts - US natural gas futures ended a volatile week down almost 5% on Friday as spot prices continued to trade much lower than futures on forecasts for less demand over the next two weeks than previously expected. The decline in futures prices came despite a projected increase in LNG exports, record sales to Mexico and a drop in daily output to a 25-month low. On its second to last day as the front-month, gas futures for October delivery fell 10.9 cents, or 4.8%, to settle at $2.139 per million British thermal units (mmBtu). November futures, which will soon be the front-month, were down about 9 cents at $2.81 per mmBtu. If November continues to trade at that level next week, it would put the front-month on track for its highest close since November 2019. For the week, the front-month was up about 4% after falling over 10% on Monday and rising almost 16% on Wednesday. Next-day gas at the Henry Hub benchmark in Louisiana, which fell to a 21-year low earlier this week, has traded below front-month futures since late August due mostly to weak demand along the Gulf Coast after a series of storms hit LNG exports. Data provider Refinitiv projected demand, including exports, would rise from 82.4 billion cubic feet per day (bcfd) this week to 84.6 bcfd next week and 85.3 bcfd in two weeks, with LNG exports expected to climb. That, however, is lower than Refinitiv's forecast on Thursday, as an expected increase in gas prices will cause some electric generators to burn more coal instead of gas to produce power. The amount of gas flowing to LNG export plants was on track to reach 6.1 bcfd on Friday, up from a two-week low of 3.9 bcfd on Tuesday, as vessels returned to Gulf Coast terminals after Tropical Storm Beta dissipated.

Sen. Tillis: Trump to extend offshore drilling pause to NC (AP) — President Donald Trump will add North Carolina to a list of southeastern states whose coastal waters won’t be subjected to offshore drilling for a decade, U.S. Sen. Thom Tillis said on Monday. Earlier this month, Trump signed a memorandum instructing his interior secretary to prohibit drilling in the waters off both Florida coasts, and off the coasts of Georgia and South Carolina for 10 years — from July 2022 through June 2032. North Carolina wasn’t on the list. In a short video released by his Senate office, Tillis, a Republican, said he spoke to Trump on Monday morning and asked him to “extend the offshore drilling moratorium to North Carolina. I’m pleased to announce that the president will be doing just that.” The Trump administration didn’t immediately announce such a move Monday. The three-state prohibition marked a policy reversal by Trump and was seen as a potential political asset for Republican senators in Georgia and South Carolina facing tough election fights. The drilling issue hasn’t reached the forefront of the Senate campaign between Tillis and Democrat Cal Cunningham, however. Still, Democratic Gov. Roy Cooper, an offshore drilling opponent, wrote Trump last week asking him to add North Carolina to the list, citing the risk of spills and potential damage to the tourism and fishing industries. Tillis was state House speaker in the early 2010s, when the legislature approved the framework to allow oil and natural gas drilling off the Atlantic coast and to collect taxes from the energy products. But that production hasn’t occurred due to delays from Washington as well as an oversupply of natural gas. A bipartisan group of more than two dozen coastal mayors signed a resolution last year urging such exploration be permanently off-limits. Tillis pressed for Atlantic coast exploration during a floor speech early in his Senate term for jobs and U.S. energy independence. But last year he expressed some concerns, asking the Trump administration to speak with North Carolina tourism and fishing interests to ensure they would be protected under an exploration plan.

Questions Linger on Offshore Drilling, Seismic Testing -- Sen. Thom Tillis, R-N.C., announced this week that President Trump had agreed to prevent drilling for oil and natural gas off the North Carolina coast, but the president has yet to speak publicly on the matter, and his administration says it is still moving forward with permitting for seismic exploration in the Atlantic.Tillis, whom polls show trailing his Democratic Party challenger Cal Cunningham, announced Monday that Trump had agreed to add North Carolina to a multistate moratorium on Atlantic offshore drilling announced earlier this month.The president announced Sept. 8 during an event in Jupiter, Florida, an order to extend the moratorium on offshore drilling on Florida’s Gulf Coast and expand it to Florida’s Atlantic Coast, as well as the coasts of Georgia and South Carolina. North Carolina was not included at the time.Tillis said Monday that he had spoken with Trump who agreed North Carolina would be included in the presidential memorandum withdrawing new leasing for offshore oil and gas developments for the next 12 years.Also on Monday, the Department of Justice filed a document with the U.S. District Court for the District of South Carolina, Charleston Division, stating that Trump’s memorandum “has no legal effect” on the status of the applications to conduct seismic surveys in the Atlantic Outer Continental Shelf that are pending before the Bureau of Ocean Energy Management.“If Trump were remotely serious about protecting Florida and the Carolinas from offshore drilling, he wouldn’t be allowing oil exploration along the coast,” Kristen Monsell of the Center for Biological Diversity Action Fund said in a statement. “This Justice Department filing underscores the appalling emptiness of Trump’s election-year effort to hoodwink voters. Seismic testing’s sonic blasts harm whales and other marine life, and they set the stage for future drilling and devastating oil spills.”

SCS resists request for Byhalia Pipeline to run through section of district property - Shelby County Schools is resisting an easement request for an oil pipeline to run along its property on Weaver Road in South Memphis, documents show. Leadership pointed to potential environmental risks and several lingering questions about the Byhalia Connection Pipeline and also pointed to community outcry over the last several months. The pipeline would run through Boxtown, a historically Black neighborhood in South Memphis that is still one of the city's poorest and most isolated, as reported in-depth by Storyboard Memphis. "From the administration side, there's still several questions about this project. Especially the idea that there would be an underground oil transfer from President's Island to Byhalia, would potentially present environmental risks. So our initial response, our recommendation, is to not accept this offer," John Barker, deputy superintendent for strategic operations and finance, said in a recent capital needs and facilities meeting. During the meeting district representatives Barker and Michelle Stuart, the director of facility planning and property management, said that the pipeline offered $25,340 for a 50-foot-wide easement, which would run along empty land the district owns on Weaver Road, between W. Holmes Road and Ruby Creek Cove. Board member Billy Orgel, who chairs the committee, initially questioned the rejection since the land is vacant and pointed to existing pipelines in Memphis. He later questioned whether the current route was the only one available. "Certainly it's not running through someone's neighborhood, is it?" he said. Stuart pointed to community meetings about the pipeline reported in the news. Southerly, which covers ecology, justice and culture in the South, and MLK50: Justice Through Journalism recently c0reported about the pipeline and the people whose families have owned land on the planned route for generations.

Louisiana lawmaker paid to push proposed pipeline through Black, Indigenous communities - Dorothy Ingram is among dozens of Raceland, Louisiana residents who say they’ve received few details about a proposed natural gas pipeline that would cut through historic Black churches and graveyards in their community, which sits about 40 miles west of New Orleans. “We have been treated unfairly and without meaningful involvement,”  “We as a community did not have a meeting in our area to participate in the plan.”First proposed in April 2019, the 280-mile Delta Express pipeline would be built through 14 parishes, connecting an existing natural gas pipeline in northern Louisiana to a liquid natural gas facility in Plaquemines Parish — Louisiana’s southernmost parish, where coastal erosion and sea level rise are expected to swallow up 55% of land without coastal restoration projects. The company, Venture Global, has not held a meeting to seek public comments in Lafourche Parish, which includes Ingram’s neighborhood. The pipeline is still in an early stage of permitting: Venture Global hasn’t submitted its formal application to FERC or acquired state permits. But emails show that the company has tried to influence state and federal permitting agencies by employing a Louisiana lawmaker, Rep. Ryan Bourriaque, R-Abbeville, who is also vice chair of the House Natural Resources and Environment Committee. Emails obtained through a public records request by the Energy and Policy Institute reveal that Bourriaque negotiated with the state’s Coastal Protection and Restoration Authority, or CPRA, about a separate Venture Global pipeline crossing a Mississippi River levee CPRA is planning to elevate. Bourriaque also sent a template letter for other Louisiana lawmakers to send to FERC in support of the Delta Express pipeline. “Regular citizens are having a harder time voicing their opposition to projects that impact them directly,” said Energy and Policy Institute researcher Itai Vardi. “At the same time, you see that there’s an acceleration with industry insiders using their cozy relationship with elected officials to influence decisions.”

Max Midstream buys Seahawk pipeline, terminal project -  Houston-based Max Midstream has purchased the Seahawk Pipeline project and Seahawk Terminal from Los Angeles-based Oaktree Capital Management. Max Midstream plans to bring the first phase of the terminal-and-pipeline project online in the fourth quarter, exporting crude from the terminal site at the Port of Calhoun on the Texas Coast between Houston and Corpus Christi. If it successfully does so, the project would represent a new place to load crude oil for waterborne export abroad."By developing the Seahawk Terminal at the port, we will be able to offer a deep-water terminal with little congestion and the ability for producers to get their product to the port at a very reasonable price,” CEO Todd Edwards said in a press release.The project is set to directly create 474 new jobs in addition to 598 construction-related jobs, according to the press release. The eventual goal of the project will be to directly connect oil production in the Permian Basin and Eagle Ford to the Port of Calhoun for export, and the company plans to spend up to $1 billion on the whole endeavor.The company expects it will be able to export up to 4.2 million barrels a month by November, Edwards said.Max Midstream has also reached a deal with the Calhoun Port Authority in which the company will finance $360 million toward an effort to deepen and widen the port to accommodate large vessels.“Once the widening and deepening project is complete, Aframax and Suezmax ships will also be able to load at the port, making it a viable option for any exporter seeking a port other than Houston or Corpus Christi,” the company said in the press release.

