oil prices saw their greatest drop in 10 months this week, as US crude inventories rose unexpectedly and rising Covid cases prompted economic restrictions worldwide.... after rising 2.6% to $73.95 a barrel last week as crude, gasoline, and distillates supplies all fell more than had been expected, the contract price of US light sweet crude for September delivery fell early on Monday after a Chinese survey showed that growth in factory activity slipped sharply in the world's largest oil importer, and continued to tumble more than 4% before recovering to settle $2.69 lower at $71.26 a barrel, as the fast-spreading delta variant posed a threat to demand and as higher crude output from OPEC producers stoked fears of oversupply…oil prices were down another 3% early Tuesday as the resurgence in Covid cases globally driven by the Delta variant fuelled concerns that restrictions on economic activity might be reimposed, but recovered from the worst levels after news of a “potential hijack” of a tanker in the Gulf of Oman to close down 70 cents or less than 1% lower at $ $70.56 a barrel, after sources said preliminary data suggested US crude stocks were lower for the week....however, oil prices dipped again after the API reported a disappointingly small crude inventory draw and then extended those losses after the EIA reported an unexpected crude inventory increase, and ultimately fell $2.41 or again more than 3% to $68.15 a barrel, as the spread of the coronavirus Delta variant outweighed the impact of new Mideast geopolitical tensions....oil prices were up Thursday morning in Asia, even as traders were surprised by the build in U.S. crude oil supply, as prices were still supported by ongoing tensions in the Middle East and then moved higher in New York trading, rising on the tailwind of strong equity markets to break the three day losing streak and close 94 cents higher at $69.09 a barrel, while gains were capped as fresh restrictions to counter a surge in COVID-19 cases threatened the global energy demand recovery....prices continued to rise early Friday and were up more than 1% early on, gaining support from rising tensions between Israel and Iran, but reversed by the same percentage to settle Friday’s trade down 81 cents, or 1.2%, at $68.28 per barrel, tumbling as the dollar jumped on a strong U.S. jobs report, raising questions about the continuance of the Fed stimulus that had underpinned the markets and the economy...with that, oil prices ended the week 7.7% lower, capping the biggest weekly loss since October, as the spread of the delta coronavirus variant in China and elsewhere in the world cast doubts on demand growth...
natural gas prices, on the other hand, rose on forecasts for hotter weather and on low supplies for this time of year....after falling 3.2% to $3.914 per mmBTU last week on signs that the long heat wave was finally breaking, the contract price of natural gas for September delivery rose 2.1 cents to $3.935 per mmBTU on Monday as forecasts predicted hotter weather and greater demand for cooling over the coming weeks than had been previously expected...a drop in production drove natural gas prices higher for a second day on Tuesday, with gains accelerating after the latest weather models turned even hotter for next week, as September gas settled 9.2 cents higher at $4.027 per mmBTU...natural gas prices then climbed over 3% to a 31-month high on Wednesday, rising 13.1 cents to $4.158 per mmBTU, as traders anticipated what was forecast to be the smallest addition to inventories of the summer...however, natural gas prices retreated 1.8 cents to $4.140 per mmBTU on Thursday, even though the government storage data was about as bullish as it could be, as weather models showed the upcoming heat would be a little less intense...although prices remained volatile on Friday, they finished unchanged at $4.140 per mmBTU as growing supply concerns offset a slightly cooler shift in the latest weather forecasts, but still ended 5.8% higher on the week...
the natural gas storage report from the EIA for the week ending July 30th indicated that the amount of natural gas held in underground storage in the US rose by 13 billion cubic feet to 2,727 billion cubic feet by the end of the week, which left our gas supplies 542 billion cubic feet, or 16.6% below the 3,269 billion cubic feet that were in storage on July 30th of last year, and 185 billion cubic feet, or 6.4% below the five-year average of 2,912 billion cubic feet of natural gas that have been in storage as of the 30th of July in recent years...the 13 billion cubic feet increase in US natural gas in storage this week was 4 billion cubic feet below the median forecast for a 17 billion cubic foot addition from a S&P Global Platts survey of analysts, and less than half of the average addition of 32 billion cubic feet of natural gas that have typically been injected into natural gas storage during the same week over the past 5 years, and also less than half of the 32 billion cubic feet that were added to natural gas storage during the corresponding week of 2020…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending July 30th indicated that after a sizable decrease in our oil exports and a modest decrease in our oil production, we had surplus oil to add to our stored commercial crude supplies for the second time in eleven weeks, and for the 13th time in the past thirty-eight weeks….our imports of crude oil fell by an average of 75,000 barrels per day to an average of 6,432,000 barrels per day, after fallng by an average of 590,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 585,000 barrels per day to an average of 1,904,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 4,528,000 barrels of per day during the week ending July 30th, 510,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was reportedly unchanged at 11,200,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to total an average of 15,728,000 barrels per day during this reporting week…
meanwhile, US oil refineries reported they were processing 15,920,000 barrels of crude per day during the week ending July 30th, 46,000 more 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 net average of 518,000 barrels of oil per day were being added to the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports and from oilfield production was 711,000 barrels per day less than what was added to storage plus what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a (+711,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed….since last week’s EIA fudge factor was at (+73,000) barrels per day, that means there was a 638,000 barrel per day balance sheet difference in the crude oil fudge figure from a week ago, thus rendering the week over week supply and demand changes indicated by this report pretty useless….however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as they’re published, just as they’re watched & believed to be reasonably accurate by most everyone in the industry….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,564,000 barrels per day last week, which was 15.8% more than the 5,666,000 barrel per day average that we were importing over the same four-week period last year…the 518,000 barrel per day net increase in our crude inventories was all added to our commercially available stocks of crude oil, while the quantity of oil stored in our Strategic Petroleum Reserve remained unchanged….this week’s crude oil production was reported to be unchanged at 11,200,000 barrels per day because the EIA"s rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day lower at 10.800,000 barrels per day, while a 29,000 barrel per day increase in Alaska’s oil production to 342,000 barrels per day caused 100,000 barrels per day to be added to the rounded national production total (that's the EIA's math, not mine)….US crude oil production had hit a pre-pandemic record high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 14.5% below that of our production peak, but 32.9% above the interim low of 8,428,000 barrels per day that US oil production had fallen to during the last week of June of 2016…
meanwhile, US oil refineries were operating at 91.3% of their capacity while using those 15,920,000 barrels of crude per day during the week ending July 30th, up from 91.1% of capacity the prior week, but still somewhat below normal for summertime operations…while the 15,920,000 barrels per day of oil that were refined this week were 8.8% higher than the 14,637,000 barrels of crude that were being processed daily during the pandemic impacted week ending July 31st of last year, they were still 10.4% below the 17,777,000 barrels of crude that were being processed daily during the week ending August 2nd, 2019, when US refineries were operating at what was then a seasonally normal 96.4% of capacity…
with this week’s increase in the amount of oil being refined, the gasoline output from our refineries was also higher, increasing by 372,000 barrels per day to 10,151,000 barrels per day during the week ending July 30th, after our gasoline output had increased by 649,000 barrels per day over the prior week…while this week’s gasoline production was 9.2% higher than the 9,300,000 barrels of gasoline that were being produced daily over the same week of last year, it was still 2.6% lower than the gasoline production of 10,421,000 barrels per day during the week ending August 2nd, 2019….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 138,000 barrels per day to 4,877,000 barrels per day, after our distillates output had decreased by 163,000 barrels per day over the prior week…but after 5 straight decreases before that increase, this week’s distillates output was 0.7% less than the 4,909,000 barrels of distillates that were being produced daily during the week ending July 31st, 2020, and 7.7% below the 5,286,000 barrels of distillates that were being produced daily during the week ending August 2nd, 2019..
even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the seventh time in eighteen weeks, and for the 17th time in thirty-eight weeks, falling by 5,291,000 barrels to a nine month low of 228,870,000 barrels during the week ending July 30th, after our gasoline inventories had decreased by 2,253,000 barrels over the prior week...our gasoline supplies decreased by more this week because the amount of gasoline supplied to US users increased by 450,000 barrels per day to 9,775,000 barrels per day, and because our imports of gasoline fell by 64,000 barrels per day to 845,000 barrels per day while our exports of gasoline fell by 93,000 barrels per day to 716,000 barrels per day…after this week’s inventory decrease, our gasoline supplies were 7.6% lower than last July 31st's gasoline inventories of 247,806,000 barrels, and about 3% below the five year average of our gasoline supplies for this time of the year…
meanwhile, with the increase in our distillates production, our supplies of distillate fuels increased for the sixth time in seventeen weeks and for the 18th time in 33 weeks, risng by 832,000 barrels to 138,744,000 barrels during the week ending July 30th, after our distillates supplies had decreased by 3,088,000 barrels during the prior week….our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 738,000 barrels per day to 3,618,000 barrels per day, even while our exports of distillates rose by 290,000 barrels per day to 1,302,000 barrels per day, and while our imports of distillates fell by 26,000 barrels per day to 162,000 barrels per day…but after eleven inventory decreases over the past seventeen weeks, our distillate supplies at the end of the week were still 22.9% below the 179,977,000 barrels of distillates that we had in storage on July 31st, 2020, and about 6% below the five year average of distillates stocks for this time of the year…
finally, with the big decrease in our oil exports, our commercial supplies of crude oil in storage rose for tenth time in the past twenty-four weeks and for the 25th time in the past year, increasing by 3,627,000 barrels over the week, from 435,598,000 barrels on July 23rd to 439,225,000 barrels on July 30th, after our commercial crude supplies had decreased by 4,089,000 barrels the prior week….after this week’s increase, our commercial crude oil inventories were still about 6% below the most recent five-year average of crude oil supplies for this time of year, but were 30.2% above the average of our crude oil stocks as of the end of July over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories had jumped to record highs during the Covid lockdowns of last spring and remained elevated thereafter, our commercial crude oil supplies as of this July 30th were still 15.3% less than the 518,596,000 barrels of oil we had in commercial storage on July 31st of 2020, but are now a bit more than the 438,930,000 barrels of oil that we had in storage on August 2nd of 2019, and 7.8% more than the 407,389,000 barrels of oil we had in commercial storage on August 3rd of 2018…
This Week's Rig Count
The number of drilling rigs active in the US increased for the 39th time out of the past 46 weeks during the week ending August 6th, but was still down by 38.1% from the pre-pandemic rig count….Baker Hughes reported that the total count of rotary rigs running in the US increased by three to 491 rigs this past week, which was also up by 244 rigs from the pandemic hit 247 rigs that were in use as of the August 7th report of 2020, but was still 1,438 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, a week before OPEC began to flood the global oil market in an attempt to put US shale out of business….
The number of rigs drilling for oil was up by 2 to 385 oil rigs this week, after falling by 2 oil rigs the prior week, and it’s now 211 more oil rigs than were running a year ago, while it’s less than a quarter 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 was unchanged at 103 natural gas rigs, which was still up by 34 natural gas rigs from the 69 natural gas rigs that were drilling during the same week a year ago, but still just 6.4% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….in addition to oil and gas rigs, a horizontal rig that Baker Hughes classifies as "miscellaneous' began drilling in Kern county California, the site of 3 oil wells, this week...that's the first "miscellaneous' rig deployment since May 14th, while a year ago there were no such "miscellaneous' rigs active...
The Gulf of Mexico rig count was unchanged at 14 rigs this week, with 13 of those rigs drilling for oil in Louisiana’s offshore waters and one drilling for oil offshore from Texas….that was still two more rigs than the 12 rigs that were drilling in the Gulf a year ago, when 9 Gulf rigs were drilling for oil offshore from Louisiana and three were deployed for oil in Texas waters….since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week’s national offshore rig totals are equal to the Gulf rig count… in addition to those rigs offshore, we continue to have a rig drilling through an inland body of water in Terrebonne Parish of southern Louisiana, whereas there were no such “inland waters” rigs running a year ago…
The count of active horizontal drilling rigs was up by 7 to 449 horizontal rigs this week, which was more than double the 211 horizontal rigs that were in use in the US on August 6th of last year, but was less than a third 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 27 directional rigs this week, but those were still up by 3 from the 24 directional rigs that were operating during the same week a year ago….in addition, the vertical rig count was also down by 2 to 15 vertical rigs this week, but those were also up by 3 from the 12 vertical rigs that were in use on August 7th of 2020….
The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of August 6th, the second column shows the change in the number of working rigs between last week’s count (July 30th) and this week’s (August 6th) count, the third column shows last week’s July 30th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 7th of August, 2020..
it's not obvious from those tables how 7 horizontal rigs could have been added this week, but the 3 rigs added in Wyoming might offer a clue...checking the North America Rotary Rig Count Pivot Table at Baker Hughes (xls) we find rigs drilling 15 oil wells and one natural gas well in the state, with just 3 vertical oil rigs and only 3 rigs in the Niobrara chalk...comparing that to the prior week, we find that 6 horizontal and single vertical rig that had been drilling in the Powder Rver basin in Converse county saw no change, but that there was a new horizontal oil well being drilled Sublette county, which would be in the Green River basin, that there was a horizontal rig added in the Niobrara chalk in Laramie county, and that there was also a shallow vertical oil rig start up in Natrona county, which would be in the Powder River basin....meanwhile, the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes shows that two rigs were pulled out of Texas Oil District 8, which is the core Permian Delaware, but that two oil rigs were added in Texas Oil District 8A, which encompasses the northern counties of the Permian Midland, while another oil rig was being pulled out from Texas Oil District 7B, which includes a far eastern county of the Permian Midland...hence,Texas saw a one rig decrease in the Permian this week, and since the national Permian count was unchanged, that means that the rig that was added in New Mexico must have been set up to drill in the far west reaches of the Permian Delaware in that state...elsewhere in Texas, was no change in the rig deployment in Texas Oil District 10, that means that the rig that was added in the Granite Wash basin almost had to have been added in nearby Oklahoma...note that all that activity we've just noted represents oil well drilling; there were no changes among natural gas rigs this week...