Oil well drilling fluid flows through neighborhood — While arriving home from work Wednesday afternoon, Alan Flores was surprised to see some kind of liquid flowing in the bar ditch in front of his house on Nueces County Road 73A just outside of Calallen. “We hadn’t had rain in two or three days, so I wondered, 'Where is all this coming from?" Flores said. "And the color was unusual. That’s what got me." Flores tracked the liquid about a quarter of a mile up the street to a property where a Houston-based company drilled for oil last month. He then called the Texas Commission on Environmental Quality concerned that the liquid could be dangerous. “We’re just being taken advantage of because the drilling company said they were going to take care of the community," he said while motioning to the bar ditch that still contained some of the liquid Thursday. "This isn’t taking care of the community." Rather than TCEQ, the Texas Railroad Commission says it's the agency that investigated the drilling fluid release Thursday and will continue to monitor the cleanup process. "The Railroad Commission will inspect the work to ensure public safety and the environment has been safeguarded," spokesperson Andrew Keese said in an email. The drilling company says the liquid is mostly rainwater but does include some drilling fluids used for lubrication, among other purposes. Tag Operating Company, Inc. says that fluid is not harmful -- rather beneficial. “They’re very desirable for agricultural purposes," Tag Principal Ted Snyder said. "Many landowners are very happy to have that on their soil." Snyder says the owner of the drill site and the Texas Railroad Commission approved releasing the drilling fluid on the property for that very purpose. But there was a problem. “What we hadn’t really calculated, with the heavy rains that we had last week, the ground was quite saturated," Snyder said. "As a result — rather than soaking into the soil as we anticipated that it would do — it ran off.” Snyder apologized for the miscalculation and reiterated to concerned residents that the drilling fluid isn't dangerous. Flores remains convinced there will be a negative impact. "Regardless of whether this (drilling fluid) is good for the environment or not, it shouldn’t end up going into the ditch which eventually goes into the Nueces River," Flores said.

Texas oil regulator exceeds state’s annual goal for plugging abandoned wells – For the fourth straight year the Railroad Commission of Texas has exceeded its performance target of plugging abandoned oil and gas wells throughout the state. With the fiscal year ending on Aug. 31, the agency plugged 1,477 orphan wells in Fiscal Year 2020, which exceeded the target of 1,400 set by the Legislature. “The State Managed Plugging Program is an important part of our critical mission to protect public safety and the environment.” said Danny Sorrells, RRC’s Assistant Executive Director and Director of its Oil and Gas Division. “Given the current energy industry downturn, the program also helps to employ oilfield service company workers throughout Texas. These employees are contracted and supervised to plug abandoned orphan wells by the Railroad Commission of Texas.” The State Managed Plugging Program is paid through industry fees rather than by taxpayers. This program addresses wells that are no longer productive and are considered orphaned in accordance with state laws and regulations. Railroad Commission staff prioritizes which orphan wells to plug based on potential risks to public safety and the environment. The work done in the most recent fiscal year continues a positive trend in the RRC’s work in exceeding performance targets. In Fiscal Year 2017, the goal was to plug 875 wells, and the agency plugged 918 wells. In Fiscal Years 2018 and 2019 the performance goal was to plug 979 abandoned wells each year, and the agency plugged 1,364 and 1,710 respectively.

Drilling Gaining Steam in Texas as US Rig Count Rises - Spurred by an uptick in drilling activity in Texas, the U.S. rig count climbed six units to finish at 261 for the week ending Friday (Sept. 25), according to the latest tally from oilfield services provider Baker Hughes Co. (BKR).Four oil-directed rigs and two natural gas-directed units returned to action in the United States, offering perhaps a hint of recovery amid a profoundly challenging stretch for the industry. As of Friday, BKR’s combined domestic tally still lagged year-ago levels by nearly 600 units.All of the gains occurred on land in the United States, with the Gulf of Mexico count unchanged at 14. Horizontal units increased by nine, while directional units declined by two and vertical units eased lower by one overall.The Canadian rig count gained seven units for the week to end at 71, down from 127 a year ago. Gains there were split between three oil-directed units and four gas-directed.The combined North American count rose 13 units for the week to end at 332, down from 987 at this time last year.Among the major plays, it was not the Permian Basin but the Eagle Ford Shale that led the charge during the week. The Eagle Ford added three rigs, upping its total to 12, versus 62 a year ago. The Permian, meanwhile, picked up to two rigs to end with 125, off from 414 a year ago.Also among plays, the Marcellus and Utica shales in the Northeast each added one rig to their respective totals.Broken down by state, the gains in the Permian and Eagle Ford helped lift the rig count in Texas by seven week/week. The Lone Star State ended up with 113 overall, versus 418 a year ago. New Mexico dropped two rigs from its total, falling to 41, versus 109 at this time last year. Elsewhere among states, Ohio and Pennsylvania each added a rig during the week, while Alaska and West Virginia each dropped one, BKR data show.

Exclusive: U.S. shale producer Devon in talks to acquire peer WPX - sources (Reuters) - U.S. shale producer Devon Energy Corp is in talks to acquire rival WPX Energy Inc in an all-stock transaction that would create a company worth around $6 billion, people familiar with the matter said on Saturday. The deal talks show how consolidation in the oil and gas industry is picking up, as low energy prices drive some independent producers to seek scale through mergers. In July, Noble Energy Inc agreed to be acquired by Chevron Corp for $5 billion in stock. The deal, which would value Tulsa, Oklahoma-based WPX at a small premium to its current share price, could be announced as soon as next week, according to one of the sources. The sources, who requested anonymity to discuss the private talks, cautioned that an agreement was not guaranteed. Devon and WPX did not immediately respond to requests for comment. Buffered by reduced demand for hydrocarbons amid coronavirus lockdown measures, which helped push U.S. crude prices briefly into negative territory for the first time earlier this year, U.S. oil and gas producers are seeking out combinations. Such mergers allow companies to remove duplication and create economies of scale, while structuring them at a small premium or none to existing valuations to retain as much cash as possible.

State, Enbridge resolve Straits of Mackinac oil pipeline injunction - Canadian oil transport giant Enbridge will create new safety guidelines for its contracted vessels operating near twin underwater oil and gas pipelines in the Straits of Mackinac, as part of a stipulated agreement with the state of Michigan in a court case stemming from damage to the 67-year-old pipelines. Ingham County Circuit Judge James Jamo announced the agreement Thursday. State Attorney General Dana Nessel on June 22 sought a preliminary injunction and temporary restraining order against operation of the Straits pipelines, known as Line 5, after Enbridge days earlier reported to the state "significant damage" had occurred to an anchor support holding one of the twin pipelines along the lake bottom. Later inspection showed an exterior striking of the other, westernmost pipeline as well by an object, suspected of being a cable hanging from a passing vessel. Nessel sought all of the information Enbridge had on the incident, and to keep the underwater pipelines out of operation until the state conducted a full review of the information with the help of independent experts. Ingham County Circuit Judge Jamo granted the temporary shutdown, then on July 1 allowed the westernmost of the underwater pipelines to resume operation following inspections, keeping the eastern line shut down as its damage was further investigated and awaiting response from the federal Pipeline and Hazardous Materials Safety Administration, or PHMSA, which regulates interstate oil and gas pipelines. In a Sept. 4 letter to Enbridge, PHMSA officials gave approval for the eastern line to resume operations, and those flows resumed Sept. 10.

Nessel joins coalition backing DAPL shutdown ⋆ Attorney General Dana Nessel has joined a coalition supporting the federal court order shutting down the Dakota Access Pipeline (DAPL). Michigan joins 18 other states, territories and countries urging the D.C. Circuit Court of Appeals to affirm strict enforcement of the National Environmental Policy Act (NEPA). Nessel has previously sued Enbridge — which owns Line 5 and also is a partial owner of the DAPL — on behalf of the state of Michigan due to environmental concerns about that pipeline running through the Straits of Mackinac. A court decision was announced in July that the DAPL must shut down due to an environmental review. That pipeline runs from North Dakota and has been opposed by environmental groups and Native American tribes, including the Standing Rock Sioux. President Trump has been a staunch supporter. “The U.S. Army Corps of Engineers failed to comply with legal requirements by neglecting to fully consider the consequences of a breach of the Dakota Access Pipeline, and my colleagues and I urge the Court of Appeals to affirm the lower court’s ruling,” Nessel said in the press release on Thursday. “This oil and gas pipeline could potentially impact the environment and has climate change implications we cannot overlook. Moreover, we must join our Indigenous partners who have led the way in raising the alarm about the environmental threat this project poses. As they have advocated from the beginning, shutting down this project is essential to protecting the environment.”

Judge denies key permit for Monroe County sand project; Meteor Timber sought to fill rare wetlands  – A judge has declined to reinstate a key permit for a Georgia company seeking to build a controversial frac sand operation in Monroe County.Monroe County Circuit Judge Todd Ziegler ruled Monday that the state Department of Natural Resources violated the law when it granted Meteor Timber a permit to fill 16.25 acres of wetlands for the $75 million project.Ziegler’s oral ruling affirms an administrative law judge’s decision to revoke the permit, finding that Meteor failed to demonstrate its project would not result in significant adverse impacts to the environment.“The application was not complete. That requires the application to be denied,” Ziegler said. “The law as interpreted by the (administrative law judge) is correct in this regard.”Environmental advocates and the Ho-Chunk Nation, who had challenged the permit, applauded Ziegler’s decision as a victory “for all those who value our natural resources and the public’s role in protecting them.”Ho-Chunk lawmaker Rep. Conroy Greendeer Jr. said the nation is “relieved that the law can balance economic development and the harmful impacts of environmental exploitation.”“The homelands of the Ho-Chunk Nation and our people are being defaced by each of these frac sand operations,” Greendeer said. “Every truckload and train full of sand that comes out of Wisconsin leaves behind scars on our landscape, upon this habitat, and in our lungs.”“We must listen to the science, and to scientists, when making decisions that permanently affect the environment in Wisconsin,” said Evan Feinauer, staff attorney for Clean Wisconsin. “Today’s ruling also makes clear that all permit applicants must meet the same legal standards, irrespective of their wealth or political influence.”Attorneys for Meteor Timber did not immediately respond to requests for comment. The decision marks the end of another chapter in Meteor’s four-year effort, which has spanned two administrations, multiple courts and a boom-and-bust cycle for Wisconsin’s frac sand industry, which supplies silica used to extract oil and gas from deep rock formations.