+++++++++++++++++++++++++++++++++++++++
Radioactive, for 1600 years -— It might be that it's just not something people want to think about. But the fact is radioactive waste from fracking getting shipped to loosely regulated landfills in Ohio has the potential to poison the environment for 1,600 years. Despite efforts from environmental organizations to educate the public about the radioactive risks created by the boom in shale gas fracking since the early 2000s, some Ohioans remain unaware that it is piling up, in many cases, in their own backyards. Sil Caggiano, senior battalion chief for the Youngstown Fire Department, blames the lack of awareness on the state’s protection of the industry. “It's the third rail of politics here in Ohio,” Caggiano said. “You don't screw with the fracking.” Caggiano contends his fellow first responders and civilians are not being given the knowledge owed to them by the Emergency Planning and Community Right-to-Know Act, also known as SARA Title III. The act requires that states “organize, analyze and disseminate information on hazardous chemicals to local governments and the public.” The lack of transparency, according to Caggiano, puts him and fellow first responders in danger. They have no way to navigate industry-related incidents, like spills and explosions, when they don’t know what to test for or what they might be getting exposed to during emergency calls. Cagginao is wary of the industry’s money and power to buy "experts" and politicians. When it comes to influencing public opinion, he thinks the industry is nearly impossible to compete with in a fair or responsible manner. “If you bring in some guy who tries to tell you that the radium in the brine tanks is no worse than the radioactive potassium of bananas, people believe it because some guy who got paid and has got a Ph.D. said it,” Caggiano said. Previous reporting from Public Herald has shown that health risks related to fracking waste exposure do in fact exist — it’s not bananas. The industry, though, with help from the state, has chosen to downplay or ignore risks to both workers in the fracking industry and locals who live near oil and gas sites, treatment plants and sewage systems. Radioactive elements, such as radium-226, emit alpha particles that can become airborne as dust, drift through the air or be blown about by the wind to be inhaled or ingested. Once inside the human body, an alpha particle’s explosive charge can shred DNA to pieces, causing mutations in genetic material that can potentially affect future generations and obliterate cellular structures, creating the possibility for the development of tumors that can lead to fatal cancers. Radium-226 is commonly found in oil and gas waste and equipment, especially in the Marcellus and Utica Shale regions of Ohio and Pennsylvania, and is known to cause cancer in humans. Research has found exposure to high levels of radium can cause malignant bone tumors, such as childhood bone cancer. .“Putting this radioactive material into municipal waste sites is a giant concern. That could be life-altering for a lot of people, people in the vicinity, people downwater of streams, all those things,” “This is a permanent reactor near your house, and it will always be a reactor because the waste got pooled together. And it will make as much radon and radium today as it will tomorrow and the next day and the next day and 30 years from now and 100 years from now and 500 years from now because the half life of this stuff is like, forever … So while it’s a naturally occurring material, when you concentrate it, you create a reactor.”
OSU study looks into impact pipeline installation has on crop yields -Preliminary results of an Ohio State University study show that pipeline installation on farmland negatively impacts crop yields. Researchers with the Ohio State University Extension Agronomics Crops Team collected soil and yield samples from 24 farms in seven counties that were impacted by natural gas pipeline installation in the last few years. They sampled the right-of-way over the pipeline and an adjacent, undisturbed area of the same field. Pipeline easements are typically 50 feet wide.They found corn grain yields decreased by an average of 23.8% in the pipeline installation area when compared with yields in the undisturbed area. Silage corn decreased an average of 28.8%; and soybean yield decreased an average of 7.4%. Soils within the right-of-way also had more rock fragments, lower soil moisture and a higher resistance to penetration, which indicates some amount of soil compaction. The results were similar to previous studies done on pipeline installation and crop yields.The farms were in Tuscarawas, Stark, Wayne, Medina, Lorain, Ashland and Wood counties. The Rover, Utopia and Nexus pipelines were targeted because they were each installed within the last three to four years.The team is collecting data again in the fall and looking for yield maps from other fields in Ohio where the Rover, Utopia or Nexus pipelines were installed.
Ohio Utica Shale Production 1Q21 – Northern Utica Oil Roars Back - Each quarter the Ohio Dept. of Natural Resources (ODNR) issues an update on Utica (and Marcellus) oil and natural gas production. ODNR no longer issues a summary press release as they once did, which means we don’t automatically notice when quarterly updates appear on their website. ODNR publishes a detailed spreadsheet of all active wells showing oil and gas production by well. We make a copy of that spreadsheet, enhance it to make it more usable, and link to it. We also do our own sorting to show you the top 25 shale gas wells and top 25 shale oil wells. An astute MDN reader inquired about the report for 1Q21, which is now available. We’ve created our own version of their report and have some exciting news to share about 1Q21 results. Oil is back, in a big way, in the northern Utica! First up is Ohio’s top producing gas wells. Note: 3,221,989 thousand cubic feet (Mcf) is roughly equivalent to 3.22 billion cubic feet (Bcf). table: Ohio’s Top 25 Producing Utica Shale Gas Wells for 1Q21 As promised, the good news about the northern Utica being back–at least for oil production. Seemingly out of nowhere, in 1Q21 wells drilled by PennEnergy Resources appeared and dominated the top 25 oil wells. And all of those wells are in Carroll County, OH–the northern Utica. When Aubrey McClendon (former CEO of Chesapeake Energy) “discovered” the Utica, he bought up leases in the northern part of the play, places like Carroll County. Ultimately the southern part of the Utica proved to have more prolific production. However, somehow PennEnergy has reopened the door to the northern part of the play. PennEnergy scored 14 of the top 25 wells in oil production for 1Q21–by far the most of any company. Kudos! We run the numbers and calculated each well’s production by a daily average so we can rank all of the wells that way. Bear in mind a well online for just a few days will have higher daily production than a well online for a full 90 days. Finally, below is a link to view the spreadsheet online for 1Q21 Ohio Utica Production. You can sort the data any which way you want, or download it as a CSV file and keep your own copy. Enjoy!