Colorado draws 2,000-foot statewide oil and gas drilling setback. But it comes with a big “however.” –  Colorado is poised to impose the biggest statewide oil and gas drilling setback in the nation – 2,000 feet from homes and schools – after state regulators unanimously backed the measure in an informal vote Thursday. A final, formal vote will be held Nov. 6. But while setting the buffer for even a single home, many members of the commission made clear that there would be “offramps” allowing oil and gas operators to site their drill pads closer. “This is a good place to be,” Colorado Oil and Gas Conservation Commission Chairman Jeff Robbins said during a meeting held on Zoom. “2,000 feet is necessary and reasonable” to protect public health and safety Environmental and community groups had pushed for the 2,000-foot buffer from drilling, while industry advocates said it would severely hamstring companies and might lead to a lawsuit. Twelve other states have statewide setbacks, but the largest is 1,000 feet, according to the National Conference of State Legislatures. California is also considering a 2,000-foot setback. The setback rule is part of a comprehensive revision of regulations to reflect COGCC’s change in mission, from promoting oil and gas development to protecting public health, safety and welfare, and the environment. The change is the result of Senate Bill 181, which was passed in 2019.

This month's oil and gas lease sale still on, but numerous parcels deferred - A federal auction of public land scheduled this month for oil and gas companies will move ahead, albeit at a significantly smaller scalethan initially announced. The Bureau of Land Management confirmed it will defer the vast majority of parcels from the Thursday sale in response to a federal court decision to vacate leases located on sage grouse habitat.Of the 290 parcels the agency originally intended to lease during two sales this month, only eight parcels covering about 4,000 acres will be available to oil and gas developers in Wyoming.The federal government offers a selection of nominated parcels to oil and gas companies in an online bidding process, typically four times a year. The agency usually hosts the competitive sales in March, June, September and December, but the pandemic has made this year an anomaly. The agency postponed the June sale in Wyoming, along with sales in several other Western states, in response to COVID-19. And the September sale will be notably smaller in response to a court order. In May, a Montana judge ruled the U.S. Interior Department had failed to properly prioritize leasing public land outside sage grouse core habitat for energy development during several quarterly lease sales. The U.S. District Court for Montana’s order effectively struck down the sale of 440 leases, encompassing 336,000 acres auctioned during a June 2018 lease sale. It marked the second ruling in a single year from the 9th Circuit vacating oil and gas lease sales in Wyoming. Wyoming is home to the world’s largest sage grouse population, forcing public officials to walk a fine line between preserving the imperiled bird’s limited sagebrush habitat and not infringing on the state’s economic backbone — oil and gas. Nearly half of sage grouse habitat nationwide falls on public land managed by the BLM.

North Dakota's Natural Gas Production Increased 17% Month-Over-Month; State Still Hit Capture Target Guidelines; NDIC Tweaks Policy -- September 23, 2020 - Big headline in Bismarck, but, wow, talk about trivial. The NDIC simply tweaked some rules and regulations after consulting with the oil companies. Link to Houston Chronicle:North Dakota’s Industrial Commission on Tuesday approved a revised gas capture policy that aims to encourage investment in infrastructure but doesn’t change targets for burning excess natural gas at well heads.State Mineral Resources Director Lynn Helms said the Oil and Gas Division has “relaxed the policy slightly in a few places and tightened it significantly in other places” after months of consultation with industry and environmental groups, The Bismarck Tribune reported.Helms said future gas capture requires “a monumental effort” and billions of dollars in infrastructure such as natural gas processing plants and pipelines. North Dakota's gas production is projected to hit 5.3 billion cubic feet a day 18 years from now. The state produced a record of more than 3.1 billion cubic feet per day in November 2019.Companies have met or exceeded gas capture goals in recent months, largely due to decreased production amid the coronavirus pandemic and several new processing facilities and expansions coming online in the last year, North Dakota Pipeline Authority Director Justin Kringstad said.The policy includes several exceptions for companies that flare natural gas under certain circumstances, such as gas plant outages or delays securing a right-of-way for pipeline construction. Mineral Resources spokeswoman Katie Haarsager said the revised policy should clarify how the variances in the calculation are applied. In fact, natural gas production increased by 17% month-over-month in most recent data and North Dakota still reached its natural gas capture target.  Link here.

North Dakota Industrial Commission approves revisions to gas capture policy North Dakota’s Industrial Commission on Tuesday approved a revised gas capture policy that aims to encourage investment in infrastructure but doesn't change the gas capture targets.Current gas capture policy requires companies to capture 88% of the Bakken natural gas they produce. The target increases to 91% on Nov. 1.State Mineral Resources Director Lynn Helms said the Oil and Gas Division has “relaxed the policy slightly in a few places and tightened it significantly in other places” after months of consultation with industry and environmental groups.The changes approved unanimously Tuesday aim to ensure industry compliance with gas capture regulations amid future gas production growth."We believe that the revisions that we've made to the gas capture policy are the right step at the right time, but I do think every two or three years, we are going to have to look at this thing and modify it as time goes on," Helms told the three-member, all-Republican panel chaired by Gov. Doug Burgum. Helms said future gas capture requires "a monumental effort" and billions of dollars in infrastructure such as natural gas processing plants and pipelines amid projections that see North Dakota's gas production hitting 5.3 billion cubic feet a day 18 years from now.North Dakota produced nearly 2.3 billion cubic feet per day in July, the most recent figure available. The state produced a record of more than 3.1 billion cubic feet per day in November 2019.Companies have met or exceeded gas capture goals in recent months, largely due to decreased production amid the coronavirus pandemic and several new processing facilities and expansions coming online in the last year, North Dakota Pipeline Authority Director Justin Kringstad said.The policy includes several variances, or exceptions, for companies that flare natural gas under certain circumstances, such as gas plant outages or delays securing a right-of-way for pipeline construction. Mineral Resources spokeswoman Katie Haarsager said the revised policy aims to clarify how the variances in the calculation are applied. Attorney General Wayne Stenehjem, who sits on the commission, praised Helms for developing "a North Dakota-centric plan."

Lightning strike causes oil spill near McKenzie County creek - — An estimated 10,000 gallons of oil and produced water spilled into the tributary of a creek in McKenzie County, according to a news release from the state Department of Environmental Quality. Produced water, or brine, is a mixture of saltwater, oil and sometimes, drilling fluids, that is created during oil and gas production. The spill occurred Wednesday, Sept. 24, at a saltwater disposal well about eight miles north of Alexander due to a lightning strike at a saltwater injection facility operated by Environmentally Clean Systems, according to the release. Initial inspection found that the oil and brine spilled into a tributary of Camp Creek. It's the second spill in McKenzie County this summer caused by a lightning strike. Department officials will continue inspecting the site and monitoring remediation efforts, the release said.

Oil Companies Are Profiting From Illegal Spills. And California Lets Them. — ProPublica - In May 2019, workers in California’s Central Valley struggled to seal a broken oil well. It was one of thousands of aging wells that crowd the dusty foothills three hours from the coast, where Chevron and other companies inject steam at high pressure to loosen up heavy crude. Suddenly, oil shot out of the bare ground nearby. Chevron corralled the oil in a dry streambed, and within days the flow petered out. But it resumed with a vengeance a month later. By July, a sticky, shimmering stream of crude and brine oozed through the steep ravine.  Workers and wildlife rescuers couldn’t immediately approach the site — it was 400 degrees underground, and if the earth exploded or gave way, they might be scalded or drown in boiling fluids. Dizzying, potentially toxic fumes filled the scorching summer air. Lights strobed through the night and propane cannons fired to ward off rare burrowing owls, tiny San Joaquin kit foxes, antelope squirrels and other wildlife.   Over four months, more than 1.2 million gallons of oil and wastewater ran down the gully. California had declared these dangerous inland spills illegal that spring. They are known as “surface expressions,” and the Cymric field was a hot spot. Half a dozen spills and a massive well blowout had occurred there since 1999. This time, faced with news headlines and a visit by Gov. Gavin Newsom to the site, officials with the California Geologic Energy Management Division, or CalGEM — the main state agency overseeing the petroleum industry — ordered Chevron to stop the flow. Regulators later levied a $2.7 million fine on the company.Instead, Chevron profited.Amid the noise and heat, trucks arrived daily to vacuum out the oil from a safe distance. It was refined, sold and shipped to corner gas stations, bringing the company $399,000, according to state records. Chevron appealed the fine, saying while “we fully accept — and take responsibility for — our actions,” it does not believe the spill, known as Cymric 1Y, posed a threat to human health. The company has yet to pay, and CalGEM has not moved forward with an appeal hearing. Along with being a global leader on addressing climate change, California is the seventh-largest producer of oil in the nation. And across some of its largest oil fields, companies have for decades turned spills into profits, garnering millions of dollars from surface expressions that can foul sensitive habitats and endanger workers, an investigation by The Desert Sun and ProPublica has found.