Equitrans Mulling Requests by ‘Several’ Shippers to Boost Appalachia Natural Gas Takeaway Equitrans Midstream Corp. is making headway to increase natural gas connectivity in the Appalachian Basin, with management evaluating shipper interest received during a recent open season. The binding open season was related to Equitrans’ transmission system. It would increase shipper access to downstream markets in the Midwest and Gulf Coast, primarily through existing delivery interconnects with interstate pipelines in Clarington, OH. Management is evaluating the shipper requests, “and there were several,” according to Equitrans COO Diana Charletta. Also under evaluation are the costs to complete the expansion and the project economics. “There is still some back and forth with those shippers as far as where they want to come from and where they want to go,” Charletta said Tuesday during the second quarter earnings call with investors. “So, we’re working through all of that right now with shippers, and we should have final results in the next couple of months.” Meanwhile, construction continues on the long-delayed Mountain Valley Pipeline (MVP). Charletta said crews have been working since the spring on all approved upland areas for MVP and are on track to complete work in the fall. Once the upland work is done, the remaining work would include about 10 miles related to water crossings and eight miles in areas in and around the Jefferson National Forest. A recent notice of schedule published by FERC indicates that the environmental assessment for MVP would be published by the middle of August. Charletta said the permitting timelines for the Federal Energy Regulatory Commission and the U,S. Army Corps of Engineers remain consistent with summer 2022 service. The total project cost estimate also remains around $6.2 billion.
Pipeline's plan to offset greenhouse gas emissions questioned by environmentalists - If natural gas begins to flow through the Mountain Valley Pipeline a year from now, as its developers expect, the operation will produce about 730,000 metric tons of greenhouse gases per year. Airborne emissions of carbon dioxide from three compressor stations along the 303-mile pipeline, along with methane expected to leak from the buried steel pipe, have long been a concern of opponents who say that delivering huge amounts of fossil fuel to markets will only worsen a climate change problem that is rapidly overheating the earth.On July 12, Mountain Valley announced a plan: The company will spend at least $150 million over the next 10 years on carbon offsets, which will be used to construct a massive methane abatement system at a coal mine in far Southwest Virginia.The mine is currently authorized by the federal government to release methane, generated by digging through rock formations, to prevent underground concentrations of the volatile gas from exploding and killing miners. A massive machine to be installed at the mine would convert the methane into water vapor and carbon dioxide before it is released into the air.Mountain Valley says the reduction of greenhouse gases will be roughly equivalent to what its pipeline will produce.The company will thus fight pollution from coal while meeting its goal of operating a carbon-neutral pipeline, said Diana Charletta, president and chief operations officer of Equitrans Midstream Corp., the lead partner in a joint venture building the controversial pipeline.The Sierra Club and Appalachian Voices, two organizations that have participated in legal challenges of the pipeline, called the $150 million plan a “green-washing” campaign to put a clean face on what is really a “pay-to-pollute” scheme.“Decision makers and the public should not be fooled: this offset scheme does nothing to change the fact that MVP is a dirty fossil fuel project that would pollute our communities and exacerbate the climate crisis,” Patrick Grenter, associate director of the Sierra Club’s Beyond Dirty Fuels Campaign, said in a statement released shortly after the July 12 announcement.
Chesapeake Energy’s future muddied by executive departures, strategy shifts (Reuters) - When U.S. oil and gas producer Chesapeake Energy emerged from bankruptcy in February, it touted to investors a clean balance sheet, a new board of directors and a promise to restrain spending.Since then, the company has endured a senior management shakeup and, according to two sources familiar with the matter, its interim CEO has told employees that the company is eyeing acquisitions that could help double its size.The mixed signals, say some investors, shed light on why Chesapeake's stock rise has lagged that of rivals. One problem is that no one is exactly sure of the company's real post-bankruptcy strategy.Chesapeake's stock has gained about 21% since the company emerged from bankruptcy. But shares of rivals Antero Resources Corp AR.N and Range Resources Corp RRC.N have climbed about 67% and 53%, respectively, in the same period. Natural gas prices, meanwhile, have soared about 43% to $4.06 per million British thermal units.Investor confidence in Chesapeake’s reboot began to flag in April after then-director Michael Wichterich unexpectedly fired CEO Doug Lawler, who had headed Chesapeake for eight years, and took over his position on an interim basis.Lawler had been widely credited with whittling away the company’s $13 billion debt load with a conservative approach to spending and had shepherded the company through bankruptcy. In a town hall meeting shortly after the firing, Wichterich told employees that he had a knack for deal-making and recited a litany of deals he had closed on over the course of his career, according to two sources who attended the meeting. He then told them Chesapeake needed to grow or it would become an acquisition target, according to the sources, who added he has mentioned doubling the size of the company. "That freaked a lot of people out,"
Brooklyn Judge Freezes Plan to Truck Frigid Liquid Natural Gas to Brooklyn -Environmental activists protesting changes to National Grid’s Greenpoint hub for more than a year are claiming a legal victory — but the utility is pushing back.Following a court order, National Grid last week stopped construction work at the Brooklyn site that could be used to load and unload trucks containing liquefied natural gas, or LNG.LNG is predominantly methane gas cooled to liquid state and kept at minus-260 degrees — nearly as frigid as Saturn. The process reduces the gas’ volume, making for easier transportation. But trucking the combustible gas within the city has raised concerns around environmental and safety risks.A state Supreme Court judge on July 27 ordered National Grid to temporarily halt construction that would support possible LNG trucking to its North Brooklyn site, which is also at the center of a controversial pipeline plan.The move came after the Sane Energy Project and Cooper Park Resident Council sued the city, the Fire Department and National Grid to stop the work. The suit alleges required approvals haven’t been obtained and that an environmental review of the impact of trucking-related activities hasn’t been completed.“Any moment they’re not moving forward with this is more of a chance we can stop it for good,” said Lee Ziesche, community engagement coordinator for the Sane Energy Project.But in a legal filing submitted Thursday, National Grid argued against the restraining order and suggested environmental groups are misunderstanding its plan for the Greenpoint site.The work, National Grid spokesperson Karen Young said, has been “undertaken in compliance with all applicable laws, rules and regulations.”National Grid proposed bringing LNG to its Greenpoint facility by truck from outside the city through The Bronx and Queens.In November 2016, following up on a previous application, the company asked the FDNY for a “transport variance” to do so, since trucking LNG is illegal within city limits, but the request has not yet been granted or denied.Brooklyn Supreme Court Justice Karen Rothenberg found that construction related to National Grid’s variance petition must stop until the case is decided.In a legal filing, the company indicated the variance petition was old and related to a project that never came to fruition. National Grid sent a letter to the city Law Department and Fire Department on Tuesday saying it wanted to formally withdraw its application.If in an emergency the company would want to truck in LNG, it would have to apply to the city for an “event-specific” variance, rather than a general one.The company was building the “fully and lawfully permitted” truck unloading station, according to the filing, in order to be prepared for such an emergency event. The construction was about half complete.
Henderson gas pipeline opponents want environmental study of project— Environmental advocates are asking federal regulators to slow down and take time to assess the environmental impact and greenhouse gas emissions of a proposed natural gas pipeline expansion in Henderson County, Kentucky.The interstate pipeline would serve two proposed natural gas combustion turbines CenterPoint Energy wants to build across the Ohio River in Posey County, Indiana.CenterPoint Energy is seeking to speed development of the pipeline as it approaches the October 2023 retirement of its coal-burning A.B. Brown power plant near Evansville.Texas Gas Transmission, LLC, is the Houston-based company that will build and operate the pipeline by expanding its existing pipeline infrastructure. However, Texas Gas needs approval from the Federal Energy Regulatory Commission before it can go ahead with the 24-mile pipeline extension through western Henderson County. The project also includes upgrades to Texas Gas facilities near Slaughters, Ky., in Webster County, and in Johnson County, Indiana.Texas Gas has asked federal regulators to say the project won't need an environmental impact statement because it "will cause a substantial net reduction" in greenhouse gas emissions.Those reductions would come both from Texas Gas' own upgrades as well as from CenterPoint's move to more renewable energy sources, including closing A.B. Brown.The expansion will be from near the Henderson-Webster county line northwest and then north across the Ohio River to Posey County to the A.B. Brown power plant near Evansville.Both the Citizens Action Coalition of Indiana, a consumer advocacy organization, and the environmental group Sierra Club have filed written protests. Citizens Action Coalition also is seeking a public hearing.CenterPoint has stated the natural gas turbines are important to help it transition from mostly coal-fueled power generation to a mix dominated by renewable energy sources while making sure it can reliably supply power at times renewable energy lags.In a 10-page filing to support the pipeline, Jason Stephenson, a CenterPoint vice president and general counsel, wrote that transitioning to renewable energy will be cheaper for customers than continuing to upgrade and operate the coal-burning power plant if the utility can make the transition quickly.
Letter: New pipelines? No thank you - The temperature in Portland, Oregon, a city that is further north than Toronto, Canada, recently hit 116 degrees Fahrenheit. Ice sheets are melting in line with the worst-case scenarios set out by the Intergovernmental Panel on Climate Change. Now is not the time to build new gas pipelines and plants. Texas Gas filed with FERC to build a new gas pipeline under the Ohio River to the CenterPoint A.B. Brown Plant. They are asking to build without doing the usual Environmental Impact Study. CenterPoint is asking the IURC to build two gas plants that are projected to run only 4-7% of the time. They claim these plants are needed to support renewable energy sources as needed. This is misleading. Battery storage can smooth the intermittency of renewables. Energy efficiency can reduce peak load much more cheaply than new gas plants. CenterPoint’s anemic distributed energy resource and demand managements programs show they haven’t really applied much effort at meeting demand except by building new plants on our dime. Neither the new pipeline under our drinking source nor the gas plants are needed or wanted. The U.S. Energy Information Administration (EIA) expects to see huge increases in battery storage deployments – from 1,600 MW installed in 2020 to 10,700 MW by 2023. That’s the technology we deserve. CenterPoint would have us pay for gas plants and pipelines then almost immediately turn around and say – oops – NOW we need to replace these with battery storage like everyone else. Let’s not be stupid. Get it right the first time.
Hoosiers Concerned About ‘Pipeline to Nowhere’ That Could Be Built Under Ohio River -A Kentucky-based company is seeking approval from federal authorities to build a natural gas pipeline under the Ohio River to bring out-of-state fuel to non-existent power plants.Hoosiers and advocacy groups are concerned about the pipeline’s environmental effects and whether its approval could set back a transition to clean energy.Texas Gas Transmission LLC is project asking the Federal Energy Regulatory Commission for approval to build a 24-mile pipeline extension to connect two centerpointpetition proposed natural gas-fired power plants at CenterPoint Energy Inc.’s A.B. Brown Generating Station in Posey County to a network of interstate natural gas pipelines. The company is asking FERC to approve the project, which would extend from Robards, Kentucky to Evansville, Indiana via an underwater crossing under the Ohio River, without performing an environmental impact statement.Texas Gas said the project would facilitate a substantial net reduction in overall greenhouse gas emissions, the heat-trapping gases responsible for man-made climate change.“FERC should determine that an environmental impact statement is not necessary to evaluate whether the Project will result in adverse climate change impacts because the Project will cause a substantial net reduction in methane, NOx, and carbon monoxide emissions resulting from the retirement and transitioning to standby of existing reciprocating compressor units on Texas Gas’ system and a reduction of indirect, downstream GHG emissions from the replacement of coal-fired generating facilities at CenterPoint’s AB Brown Plant with new-gas fired turbines and renewable resources,” Texas Gas wrote in its application to FERC.The company’s assertion is based on the assumption that the Indiana Utility Regulatory Commission will approve CenterPoint Energy’s petition to build the two natural gas combustion turbines the pipeline would eventually fuel.
Nelson County Activists Say Atlantic Coast Pipeline Should Rescind "Zombie Easements" | WVTF - It’s been just over a year since Dominion and its utility partners announced they were scrapping plans for a pipeline to carry natural gas from the fracking fields of West Virginia through Virginia to North Carolina. Opponents were thrilled, but some say their fight isn’t over yet. In 2012, David and Nancy Schwiesow retired from jobs in Washington D.C. to a small community in the Blue Ridge. They built their dream house near Wintergreen – 5,000 square feet with a spectacular view of three mountain ridges. But one year after moving in, David got a call from a real estate agent. “The realtor said, ‘Dominion has just rerouted the pipeline past the entrance to Wintergreen, up through your neighborhood.’ And I said, ‘You’ve got to be kidding.’” As a corporate lawyer, he knew something about government, power and politics. “In Nelson County, Wintergreen is by far the most valuable set of properties," he explains. "The people here tend to be more politically connected than other people, so we thought there was no chance they’ll do that.” But it was soon apparent that backers of the Atlantic Coast Pipeline or ACP intended to clear a 600-mile path 125 feet wide. David Schwiesow stands on his front porch, shaking his head at the memory. Armed with approval from the Federal Energy Regulatory Commission – FERC – the pipeline was able to take land from owners, even before agreeing on a price. Megan Gibson is a senior staff attorney with the Niskanen Center – a Washington-based think tank that has helped landowners across the country to fight pipelines. “They say to the court, ‘This is an emergency. We need to begin construction or tree felling or trench digging or whatever excuse that they’re giving to the court immediately, or we are going to lose thousands of dollars, and all of these terrible things are going to happen," she says. "The court more often than not grants immediate possession to the pipeline company without having to pay the land owner a dime!” Owners could no longer build on that part of their property nor could they plant trees, although Schwiesow’s neighbors were assured they would have some control. “After we build the pipeline, you can select the grass seed to go across the easement,” Schwiesow says they were told. So with the help of the Southern Environmental Law Center and a half dozen other groups, residents of Nelson County filed several lawsuits and challenged federal construction permits.
Pembroke Black Farming Community Fighting Gas Pipeline - At one time Pembroke Township in Kankakee County, Illinois was the largest Black farming community in the northern United States. Over environmental concerns and opposition by local Black farmers, a natural gas pipeline with large political backing is moving closer to reality. Farmers and political supporters claim the pipeline “threatens to replace [Pembroke] the last community of African American farmers in Illinois.” Reset talk with a farmer married couple leading protests of Black farmers.