Energy executives say U.S. oil production has peaked: Dallas Fed survey  (Reuters) - Nearly two-thirds of U.S. energy company executives polled by the Federal Reserve Bank of Dallas believe U.S. crude oil production has peaked, according to a survey released on Wednesday. The COVID-19 pandemic has knocked global oil demand and prices, prompting deep cuts in drilling this year by shale oil producers. The United States last pumped 12.2 million barrels per day, taking top spot in global crude oil output. Survey results said 66% of 154 oil and gas firm executives contacted by the Dallas Fed this month believe U.S. crude oil production has peaked. The survey includes executives from Texas, Louisiana and New Mexico. The Dallas Fed did not say if the peak was considered temporary or permanent as major oil firms have been discussing. Global demand destruction during the COVID-19 pandemic, work from home policies and the continued growth of electric vehicles has energy companies looking to a prolonged downturn in crude oil and fuel consumption. Earlier this year, BP Plc BP.L said the pandemic would reduce demand by 3 million barrels per day (bpd) through 2025 and forecast a peak in demand between 2019 and 2050, according to the company's energy outlook. Nearly three-quarters of executives from 148 oil and gas firms told the Dallas Fed that the Organization of Petroleum Exporting Countries (OPEC) would have a bigger role in determining the price of crude oil going forward. Executives surveyed, on average, expect the price of West Texas Intermediate (WTI) crude oil CLc1 to be $43.27 a barrel by the end of 2020. On Wednesday, WTI was up 36 cents at $40.16 a barrel.

Energy transition could spur $111 billion in oil divestments, report says -  A societal shift from fossil fuels to renewable energy could force the largest oil companies to sell $111 billion worth of oil and gas assets in the coming years, according to a new report. Rystad, a Norwegian energy research firm, on Tuesday said oil companies will need to streamline their oil and gas portfolios significantly to address low oil prices and falling demand for fossil fuels, particularly in advanced countries concerned about climate change.

It's time for states that grew rich from oil, gas and coal to figure out what's next - These are very challenging times for U.S. fossil fuel-producing states, such as Wyoming, Alaska and North Dakota. The COVID-19 economic downturn has reduced energy demand, with uncertain prospects for the extent of its recovery. Meanwhile, rising concern about climate change and the declining cost of renewable energy are precipitating a sharp decline in demand for coal in particular. As a result, fossil fuel-dependent states and communities face the prospect of budget shortfalls and lower employment for the next several years. As researchers who study energy from economic, cultural and public policyperspectives, we believe that it is time for these states to develop long-term plans to diversify their economies and help ensure just and equitable transitions. The idea of a just transition emerged from North American labor law, and has become part of international discussions about making societies more environmentally sustainable. It centers on protecting workers’ rights and livelihoods as they move out of declining industries. In our view, just transition programs likely are the best way for these states to build more sustainable and diverse economic bases, reducing their reliance on fossil fuel production as a revenue source. To support secure, family-sustaining jobs as global fossil reliance declines, they will need to create new, lower-carbon economies. The states that are most reliant on energy are Alaska, where it accounted for 70% of state revenues ($1.1 billion) in fiscal 2019; Wyoming, where energy and other minerals yielded 52% of state revenues ($2.2 billion) in FY2017; and North Dakota, which reaped 45% of its revenues ($1.6 billion) from energy production in fiscal 2017. Production declines and workforce reductions can have major economic impacts in fossil fuel states. For example, Wyoming is forecasting that it will have 29% less money in its General Fund than it previously expected in fiscal years 2021-22. Alaska is projecting an estimated 18% budget deficit in fiscal 2021. Even assuming that oil and gas production recovers from FY2020-2021 lows, these states expect to be forced to close the funding gap for the next several years.

Exclusive: Shell launches major cost-cutting drive to prepare for energy transition - (Reuters) - Royal Dutch Shell is looking to slash up to 40% off the cost of producing oil and gas in a major drive to save cash so it can overhaul its business and focus more on renewable energy and power markets, sources told Reuters. Shell’s new cost-cutting review, known internally as Project Reshape and expected to be completed this year, will affect its three main divisions and any savings will come on top of a $4 billion target set in the wake of the COVID-19 crisis. Reducing costs is vital for Shell’s plans to move into the power sector and renewables where margins are relatively low. Competition is also likely to intensify with utilities and rival oil firms including BP and Total all battling for market share as economies around the world go green. “We had a great model but is it right for the future? There will be differences, this is not just about structure but culture and about the type of company we want to be,” said a senior Shell source, who declined to be named. Last year, Shell’s overall operating costs came to $38 billion and capital spending totalled $24 billion. Shell is exploring ways to reduce spending on oil and gas production, its largest division known as upstream, by 30% to 40% through cuts in operating costs and capital spending on new projects, two sources involved with the review told Reuters. Shell now wants to focus its oil and gas production on a few key hubs, including the Gulf of Mexico, Nigeria and the North Sea, the sources said. The company’s integrated gas division, which runs Shell’s liquefied natural gas (LNG) operations as well as some gas production, is also looking at deep cuts, the sources said. For downstream, the review is focusing on cutting costs from Shell’s network of 45,000 service stations - the world’s biggest - which is seen as one its “most high-value activities” and is expected to play a pivotal role in the transition, two more sources involved with the review told Reuters. “We are undergoing a strategic review of the organisation, which intends to ensure we are set up to thrive throughout the energy transition and be a simpler organisation, which is also cost competitive. We are looking at a range of options and scenarios at this time, which are being carefully evaluated,” a spokeswoman for Shell said in a statement.

Oil Springs Eternal - EXXONMOBIL WAS ONCE the most valuable company on earth. The product of a Clinton-era merger between the rebranded progeny of Standard Oil Company of New Jersey and Standard Oil Company of New York—reuniting, respectively, as Exxon and Mobil, nearly a century after a Supreme Court antitrust ruling cleaved their parent company apart—it has long benefitted from the worldwide neoliberal retreat of government in the face of swelling corporate power. The corporation’s influence ran deep, especially in regard to the public perception of climate change. “Those with power create knowledge,” wrote Emily Plec and Mary Pettenger in a 2012 study of ExxonMobil’s marketing practices. At the time, ExxonMobil was aggressively marketing its latest low-emission energy initiative, a venture into algae biofuels. Do not fear climate change, such ads, which carry on today, seemed to suggest. Our engineers are hard at work. As Plec and Pettenger saw it, ExxonMobil’s greenwashing coached “acceptance of a particular attitude toward history,” effectively resigning the mainstream public to the incumbent energy regime, constraining efforts to imagine a future that does not, like the present, orbit around “ideologies of consumption”—and companies like ExxonMobil. If ExxonMobil ever did stand eternal, its public messaging certainly did not. In his day, one-time CEO Lee R. Raymond was famously loathe to concede an inch to the company’s rabid environmentalist adversaries—even on the public relations front. In 2000, with regard to global warming, he could be heard telling shareholders: “If the data were compelling, I would change my view. Ninety percent of people thought the world was flat. No?” As the journalist Steve Coll noted in his 2012 epic, Private Empire: ExxonMobil and American Power, some ExxonMobil executives “took pride in their self-image as a corporation that did not try to pretend to be something it was not.” In this, the company differed from fellow oil and gas giant BP Amoco, which rebranded in 2000 as just “BP,” unveiling a new sun logo and marketing slogan: Beyond Petroleum. ExxonMobil took a different tack. Raymond dismissed the company’s earlier ventures into renewable energy as moments of weakness, in which its former leaders made reactionary concessions to ephemeral political fads, eroding the business’s core identity. “In hindsight it appeared that we were abdicating who we were,” Raymond told Coll, referring to the company’s adventures in solar during the seventies. “Presidents come and go; Exxon doesn’t come and go.”

Oil Industry’s Shift to Plastics in Question as Report Warns $400 Billion in Stranded Assets Possible -  Aldabra is a UN World Heritage Site that’s home to a stunning array of wildlife, including tens of thousands of wild giant tortoises, far more tortoises than in the Galapagos Islands. This wild, protected place is also, according to newly published research from Oxford University, littered with over 500 tons of plastic waste.That’s the amount remaining after the Oxford team itself removed 25 tons of plastic debris, a manufactured mountain of plastic trash that included 360,000 used flip flop sandals and literal tons of plastic nets, ropes and other fishing industry trash. “This is the largest accumulation of plastic waste reported for any single island in the world,” Oxford noted as the findings were announced.  Since the 1950’s, the world has produced over 8.3 billion tons of plastic, according to UN Environment, virtually all of it derived from fossil fuels. During the 1970’s and 80’s, plastic waste generation rates more than tripled, causing growing concern among consumers.“The image of plastics is deteriorating at an alarming rate,” Larry Thomas, a former president of a plastics industry association, wrote in records obtained by NPR from that meeting. “We are approaching a point of no return.”The solution the gathered executives arrived at, NPR found, was to advertise a solution that industry officials knew was unworkable: recycling.The campaigns resulted in very little actual plastic being recycled. Less than ten percent of the plastic ever made has been recycled even once, a 2017 peer-reviewed scientific paper found — and global recycling ran further aground the following year, when China banned imports of most used plastics after that nation’s attempts at processing and recycling the world’s plastic scrap became inescapably overwhelmed.  But from the plastic and oil industries’ perspectives, pro-recycling campaigns proved to be extraordinarily effective — not just because advertising plastic recycling helped to insulate the industry from public concern, but also, as NPR noted, because recycled plastic was always actually a poor and expensive substitute for new plastics — which meant less competition for oil companies and plastics manufacturers. This past year has brought massive disruptions for fossil fuel producers, who saw oil prices briefly dip far below $0 a barrel in some places amid pandemic lockdowns and witnessed ExxonMobil, once the king of blue chip stocks, unceremoniously bootedfrom the widely-watched Dow Jones Industrial Average. But executives with major oil giants have said that even if oil demand grown dries up, they expect they’ll still be able to sell an increasing amount of their products as petrochemicals. “Unlike refining, and ultimately unlike oil, which will see a moment when the growth will stop, we actually don’t anticipate that with petrochemicals,” Andrew Brown, a Royal Dutch Shell official,told the San Antonio Express News in 2018. This strategy, according to a report published this month by the Carbon Tracker Initiative, carries significant financial risks, putting $400 billion of petrochemical industry investments at risk of becoming stranded assets. That’s nearly an entire year’s revenue for the worldwide plastics industry, based on 2018 figures from the Plastics Industry Association, potentially down the drain.