Looming Northeast supply shortage drives steady advance in winter gas prices | S&P Global Platts - Natural gas prices in the US Northeast market area could hit their highest in four years or more this winter as lagging storage volumes and flat production are stretched thin by strong seasonal demand. Forwards markets are already bracing for the increasingly likely scenario. Since the start of April, peak-winter-season prices have surged at downstream hubs across the Northeast Atlantic Seaboard. At Transco Zone 6 New York, the December-January-February calendar-month average has climbed to more than $7/MMBtu recently, up from levels around $5.50 in early April. At Boston-area Algonquin city-gates, the peak-winter calendar-month average has climbed to the mid-$12s/MMBtu recently, gaining about $5.50 or almost 80% since the start of April, S&P Global Platts data shows. At both locations, the winter forward contracts are priced at their highest for January and February which recently settled in the upper-$7 range at Transco Zone 6 and the $13 to $14 range at Algonquin. The runup in Northeast winter gas prices over the past several months comes as regional storage inventories appear increasingly ill prepared to handle the upcoming spike in seasonal heating demand. As of early August, gas storage in the Northeast is estimated at 690 Bcf – about 54 Bcf, or 7%, below the prior five-year average and 128 Bcf, or almost 16%, behind the region's year-ago inventory level, data from S&P Global Platts Analytics shows. Since the start of May, storage injections in the Northeast have averaged about 3.2 Bcf/d – almost 300 MMcf/d below the prior five-year average. While a recent uptick in the pace of injections has narrowed the region's inventory deficit from over 60 Bcf, the speed of this summer's build will need to accelerate to about 3.4 Bcf/d through early November to reach typical pre-winter inventory levels at over 1 Tcf.
Natural gas prices soar as demand for cooling boosts - Natural gas prices peaked this Monday, as cooling demand is forecast to boost in coming weeks; forecasts have predicted that weather will get hotter around the U.S. Consequently, more natural gas is going to be needed in order to cool off departments and buildings. Front-month gas futures rose 2.1 cents, or 0.5%, to settle at $3.935 per million British thermal units; Reuters reported. “The market is looking ahead to what could be a very hot end to the summer; with the cooling degree days likely to go up a little bit.” “Today’s price advance, although contained below Friday’s highs; reinforced our bullish view as we still see achievement of the $4.18 level as a high probability before this week is out.” Moreover, data provider Refinitv also projected that U.S. demand, including exports, will rise from an average of 91.2 bcfd this week to 95.2 bcfd next week. “We believe that early gains were shaved by the plunge in petroleum values; and also, that today’s highs will see violation by mid-week at the latest.” Added Ritterbusch. In addition, as we reported previously, liquified natural gas prices also peaked. Flynn also said to Reuters that U.S. LNG will stay very strong; while U.S. supply will weaken; leading to a tight market this year, which should support prices. In fact, last week natural gas prices jumped to their highest since December 2018 at $4.187. On the other hand, U.S. LNG exports reached 10.8 bcfd in July, up from 10.1 bcfd in June but still below April’s record 11.5 bcfd. On the other hand, U.S. production will remain unchanged, according to Refinitiv, in 92.2 billion cubic feet per day next week. That number will still be below November’s all-time monthly high of 95.4 bcfd. Finally, according to experts, U.S. LNG exports will remain strong for the whole year; supported by European natural gas prices ar tecord levels; and also Asian gas trading nearly at $15 per mmBtu.
Production Drop, Hotter Forecast Propel Natural Gas Futures Prices a Second Day - A step down in production drove natural gas futures prices higher for a second day, with gains accelerating after the latest weather models turned even hotter for next week. The September Nymex gas futures contract settled Tuesday at $4.027, up 9.2 cents on the day. October climbed 9.4 cents to $4.032. Spot gas prices were mostly higher, but there were small decreases in the Midwest and part of the western United States. NGI’s Spot Gas National Avg. climbed 8.5 cents to $4.000. With summer heat nearing what traditionally is the peak period this month, weather forecasts have once again become a driving force for gas markets. Weather models early Tuesday changed only slightly, according to NatGasWeather. The American and European data each saw a difference of less than 2 cooling degree days (CDD) for the coming 15 days compared to Monday’s data. As important, the models remained “quite hot” with the U.S. pattern for Saturday through Aug. 15. The midday Global Forecast System model, however, trended even hotter for next week into the following week, gaining more than 5 CDDs, NatGasWeather said. The forecast showed widespread heat building across most of the United States beginning late this weekend, aided by highs of lower to mid-90s over the East Coast and mid-90s to 102 over Texas and the South. “This should increase power burns to 45 to 47-plus Bcf/d, an impressive amount, thereby resulting in a couple smaller-than-normal builds to finally push current deficits of 168 Bcf to near or over 200 Bcf,” NatGasWeather said. The forecaster expects the “very warm to hot pattern” from Sunday to Aug. 15 and possibly carrying over to Aug. 16-18. However, early indications showed conditions not quite as impressively hot by then, “as weather systems find flaws in the ridge to weaken it moderately.” Bespoke Weather Services said another factor to consider is that wind early next week is expected to be stronger than recently, but it then may back off by the end of the period. Wind penetration has been a key driver of natural gas demand for power generation, even in the current higher price environment. Energy Aspects noted that wind generation in July averaged around 30 GW, short of its pre-month expectations by 9 GW. The firm attributed most of the miss to low wind generation earlier in the month in the Midcontinent.
September Natural Gas Prices Hit $4.20 Ahead of Potentially Lowest Injection of Season - After two solid days in the black, natural gas futures prices reached new heights on Wednesday as production continued to decline, and hot weather remained firmly in next week’s forecast. The September Nymex gas futures contract hit a $4.205 intraday high before settling at $4.158, up 13.1 cents from Tuesday’s close. Spot gas prices also strengthened as the cool conditions experienced in much of the country this week started to fade. With warmer temperatures on the way, NGI’s Spot Gas National Avg. ticked up 12.0 cents to $4.120. The potential for intense heat next week already has cut short an emerging period of consolidation in the gas market, according to EBW Analytics Group LLC. A growing cooling demand outlook for the coming 15-day period could lift weekly cooling degree day (CDD) forecasts for the week ending Aug. 12 to 93, which is 25 CDDs hotter than this week. “Bullish momentum has reemerged faster than appeared likely just last week,” said EBW analysts. The supportive outlook comes as long-range weather forecasts remained stable again Wednesday morning. The outlook showed next week as the “hottest week of the summer,” said Bespoke Weather Services. Forecasters pointed to widespread temperatures in the 90s across the Midwest and East underneath a strong upper level ridge in the six- to 10-day period. A couple of days next week are forecast to reach near records in terms of national gas-weighted degree days.