Pompeo: We are Building A Coalition Against Nord Stream 2 - The United States is building a coalition aimed at preventing the completion of the Nord Stream 2 pipeline that will substantially increase the flow of Russian gas into Europe, the U.S. Secretary of State told German daily Bild in an interview. “From the US point of view, Nord Stream 2 endangers Europe because it makes it dependent on Russian gas and endangers Ukraine – which in my opinion worries many Germans,” Pompeo said. “We hope Nord Stream 2 will not be completed and we are working on a coalition to prevent this from happening. We hope that the German government will also come to this assessment, be it because of what happened to Mr. Navalny or because of the security implications that dependence on Russian gas brings.” The interview comes days after another report in German media said the German government had tried to appease Washington about Nord Stream by offering to build two liquefied natural gas import terminals worth $1.2 billion if the U.S. stopped opposing the pipeline. Germany will be the receiver of most of the gas that will flow through the expanded Nord Stream pipeline amid an expected surge in demand for natural gas as it closes coal and nuclear power plants. The U.S., however, is against it, claiming it will only increase Russia’s influence in the energy supply of the EU, which would be unwise. Of course, there are also the U.S. gas interests as a major LNG exporter. The alleged poisoning of Putin critic Alexey Navalny recently raised the temperature of the issue, with critics of the Nord Stream project calling for the German government to punish Moscow by withdrawing its support for the infrastructure. On the other hand, a group of local primer minister from eastern German regions declared their support for Nord Stream 2, saying in a joint document that it was important for the energy future of both Germany and Europe and its completion would be “right and justified”.

Trinidad to inspect Venezuela oil storage vessel - Trinidad and Tobago is concluding arrangements with Venezuela to allow its inspectors to access a damaged oil storage vessel in the Gulf of Paria, the Caribbean state's energy ministry told Argus. The inspection of the Venezuela-flagged Nabarima is meant to "independently verify reports that the vessel has been stabilized and that leaking oil does not pose a threat to our waters," Trinidad's energy ministry said. The inspection will not violate US sanctions on Venezuela, the ministry added. The Trinidadian and Venezuelan governments have exchanged the required protocols to clear the way for the inspection that will happen by the end of September, the ministry said. "We have been told arrangements are being made to offload the cargo and we are relieved that this is happening," the ministry said, adding that the inspection will deliver the assurance that Trinidad's waters are not in danger of a major oil spill. The Nabarima, which is holding around 1.2mn bl of crude, has been moored at the offshore Corocoro field in the Gulf of Paria for 10 years. The field, which is not currently in production, belongs to PetroSucre, a joint venture operated by Venezuelan state-owned PdV. The company's minority partner is Italy's Eni. The vessel had been listing in recent weeks, but PdV and Eni have since said the vessel is upright after problems were corrected. The Corocoro field had been producing around 11,000 b/d of medium-quality crude before it was suspended in August 2019. Trinidad has a bilateral oil spill contingency plan with Venezuela, but transferring the oil off of the Nabarima has been delayed by the sanctions. Eni has said it awaiting a green light from the US before proceeding to help deploy a dynamic positioning tanker to drain the vessel. How the crude is handled after it is unloaded is unclear in light of the sanctions.

Chilean regulators file charges against state-run ENAP over Quintero pollution crisis (Reuters) - Chile´s top environmental regulator on Thursday filed charges against state energy company ENAP over allegations its Quintero port facilities emitted air pollution that may have sickened hundreds during an incident in 2018. The Environmental Superintendent (SMA) said recent studies linked high levels of air contaminants to the company´s operations in Quintero at a time when it was offloading a shipment of heavy Iranian crude oil. At the time, hundreds of people in the port town reported nausea, headaches and vomiting. ENAP told Chile´s financial regulator in a filing Thursday “it has the necessary technical background to demonstrate...that the alleged infractions have not caused any effect in the health of the population.” Environmental activists have long labeled the town of Quintero and its surroundings a “sacrifice zone” for the successive pollution episodes that have caused public health emergencies. The coastal port city is home to coal-burning power plants, an oil refinery, and a copper smelter, some of which operate very close to residential areas. ADVERTISEMENT The SMA said in a statement that the company had eluded regulators by failing to inform them of their activities and use of potentially high-risk and closely regulated chemicals. The infractions continued during the SMA´s earlier investigation of the incident, the agency said. The regulator said some of the seven charges it filed against ENAP are serious enough to lead to the revocation of the company´s environmental permits at Quintero. It has given the state energy company 10 days to provide the agency with a compliance plan or 15 days to contest the charges. ENAP is the main oil refiner in Chile, which imports nearly all the fuel it consumes.

Investors Are Pulling The Plug On Argentina’s Prized Shale Play  Much ink has been spilled about the downfall and dubious recovery of the United States shale oil sector. The West Texas Intermediate (WTI) crude benchmark’s dramatic rock bottom in April, which saw oil prices plunge to nearly $40 dollars below zero in a jaw-dropping first, a flurry of think pieces about the sector’s future poured forth and has never fully stopped. While the Brent international crude benchmark never went negative, it also suffered, and there have been no shortage of headlines about OPEC and their ill-planned actions that sent prices tumbling in the first place or their redoubled efforts to recover after the crash. But there are plenty of other oil producing countries in the world who have also seen massive market failures due to COVID-19’s destruction of oil demand and which have not received even a fraction of the attention. One such country is Argentina, home to one of the largest oil and gas fields in the world, the Vaca Muerta shale basin, which contains approximately 927 million barrels of proven reserves.  Way back in April, even before the historic WTI crash, Bloomberg (via World Oil) published one of relatively few reports of the shale play. More than a report, it was an obituary. “Oil crash kills Vaca Muerta’s potential as the next shale hotspot,” the headline read.  Now, nearly half a year later, is Vaca Muerta fully dead? The short answer is no. The full answer, of course, is a lot more complicated. According to the Argentinian energy minister of Neuquen province, where the vast Vaca Muerta field is located, resurrecting the shale play will take more than a year. Achieving pre-COVID-19 production levels, he said, will take an estimated 12-18 months due to a lack of market demand, which may not be bouncing back any time soon. “We believe it will take a while for fuel demand to fully recover,” Monteiro told listeners on Monday in an industry webinar. Before COCID-19, Vaca Muerta had been in a state of rapid expansion, as Bloomberg's “next potential shale hotspot” description would indicate. The novel coronavirus, however, stopped this expansion in its tracks, leaving many projects half-completed. “Many wells have been drilled but not connected, but even when demand fully recovers it will take even longer for drilling activity to return to pre-pandemic levels because of storage constraints,” MercoPress reported this week, summing up the energy minister’s announcement. This is exemplified by YPF, Argentina’s largest shale producer, which is controlled by the state. YPF “has said it has 71 shale oil wells and 10 shale gas wells in Neuquen that have been drilled but not completed.”   “In mid-2019, companies had said they would invest a total of more than US$ 6bn in upstream projects in Neuquen in 2020,” MercoPress reports. “Now the number is closer to US$ 3bn, the lowest since 2016, according to provincial data.”

Seventeen dead dolphins wash ashore on island of Mauritius - Seventeen dead dolphins washed up on the Indian Ocean island of Mauritius after a wrecked oil tanker precipitated an ecological disaster within the space — sparking anger from residents, in line with studies. Some of the animals had bloody accidents once they have been found Wednesday and others touring within the pod appeared severely sick, researchers from the island nation advised Reuters. “The dead dolphins had a number of wounds and blood round their jaws, no hint of oil nevertheless,” mentioned Jasvin Sok Appadu of the nation’s fisheries ministry. “Those that survived, round ten, appeared very fatigued and will barely swim.” Some residents have been livid over the heartbreaking discovery. “Waking up this morning to witness so many dead dolphins on our seashore is worse than a nightmare,” Nitin Jeeha, who lives on the island, advised the BBC. The lifeless mammals have been taken to the Albion Fisheries Analysis Centre for an animal post-mortem however outcomes hadn’t been launched Thursday. They have been discovered roughly a month after the Japanese-owned MV Wakashio tanker struck a coral reef on July 25 and commenced to leak a whole lot of tons of oil. Some scientists mentioned the dolphins seemingly died from being poisoned by the gasoline. A person holds open the mouth of a dead Melon-headed whale, also called Electra dolphin, after the oil spill.EPA“I feel there are two potentialities: Both they died from tons of gasoline spilled within the sea, or they have been poisoned by the poisonous supplies on the bow of the ship that was sunk offshore,” mentioned environmental marketing consultant Sunil Dowarkasing.

Oil leak from ONGC pipeline damages samba crops - Oil spill from the underground pipeline of Oil and Natural Gas Corporation (ONGC), conveying crude oil extracted from the ground has damaged an agricultural land cultivated with samba crops at Keezha Erukkattur village in Tiruvarur district. The oil seepage into agricultural land, reportedly due to a crack in the ONGC pipeline, owned by a farmer Dhanasekaran was noticed on Wednesday morning. Due to the oil leakage, a portion of the land was inundated with the crude oil damaging the samba crops raised in one acre. The oil seepage was spreading to the nearby agricultural lands in the village, the locals alleged.

Arab ministers warn of oil spill disasters in the Red Sea - Arab ministers have warned of oil spill disasters in the Red Sea and called on international and regional bodies to maintain maritime security in the area. An Arab League video conference session on Monday brought together ministers responsible for environmental affairs. The session was held at Saudi Arabia’s request to discuss ways of avoiding a disaster in the Red Sea because of an oil tanker that has been anchored off Yemen’s Ras Isa port since 2015. The Houthis have prevented international engineers from boarding the vessel to carry out essential repairs and there are fears that the oil it contains will start to seep out as the tanker’s condition deteriorates. Ambassador Kamal Hassan Ali, assistant secretary-general and head of the economic affairs sector at the Arab League, said that the meeting concluded with foreign ministers being requested to take political action as the oil disaster threat was a matter of politics and security. The meeting also requested that the league’s general secretariat communicate with the regional and international bodies of countries bordering the Red Sea and Gulf of Aden to preserve the environment and provide technical support in order to submit a report on spillage risks. Hassan said that finding an appropriate solution to avoid an environmental catastrophe was of major regional and global importance because the scale of such a disaster would threaten marine life, biodiversity, international shipping lines and ports in that location. He said that the region was facing major challenges that demanded solidarity and unity in all fields, including the environment.