US working natural gas volumes in underground storage increase 13 Bcf: EIA | S&P Global Platts - US natural gas storage volumes increased by 13 Bcf in the week ended July 30, which was 4 Bcf less than a S&P Global Platts survey of analysts, but exactly in line with the Platts Analytics' storage model.Working gas in storage increased to 2.727 Tcf, the US Energy Information Administration, or EIA, reported Aug. 5. The weekly injection was less than the 17 Bcf addition expected by a Platts' survey of analysts. It also trailed the five-year average build of 30 Bcf and last year's 32 Bcf injection in the corresponding week. The injection was less than half of the 36 Bcf build in the week ended July 23, with the decline being driven primarily by the South Central region. It posted a massive draw of 23 Bcf and measured as one of the largest withdrawals from storage in the region on record to take place during an injection season. The region has reported an average draw of 7 Bcf for the week over the past five years. Last year, it added 2 Bcf. Total US demand increased by more than 3 Bcf/d compared to the week before, while total US supplies were flat, according to Platts Analytics data. US storage volumes now stand at 542 Bcf, or 16.6% less than the year-ago level of 3.269 Tcf, and 185 Bcf, or 6.4% less than the five-year average of 2.912 Tcf. The NYMEX Henry Hub September contract remained at $4.16/MMBtu in trading following the release of the weekly storage report. The winter strip, November through March, averaged $4.23/MMBtu. An early end to a pipeline maintenance restricting flows from the US Northeast to the Southeast should boost supplies to the South Central region. Southeast inflows from the Northeast increased on Aug. 4 from 6.6 Bcf/d to over 7 Bcf/d as the capacity reductions along Texas Eastern Transmission were lifted. The outage, which began on June 2, cut southbound flows through the Danville compressor station by roughly 600 MMcf/d, lowering total Northeast to Southeast flows by 400 MMcf/d as other pipelines were able to make up some of the losses. The work was completed nearly two months earlier than expected, as the original end date was targeting the end of the third quarter. The increased supply reaching the Southeast will likely help to keep some pressure on regional prices. However, overall tighter balances throughout the region will likely outweigh any increases to inflows, according to Platts Analytics. Despite the elevated inflows to the Southeast, spot Henry Hub prices jumped 14 cents during trading on Aug. 4 to settle at $4.12/MMBtu. Platts Analytics' supply and demand model currently forecasts a 47 Bcf injection for the week ending Aug. 6, which would measure 5 Bcf more than the five-year average.
September Natural Gas Prices Retreat in Face of Dangerously Low Storage The latest round of government storage data was about as bullish as it could be, but sellers came into the fold once weather models showed the upcoming heat being a little less intense. The September Nymex gas futures contract settled Thursday at $4.140, off 1.8 cents day/day. October slipped 1.5 cents to $4.148. Spot gas prices remained mostly in positive territory. However, there were a handful of locations, mostly in the West, that fell into the red. NGI’s Spot Gas National Avg. tacked on 2.5 cents to $4.145. [Mexico Natural Gas Market Spotlight: Gathering insight from active buyers and sellers, NGI breaks down what fundamentals are driving Mexico’s natural gas pricing in this weekly market analysis – READ NOW.] As it is every week, the Energy Information Administration’s (EIA) storage report was the primary focus of trading early in the session. Estimates ahead of the report were wide-ranging, from an injection as small as 14 Bcf to one as large as 34 Bcf. For comparison, the EIA recorded a 32 Bcf injection in the same week last year, and the five-year average stands at 30 Bcf. The Nymex September futures contract initially popped when the EIA reported a smaller-than-expected 13 Bcf build. The prompt month hit around $4.20, but with the latest weather models backing off from some of the heat forecast for next week, sellers swept in to drag prices back down. “The market appeared to already be pricing in risk of a bullish miss, and some cooler shift in the midday weather models brought some sellers into the fold,” said Bespoke Weather Services. “Dips likely will be bought, still, until production shows.” Given rampant export demand, and near triple-digit temperatures across the South Central region, inventories declined at both salt and nonsalt facilities. The EIA said salt stocks fell by 19 Bcf, and nonsalt dropped by 3 Bcf. A participant on The Desk’s online chat Enelyst noted that the 19 Bcf withdrawal in the South Central salt inventories was the largest third quarter salt draw of all time. The nonsalt draw also surprised. “I didn’t see that draw from nonsalt coming,” said Enelyst managing director Het Shah. Elsewhere across the country, Pacific stocks also slipped by 2 Bcf amid ongoing heat and low hydroelectric power in the region. East inventories climbed 21 Bcf, and the Midwest added 17 Bcf.
Bacteria Cleanup: Should we let nature clean up oil spills? – Natural populations of oil-degrading bacteria could help to clean up freshwater rivers and lakes after spills from pipelines and trains, researchers have found after experiments that simulated spills in a Canadian lake.Vince Palace, who led the work at the International Institute for Sustainable Development’s Experimental Lakes Area in western Ontario, said that the methods currently in use for cleaning up spills in rivers and lakes – mostly digging up and dumping contaminated soil – are not particularly effective. They only recover around 20 to 40% of the oil, and the physical damage done to shorelines and streambeds can be worse than the effects of the spill itself, taking as long as a decade to recover.Palace and his colleagues wanted to see if leaving the oil in place to be cleaned up by natural processes like bacteria might be a practical alternative.“We know that in the marine environment there are bacteria that can degrade oil,” said Palace. “We wanted to know if naïve freshwater systems have that same capacity.”The researchers created enclosures along the shore of one of the experimental lakes and dumped either conventional crude oil or the diluted bitumen that comes from Canada’s oil sands to simulate a spill. After 72 hours they cleaned it up as best they could, then examined what happened to the residual oil over the course of the summer and into the winter.The team found that after the spill, the composition of the bacterial community in the soil and water shifted dramatically. Rare types of bacteria, which had barely been present before, suddenly became the most common – and most of them had the capacity to degrade oil by using it as a source of food, suggesting a natural recovery could be a potential solution to spills in places like the Great Lakes, which are criss-crossed by pipelines and home to several refineries.
Council holds city-county pipeline ordinance, passes on second reading proposed permitting process law – MLK50 - Nearly six months since the first pipeline-regulating ordinance was placed before the Memphis City Council and one month since developers canceled the Byhalia Connection Pipeline, local governments have yet to pass any measures that would make similar pipeline projects tougher, if not impossible, to build.The council will consider Tuesday afternoon the third and final reading of a joint city-county ordinance that would require 1,500 feet between an oil pipeline and residential areas. Also on the council agenda is the second of three readings for a city-only ordinance that would create a new permitting process for such projects.Even though the project was halted, passing the two ordinances have been a priority of Justin J. Pearson, a co-founder of Memphis Community Against the Pipeline, which led the charge to stop the pipeline.“We are as vulnerable today against crude oil pipelines as we were in (before the project was announced),” Pearson said. “Without legislation and just regulation, our aquifer and our people will remain vulnerable.” The now-canceled project was a joint venture of Plains All American Pipeline and Valero Energy Corporation to expand their crude oil capacity with a pipeline through largely poor and Black neighborhoods in Southwest Memphis and atop the vulnerable Memphis Sand Aquifer, from which the city draws its drinking water.Plains voluntarily abandoned the project last month after facing opposition from Southwest Memphis residents, MCAP, elected officials, and national celebrities. However many pipeline opponents worry that without legal barriers to block it, the project could be revived later. In their cancellation announcement, Plains did not commit to abandoning the project permanently, nor did it signal that it wouldn’t pursue another pipeline in Memphis.The city’s ordinance would create a new permitting process for oil pipelines, establish an advisory board of experts and community members to evaluate proposals, require public notice and comment, and give the city council final approval. The council stalled the ordinance for months out of an abundance of caution after Plains threatened to sue. Some council members also wanted to address Memphis business leaders’ concerns that the ordinance would disrupt maintenance on existing pipelines. “It is being explained to us that delays are happening because of a ‘corporate constituency’ that is against the legislation without any mention of the community constituency that is for just legislation and regulation being passed,” Pearson said.