Saudi warns of oil spill from tanker stranded off Yemen coast for five years - Saudi Arabia warned the UN Security Council on Wednesday that an "oil spot" had been seen in a shipping transit area 31 miles (50km) west of a decaying tanker that is threatening to spill 1.1 million barrels of crude oil off the coast of Yemen. The Safer tanker has been stranded off Yemen's Red Sea oil terminal of Ras Issa for more than five years. The United Nations has warned that the Safer could spill four times as much oil as the 1989 Exxon Valdez disaster off Alaska. In a letter to the 15-member body, Saudi Arabia's UN Ambassador Abdallah Al Mouallimi wrote that experts had observed that "a pipeline attached to the vessel is suspected to have been separated from the stabilisers holding it to the bottom and is now floating on the surface of the sea." The United Nations has been waiting for formal authorisation from Yemen's Houthi movement to send a mission to the Safer tanker to conduct a technical assessment and whatever initial repairs might be feasible. The Security Council and UN Secretary-General Antonio Guterres have both called on the Houthis to grant access. Al Mouallimi wrote that the tanker "has reached a critical state of degradation, and that the situation is a serious threat to all Red Sea countries, particularly Yemen and Saudi Arabia," adding "this dangerous situation must not be left unaddressed."

OPEC In Trouble As Oil Outlook Worsens -Just when they thought they had rebalanced the oil market, OPEC members were served an unpleasant surprise from exempted fellow Libya. The country’s warring factions reached a ceasefire, and some long-shuttered oil ports have been reopened, along with the fields that feed them. By the end of the month, the National Oil Corporation plans to boost the average daily output of the nation from less than 100,000 bpd to 260,000 bpd. Meanwhile, OPEC+ has relaxed its production cuts by 2 million bpd.  The market, according to Mercuria chief executive Marco Dunand, cannot handle this.In an interview for Bloomberg, Dunand said demand was still weaker than previously expected, and any additional oil flowing into markets would fail to be absorbed. This means a looming build in floating storage as this month, global inventories rose by between 500,000 bpd and 1 million bpd—and that’s excluding the Libyan restart— while drawdowns over the final quarter were seen at 1 million bpd.In his bearish outlook for the immediate term, Mercuria’s head is in sync with the head of another commodity trading major, Trafigura. The third super trader, however, is surprisingly optimistic. Also in an interview with Bloomberg, Vitol’s chief executive said earlier this month he expected global crude oil inventories to shrink considerably by the end of the year. While both the heads of Trafigura and Mercuria expect stocks to build first before starting to decline, Vitol’s chief said he expected a drawdown of some 250-300 million barrels by the end of the year.Reports emerged earlier this month that commodity traders—including the Big Three—were chartering more tankers to store crude oil offshore, sparking concern we could see something like a repeat of this spring when hundreds of millions of barrels of unsellable oil had to be dumped on tankers because onshore storage was full. After the lockdowns ended, demand began improving. This moderate demand boost, however, fell short of pretty much all expectations. One particularly worrying trend is the slow rate of economic recovery among emerging countries—the main drivers of oil demand growth. Except for China, most are still battling the coronavirus and its effects on their economies. India is a good case in point: its oil demand is seen to be the worst affected by the coronavirus as the country itself suffers the second-highest total case count in the world. Some analysts believe, however, that demand in China is about to start slowing down soon. It will be a long-term trend, according to the Oxford Institute for Energy Studies, and a result not just of Covid-19 but of Beijing’s emission-reduction goals. Over the next 20 years, the energy research organization said, China’s oil demand was likely to grow at an annual pace of 3 to 4 million bpd, after growing by double-digit rates in the past few years.According to Mercuria’s Dunand, oil demand during the fourth quarter will average 95 million bpd. That’s down from a market consensus of 97 to 98 million bpd, made in spring. And the rate at which excessive inventories will be drawn is seen weaker than previously expected. Add to this a dramatic build in diesel inventories because refiners, Dunand noted to Bloomberg, are dumping jet fuel into the diesel pool, and Libya’s restart of production and the outlook for prices once again becomes grim.

Oil prices steady as third storm in month takes aims at U.S. - Oil prices edged higher on Monday as a tropical storm took aim for the U.S. Gulf of Mexico region halting some production, though price gains were capped by the potential return of oil output in Libya and a continued rise in coronavirus cases. Brent crude was up 9 cents, or 0.2%, at $43.24 a barrel by 0230 GMT, while U.S. crude was up 10 cents, or 0.2%, to $42.21 a barrel. Royal Dutch Shell Plc halted some oil production and began evacuating workers from a U.S. Gulf of Mexico platform, the company said on Saturday. Tropical Storm Beta was predicted to bring 1 foot (30 centimetres) of rain to parts of coastal Texas and Louisiana as the 23rd named storm of this year's Atlantic hurricane season moves ashore on Monday night, the National Hurricane Center said. Oil and gas producers had been restarting their offshore operations over the weekend after being disrupted by Sally. Some 17% of U.S. Gulf of Mexico offshore oil production and nearly 13% of natural gas output went offline on Saturday in the face of Hurricane Sally's waves and winds. Elsewhere, Libya's National Oil Corp lifted force majeure on what it deemed secure oil ports and facilities on Saturday, but said the measure would remain in place for facilities where fighters remain. "The market can ill afford more crude hitting the market," ANZ analysts said in a note on Monday. A resurgence of virus cases globally is also acting as a brake on crude demand. More than 30.78 million people have been reported to be infected by the novel coronavirus globally and 954,843? have died, according to a Reuters tally. "It is hard to get excited about a pickup in crude demand as the virus is surging in France, Spain, and the UK, along with concerns the U.S. appears poised for at least one more cycle in the fall and winter," said Edward Moya, senior market analyst at OANDA. "Even if energy markets don't see Libyan production return or if Hurricane season eases, oil prices can't shake off the dwindling demand outlook."

Oil Prices Fall Amid Broad Selloff  -- Oil declined the most in almost two weeks as U.S. equities slid on mounting worries over prolonged coronavirus restrictions, while the prospect of Libya resuming exports added to supply concerns. Crude futures in New York fell 4.4%. At the same time, the S&P 500 slumped to the lowest intraday level since July. Libya is moving closer to reopening its battered oil industry after it told companies to resume production at some fields that are free of foreign mercenaries and fighters. This will add to already rising supply from OPEC+ nations. There was a “dramatic selloff in equity markets and other commodity markets, and petroleum markets took part in it,” said Andrew Lebow, senior partner at Commodity Research Group. U.S. benchmark prices jumped 10% last week after Saudi Arabia, the most influential member of the Organization of Petroleum Exporting Countries, sought to defend the market. But a troubling demand picture continues to weigh on the market. China National Petroleum Corp. -- the country’s biggest oil company -- see demand for refined petroleum products peaking around 2025. BP Plc last week became the first supermajor to call the end of the era of oil-demand growth. As U.S. deaths related to Covid-19 approached 200,000, former Food and Drug Administration Commissioner Scott Gottlieb said he expects the nation to experience “at least one more cycle” of the virus in the fall and winter. “There are legitimate demand concerns,” said Peter McNally, global head for industrials, materials and energy at Third Bridge. “If we go into another lockdown, we are going to see inventories build.” Meanwhile, the U.S. Gulf Coast is preparing for another storm, with companies shutting production or evacuating staff at some platforms and the Houston Ship Channel closing due to Tropical Storm Beta. The storm has unleashed flooding on southeastern Texas and will hammer the Gulf Coast into eastern Louisiana with heavy rain, even as the storm loses power on its approach to shore. West Texas Intermediate for October fell $1.80 to settle at $39.31 a barrel. Brent for November dropped $1.71 to end the session at $41.44 a barrel. The plunge was the steepest daily loss since Sept. 8. Libya’s National Oil Corp. is ending force majeure -- a legal status protecting a party that can’t fulfill a contract for reasons beyond its control -- at “secure” facilities in the conflict-ridden nation and has told companies to resume production. The country’s overall oil production is set to reach 310,000 barrels a day in a few days from the current 90,000 a day, according to a person with direct knowledge of the situation.

Oil rises as U.S. storm eases, but demand worries linger - Oil rose in early trade on Tuesday, paring sharp overnight losses, as the latest tropical storm in the Gulf of Mexico lost strength, but worries about fuel demand persisted with flare-ups around the globe in coronavirus cases. Brent crude futures rose 27 cents, or 0.65%, to $41.71 a barrel. U.S. West Texas Intermediate crude futures for October, due to expire on Tuesday, rose 15 cents, or 0.38%, to $39.46 a barrel. The more active November contract rose 13 cents, or 0.3%, to $39.67. Crude prices, which fell about 4% on Monday, steadied as Texas refineries stayed open despite forecasts of heavy flooding, with Tropical Storm Beta expected to keep losing strength, allaying worries about U.S. refinery demand for feedstock. "The recovery in sentiment after the rout in risk assets seen a fortnight ago was clearly fragile," "This week, the market is recalibrating to a likely stalling of the economic recovery in Europe as several countries in the region impose fresh restrictions to contain a surge in the coronavirus." Monday's price slump was spurred by concerns that an increase in coronavirus cases in major markets could lead to fresh lockdowns and hurt demand. That raised the possibility that Libyan oil could return when it isn't needed. "We had a pretty punchy risk-off session (overnight) ... on fears around the risk that a COVID resurgence starts to have negative impacts on demand again," Markets are nervous about demand in places like the United Kingdom, where fresh restrictions are being imposed. U.S. health officials are also warning of a new wave in the coming winter. "When the virus resurges, governments lock down, impose restrictions, and individuals and businesses start to retreat. It's all bad for demand," Traders will be watching out for the American Petroleum Institute's data on U.S. oil inventories due later on Tuesday. U.S. crude oil and gasoline stockpiles likely fell last week, while inventories of distillates, including diesel, were seen climbing, a preliminary Reuters poll showed.

WTI oil futures climb, but hold below $40 a barrel – Oil settled higher on Tuesday, finding support from expectations for a second weekly decline in U.S. crude supplies. Prices scored a partial rebound from the sharp decline in oil seen a day earlier, when the rise of COVID-19 cases and potential for renewed activity restrictions in Europe fed a global equity selloff reported MarketWatch. Tuesday’s oil-price rise was modest. Energy traders struggled “to assess the uncertainty with U.S. production as we approach the last two months of hurricane season [and] how bad the demand outlook will get following the winter wave of the coronavirus,” as Libyan oil production slowly bounces back, said Edward Moya, senior market analyst at Oanda. West Texas Intermediate crude for October delivery on the New York Mercantile Exchange edged up by 29 cents, or 0.7%, to settle at $39.60 a barrel after a decline of 4.3% on Monday. The contract expired at the day’s settlement. The November WTI contract , which is now the front month, settled at $39.80, up 26 cents, or 0.7%. Global benchmark November Brent crude, meanwhile, rose 28 cents, or 0.7%, at $41.72 a barrel on ICE Futures Europe.

WTI Extends Gains After Official Inventory Data Shows Big Draws - Oil prices have chopped around overnight, rallying hard as Europe opened after weakness following last night's surprise crude build reported by API.  “The API was positive I’d say, with draws in gasoline and distillates” . “A large drawdown in the fourth quarter or not is the big question.”  Additionally, as Bloomberg reports, in the near term, the demand outlook looks troubled. In Europe, the profit from turning crude into diesel slipped toward $2 a barrel earlier, a record low in data going back to 2011. That curbs demand for crude from refineries. The head of Russia’s Gazprom Neft PJSC said that the recovery in global oil consumption has indeed slowed down.  DOE:

• Crude -1.64mm (-4.0mm exp)
• Cushing +4k
• Gasoline -4.03mm (-1.9mm exp)
• Distillates -3.364mm (+1.2mm exp) - biggest draw since March 2020

Dramatic draws in crude, gasoline, and distillates... This is the 7th weekly draw in gasoline in a row and biggest distillates draw since March. Between Hurricanes and Tropical Depressions, there is still some lingering noise in the production data, which showed a small drop in the last week... Graphs Source: Bloomberg. WTI hovered around $40 ahead of the official inventory data and extended gains on the draws...

Oil posts slight gain as U.S. inventory declines - Oil rose more than 1% on Wednesday, supported by U.S. government data that showed crude and fuel inventories dropped last week, although concerns about the ongoing coronavirus pandemic capped gains. Brent crude rose 53 cents, or 1.3%, to $42.25 a barrel. U.S. West Texas Intermediate crude settled 13 cents, or 0.3%, higher at $39.93 per barrel. U.S. crude, gasoline and distillate inventories all fell last week, Energy Information Administration data showed. Crude inventories fell by 1.6 million barrels, less than forecast; gasoline stocks dropped more than expected, sliding by 4 million barrels; while distillate stockpiles posted a surprise drawdown of 3.4 million barrels. "The distillate overhang that we've seen most of this year has been a primary bearish consideration to the energy complex and as that begins to adjust lower that can be viewed as supportive," said Tony Headrick, energy markets analyst at CHS Hedging. Elsewhere, better-than-expected German manufacturing data lifted some risk appetite on Wednesday. But COVID-19 infections in countries including India, France and Spain and new restrictions in Britain have renewed worries about demand, just as more supply may come from Libya. In the United States, the death toll has passed 200,000. Oil collapsed as the pandemic decimated demand, with Brent falling below $16, a 21-year low, in April. A record output cut by the Organization of the Petroleum Exporting Countries and allies, known as OPEC+, has helped revive prices. OPEC faces a new challenge in that Libya, an OPEC member exempt from the supply cut, is aiming to boost supply after an easing of the country's conflict. An oil tanker is expected to load crude at Libya's Marsa el-Hariga terminal this week, the first since January. 

Oil falls as demand growth concerns outweigh U.S. stock drawdown - Oil prices dropped on Thursday, weighed down by concerns that U.S. economic recovery is slowing as the coronavirus outbreak lingers, while a renewed wave of COVID-19 cases in Europe have led to reimposed travel restrictions in several countries. The jitters over demand and economic outlook due to the coronavirus resurgence have prompted a rally in the dollar as investors turned to safer assets, adding pressure to oil prices. A stronger dollar makes oil, priced in U.S. dollars, less attractive to global buyers. U.S. West Texas Intermediate (WTI) crude futures fell 60 cents, or 1.5%, to $39.33 a barrel at 0445 GMT, while Brent crude futures dropped 47 cents, or 1.1%, to $41.30 a barrel. Both benchmarks climbed slightly on Wednesday after government data showed U.S. crude and fuel stockpiles dropped last week. Gasoline inventories fell more than expected, sliding by 4 million barrels, and distillate stockpiles posted a surprise drawdown of 3.4 million barrels. Still, fuel demand in the U.S. remains subdued as the pandemic limits travel. The four-week average of gasoline demand was 8.5 million barrels per day (bpd) last week, the government data showed, down 9% from a year earlier. Prices turned down after data showed U.S. business activity slowed in September, U.S. Federal Reserve officials flagged concerns about a stalling recovery, and Britain and Germany imposed restrictions to stem new coronavirus infections -- all factors affecting the fuel demand outlook. "Oil prices are wilting as product for immediate delivery remains plentiful," "Consumption outlook concerns are rising as COVID-19 restrictions return in Europe, and the clamour from the Federal Reserve for more U.S. fiscal stimulus, undermines the global recovery case, the lynchpin for oil's price recovery." On the supply side, the market remains wary of a resumption of exports from Libya, although it is unclear how quickly it can ramp up volumes. Libya's National Oil Corp (NOC) seeks to boost output to 260,000 bpd by next week. "That clearly is going to be something the oil market doesn't need right now,"

Oil prices end higher, buoyed by signs of tighter supplies -  Oil futures finished higher on Thursday, supported by signs of tighter U.S. crude supplies, despite persistent concerns that rising cases of COVID-19 will lead to weaker energy demand. The commodity tallied a third climb in a row, but the gains have been modest and prices still remain lower for the week. “Oil prices need a shot of something,” The U.S. Federal Reserve “wants it to be another shot of stimulus and perhaps a shot of a coronavirus vaccine,” he said. “Perhaps it’s another shot of compliance by the OPEC plus cartel, or maybe it just needs to get past September where hurricanes and storms impacted both supply and demand.” West Texas Intermediate crude for November delivery edged up by 38 cents, or nearly 1%, to settle at $40.31 a barrel on the New York Mercantile Exchange after tapping a low at $39.12. November Brent crude, the global benchmark, added 17 cents, or 0.4%, to trade at $41.94 a barrel on ICE Futures Europe. “Lifeless crude prices and frightful refining margins present a faltering demand recovery, especially with COVID cases rising again. But fortunately, OPEC’s supply constraint and a further fall in U.S. supply in 4Q and 2021 will provide the offset,” Oil rose Wednesday after the Energy Information Administration reported that U.S. crude inventories fell for a second straight week, by 1.6 million barrels for the week ended Sept. 18. That was much less than the average forecast from analysts polled by S&P Global Platts for a decline of 4 million barrels, but the American Petroleum Institute on Tuesday had reported an increase of 691,000 barrels. Also, gasoline inventories fell by a larger-than-expected 4 million barrels, while distillate stocks unexpectedly declined by 3.4 million barrels. On Thursday, October gasoline rose 1.2% to finish at $1.1957 a gallon, while October heating oil settled at $1.1167 a gallon, up 0.8% “The continued drop in U.S. oil supply and refinery challenges suggests a balancing of supply,” “It also indicates that we should see oil bottom and rally as we head into winter and out of the [refinery] maintenance season.” Also, “despite gridlock in Washington, oil demand should recover, and we face a balanced market globally that will add higher prices,” he said, though “the risk to this forecast is a massive” COVID-related shutdown.

Oil gains but heading for weekly fall over coronavirus demand concerns - Oil prices fell on Friday and were set for a weekly decline due to mounting worries about the impact on fuel demand of a widespread resurgence in coronavirus infections, as well as some concern about the likely return of exports from Libya. Brent crude was down 23 cents at $41.71 a barrel, while West Texas Intermediate crude fell 38 cents to $39.91. Brent is heading for a drop of more than 3% this week with U.S. crude on track for a decline of nearly 3%. Both benchmarks are also heading for a monthly decline, which would be the first for Brent in six months. "This month has not been kind to the oil market," "Rising virus infections, renewed lockdowns, slowing economic recovery and stalled U.S. stimulus talks have put the brakes on the fragile revival in fuel demand." In the United States, which has the highest death toll from the coronavirus pandemic and is the world's biggest oil consumer, unemployment claims unexpectedly rose last week suggesting an economic recovery is flailing and pushing down fuel demand. U.S. fuel demand remains in the doldrums as the pandemic constrains travel. The four-week average of gasoline demand last week was 9% below a year earlier, government data showed on Wednesday. In other parts of the world, daily increases of coronavirus infections are hitting records and new restrictions are being put in place that will likely limit travel and fuel demand. In India, throughput by crude oil refiners in August fell 26.4% from a year ago, the most in four months, as fuel demand ebbed because surging coronavirus cases hindered industrial and transport activity. In Libya, Shell has provisionally booked a tanker to load a crude cargo at Libya's Zueitina terminal on Oct. 3, potentially the first since January at the recently reopened port. However, analysts have questioned how quickly the country could ramp up supply. "Fundamentally, nothing has changed to the supply side of the equation that is weighing on oil prices in the bigger picture,"

Oil falls on mounting COVID-19 cases, supply concerns (Reuters) - Oil edged lower on Friday, falling more than 2% on the week as COVID-19 cases surged globally and oil supply is set to rise in coming weeks. FILE PHOTO: the sun sets behind a crude oil pump jack on a drill pad in the Permian Basin in Loving County, Texas, U.S. November 24, 2019. Picture taken November 24, 2019. REUTERS/Angus Mordant/File Photo Brent crude futures LCOc1 settled at $41.92 a barrel, down 2 cents, while U.S. West Texas Intermediate (WTI) crude futures CLc1 lost 6 cents to $40.25 a barrel. Brent dropped 2.9% for the week and WTI sunk 2.1% “There is this second wave of fear overhanging the oil market at this point and that’s holding us back,”  In the world’s top oil consumer the United States, infections are rising in the Midwest, while New York City, which was hit hardest in the spring, is considering renewed shutdown mandates. More than 200,000 people have died of the virus in the nation. U.S. fuel consumption remains sluggish as the pandemic constrains travel and hampers economic recovery.. The four-week average of gasoline demand last week was 9% below a year earlier. In other parts of the world, daily increases of coronavirus infections are hitting records and new restrictions are being put in place to limit travel. In India, throughput by crude oil refiners in August fell 26% from a year ago, most in four months, as demand ebbed because the pandemic is hindering industrial and transport activity. At the same time, more crude oil entering the global market threatens to beef up supply and push prices lower. The U.S. oil and gas rig count rose by six to 261 in the week to Sept. 25, energy services firm Baker Hughes Co BKR.N said. [RIG/U] Libya has recently boosted production and Shell RDSa.L has provisionally booked the first crude tanker to load at Libya's Zueitina terminal since January. Iranian oil exports, meanwhile, have risen sharply in September in defiance of U.S. sanctions, three assessments based on tanker tracking showed.

Oil prices down for the week on new coronavirus concerns -Oil fell this week amid growing concerns that another wave of the coronavirus pandemic will spark tighter lockdown measures and further stifle crude demand. New York futures edged lower Friday and fell 2.1% on the week. The number of U.S. coronavirus cases rose above 7 million, according to data from Johns Hopkins University. Meanwhile, a second governor tested positive for Covid-19 as cases surge around the country. At the same time, the market is contending with returning supply. Oil traders have reported a sharp increase in Iraqi exports for next month, while output from Libya has shown signs of rising this week. “There are concerns about the stalling economic recovery,” said Phil Streible, chief market strategist at Blue Line Futures LLC in Chicago. When the world gets a vaccine, widespread reopenings and a meaningful increase in travel, “that’s when you’re going to start to see demand pick up” and prices rally. U.S. crude’s gradual climb since May has come to a halt in September, with futures on track to drop about 5.5% this month. Still, Goldman Sachs Group Inc. said oil consumption is currently just above 93 million barrels a day and may rise 1.8 million a day to the end of the year. Yet, any meaningful recovery in consumption has so far been held back by the lingering pandemic. “We’re going to be range-bound for a while until there’s the perception that the bulk of the Covid impact on demand is behind us,” said Michael Lynch, president of Strategic Energy & Economic Research. Additionally “if the OPEC+ deal starts to fall apart and we get a lot more crude, that would send prices down.” West Texas Intermediate for November delivery edged 6 cents lower to settle at $40.25 a barrel. Brent for November dipped 2 cents to end the session at $41.92 a barrel. The contract lost 2.9% this week. In a sign of just how damaging the virus has been to oil demand, the industry’s largest tankers next year will earn 8% less than they were anticipating back in May, according to a survey of shipping analysts by Bloomberg. That comes as nations including Saudi Arabia and Russia have drastically scaled back output, draining the hoard at sea and diminishing the flow of cargoes. The spread between Nymex gasoline futures and WTI rallied over 9% on Friday toward $10 a barrel. Still, the so-called crack remains at its lowest seasonally since 2013. At the same time, Gulf Coast gasoline climbed to a one-month high as refiners snapped up winter-grade fuel and on dwindling fall stockpiles.

The Debt Crisis Is Mounting For Oil Economies - Dubai. Abu Dhabi. Bahrain. And, of course, Saudi Arabia. The two emirates this year issued debt for the first time in years. So did Bahrain. Saudi Arabia stepped up its debt issuance. The moves are typical for the oil-dependent Gulf economies. When the going is good, the money flows. When oil prices crash, they issue debt to keep going until prices recover. This time, there is a problem. Nobody knows if prices will recover. In August, Abu Dhabi announced plans for what Bloomberg called the longest bond ever issued by a Gulf government. The 50-year debt stood at $5 billion, and its issuance was completed in early September. The bond was oversubscribed as proof of the wealthiest Emirate’s continued good reputation among investors.Dubai, another emirate, said it was preparing to issue debt for the first time since 2014 at the end of August. Despite the fact the UAE economy is relatively diversified when compared to other Gulf oil producers, it too suffered a hard blow from the latest oil price crash and needed to replenish its reserves urgently. Dubai raised $2 billion on international bond markets last week. Like Abu Dhabi’s bond, Dubai’s was oversubscribed.Oversubscription is certainly a good sign. It means investors trust that the issuer of the debt is solid. But can the Gulf economies remain solid by issuing bond after bond with oil prices set to recover a lot more slowly than previously expected? Or could this crisis be the final straw that tips them into actual reforms?No economy, especially not the ones dependent on a single export for most of its budget revenues, can rely on borrowing for long-term survival, let alone growth. In fact, the growth prospects of the Gulf economies are dimming, Reuters’ Davide Barbuscia wrote in a recent analysis of the region. Gulf governments are doing what they have always done: cut public spending and borrow. This time, however, the crisis is like no other before it, and these governments may find themselves in a tight spot while they wait for prices to bounce back. The problem is that public spending is the main growth driver in the Gulf economies, Barbuscia wrote, quoting the chief economist of Abu Dhabi Commercial Bank. If public spending falls, so will consumption and, therefore, growth. This is already happening and, what’s worse, it is happening across industries. Earlier this month, IHS Markit said, as quoted by Arabian Business, that non-oil private sector activity in Saudi Arabia and the UAE had fallen in August below 50—the figure that separates growth from contraction. That was after this indicator had registered improvement in the previous month despite still low oil prices. All Gulf economies—except Qatar—are expected to stay or swing into budget deficits this year, according to the International Monetary Fund. Saudi Arabia, the biggest economy in the region, is seen faring the best, with a deficit of 11.4 percent of GDP, and Oman faring the worst, with a deficit of 16.9 percent. Deficits happen. There is nothing extraordinary about them. What is extraordinary is the lack of wiggle room for the local governments. Investor interest in their new bonds may have been strong, but how likely would it be to remain strong for further debt issues if prices continue hovering around $40 a barrel? This is much below the Gulf economies’ breakeven levels, even the lowest ones. Saudi Arabia’s breakeven alone, according to the IMF, is $76.10 per barrel this year. It could fall to $66 next year, but this will still be too high for comfort with Goldman optimistically projecting Brent to hit $65 a barrel next year. In what is perhaps a cruel twist, this unprecedented situation is stifling the Gulf economies’ attempts to diversify their economies away from oil. This is incredibly obvious in Saudi Arabia, which had the ambitious goal of becoming a diversified economy by 2030. The goal, however, was to be financed with money from oil sales, and these collapsed this year as the pandemic spread globally.

US Sends M2A2 Bradleys To Challenge Russian Forces In Northern Syria - The US military has reinforced its troops, supposedly mostly withdrawn from Syria, with a new batch of military equipment, this time M2A2 Bradley infantry fighting vehicles. In an official comment released on September 18, the US-led coalition said that mechanized infantry assets, including Bradley IFVs, were positioned to Syria in order to “ensure the enduring defeat of ISIS”, “ensure the protection of Coalition forces” and “provide the rapid flexibility needed to protect critical petroleum resources”.The M2A2 Bradley is armed with a 25 mm chain gun, a 7.62 mm coaxial machine gun and a dual TOW anti-tank guided missile launcher. This makes the IFV the heaviest weapon deployed by the US on the ground in Syria.As of September 21, the newly deployed armoured vehicles were already spotted during a coalition patrol in al-Hasakah province, where the US has a network of fortified positions and military bases. US forces regularly conduct patrols in the area. Another area of US interest in Syria’s northeast are the Omar oil fields on the eastern bank of the Euphrates. Washington reinforced its troops deployed there with M2A2 Bradley IFVs in October 2019.The main difference is that, according to local sources, the vehicles deployed in al-Hasakah province will most likely be involved in patrols in the area and thus regular confrontations with the Russian Military Police and the Syrian Army. Just a few days ago, Russian attack helicopters chased US Apaches after they had tried to harass a Russian Military Police patrol. Earlier, the US military claimed that US troops sustained “mild injures”, when a Russian vehicle rammed a US MRAP in the al-Hasakah countryside.The US-led coalition regularly tries to limit the freedom of movement of Russian and Syrian forces in the northeast of the country and faces an asymmetric response. Now, US forces will have an additional argument in securing what they see as their sphere of influence.Syrian government forces have suffered even more casualties from ISIS attacks in the provinces of Homs and Deir Ezzor. On September 19, at least five members of Liwa al-Quds, a pro-government Palestinian militia, died in an explosion of an improvised explosive device near the town of al-Shumaytiyah. On September 20, an explosion hit a vehicle of the Syrian Army near al-Mayadin reportedly injuring several soldiers. Also, a field commander of the National Defense Forces was killed in clashes with ISIS terrorists west of Deir Ezzor.