Oil leak from Golden Ray wreck could impact local beaches - — A pollution response team was been sent to the St. Simons Sound after oil leaked from the Golden Ray wreck.According to the Georgia Department of Natural Resources, there was a “significant” oil leak from the wreck.The department says it happened during “weight shedding” operations.Responders are trying to clean up the oil with current busters and oil skimmers. They ask anyone going to St. Simons Island and Jekyll Island who sees residual oil on the shoreline or in the water to call the National Response Center hotline at (800) 424-8802.
Days of cleanup after shipwreck oil leak fouls Georgia beach (AP) - Officials say cleanup efforts will take several days after oil leaking from the remains of an overturned cargo ship off the Georgia coast washed up on a beach popular with tourists.Coast Guard Petty Officer 2nd Class Michael Himes said Monday that bands of oil released into the water during demolition of the shipwreck are being cleaned up along 2.5 miles of beaches on St. Simons Island.The first spill happened Saturday as crews manning a giant crane tried to lift a newly severed section of the ship from the water. Himes said more oil gushed out during a second lift attempt Monday. About 70 workers have been working to remove the oiled sand since Sunday.
Louisiana needs sand to rebuild its coast. Old oil and gas pipelines are blocking the way. - A Houston-based energy company is asking a federal bankruptcy court for permission to walk away from its aging infrastructure in the Gulf of Mexico. Fieldwood Energy is attempting to shift responsibility for removing 1,715 wells, 276 platforms and 281 pipelines to oil and gas companies that previously held leases for the same area, according to court documents. Under existing federal regulations, companies remain liable for decommissioning infrastructure on areas of federally owned seafloor where they previously produced oil and gas. But the former holders of the Fieldwood leases — including Chevron, BP and Shell — are attempting to get out of that obligation because of the cost, estimated at $9 billion. It’s a familiar story. A recent U.S. Government Accountability Office report found that oil and gas companies have been allowed to abandon 97 percent of offshore pipelines in place without penalty. The abandoned infrastructure poses environmental concerns, but it has also created another problem: The pipelines are blocking access to the sand that Louisiana and other gulf states desperately need to rebuild their coastlines in the face of rising seas. The Gulf of Mexico swallows a football field of Louisiana coastline every 100 minutes on average. Barrier islands that have historically acted as speed bumps to hurricanes headed toward coastal communities are among the areas losing ground. Without them, the state is more vulnerable to climate change and severe weather. Geologists estimate that up to 11,000 million cubic meters of sediment are needed to restore the state’s coastline, but about 58 percent of the offshore sediment in the gulf that could be used to rebuild Louisiana’s coast is blocked by pipelines, said Syed Khalil, a geologist with the state’s Coastal Protection and Restoration Authority. While there is enough sand for the coastal restoration projects that Louisiana has planned in the short term, the state’s fight to fend off rising seas will require more. “We need every grain of sand for the restoration of coastal Louisiana,” Khalil said. Other Gulf Coast states are facing the same problem. But the issue has come to a head in Louisiana, where coastal land is disappearing faster than anywhere else in the nation. Flood control levees built along the Mississippi River are partly to blame for the Bayou State’s land loss. Levees block off the supply of sediment once carried by the river into coastal wetlands. Canals dug through the wetlands to build and service pipelines — which create pathways for saltwater to flow into the marsh — are also partly to blame for Louisiana’s coastal erosion. Now, those pipelines are hindering the solution. Federal regulations require the removal of offshore pipelines once they are decommissioned, but the rules are rarely enforced. The Bureau of Safety and Environmental Enforcement, the Interior Department agency that regulates offshore energy, has been mostly unsuccessful at getting companies to pay for the removal of pipelines decommissioned in place when they are later determined to be in the way.
Lawsuits over Louisiana oil drilling damage subject to new round of federal court hearings - Lawsuits filed in state court by Plaquemines and Cameron parishes to force oil and gas companies to clean up millions of dollars of environmental damage caused by their drilling activities were ordered Thursday to undergo a new set of hearings in federal court.The petitions are among 42 suits in state courts in six Louisiana parishes against oil and gas companies, some filed as early as 2013, over damage dating from decades ago. They allege the companies violated Louisiana's coastal resources management act by failing to obtain permits or by violating the terms of the permits they did obtain. They do not allege violations of federal laws.Take a close look at this abandoned Plaquemines oil field, why it's source of major legal battle The companies have repeatedly tried to transfer the suits to federal courts in search of a judicial audience that might be more friendly to their arguments against paying for the cleanups. Federal courts have often returned the suits to state courts.But a document filed in support of Plaquemines Parish's arguments triggered the latest challenge. The companies contend the document for the first time showed that some of their drilling operations were conducted during World War II at the request of the federal Petroleum Administration for War. That could put the drilling under federal regulatory law, making the suits eligible for federal courts.The companies also argued that their actions were conducted under the direct jurisdiction of federal agents, another reason they should be heard in federal courts.Thursday's ruling from the 5th U.S. Circuit Court of Appeals in New Orleans was written by Judge James Ho of Dallas and joined by judges Kurt Engelhardt of Metairie and Andrew Oldham of Austin, Texas. President Donald Trump nominated all three to that court.They agreed with earlier decisions, by district judges in New Orleans and Lake Charles, that the oil companies are incorrect in saying regulatory questions involving the environmental damage fall under federal legal jurisdiction. But they also ruled that the lower courts must determine whether the companies' work was overseen by federal agents, so-called "federal officer jurisdiction," which would allow the cases to stay in federal court.
Proposed oil terminal in Plaquemines Parish could disrupt Louisiana's $2B wetlands project wA massive oil export terminal proposed in Plaquemines Parish would likely undermine Louisiana's $2 billion bid to restore the degraded wetlands of Barataria Bay, according to a draft study commissioned by the Midwestern company leading the project. Modeling completed in February 2020 suggested the construction of the $2.5 billion terminal's dock could reduce the amount of sand entering the mouth of the state's planned Mid-Barataria Sediment Diversion by up to 15%. Add a ship parked in front of the terminal, and nearly half of the sediment that could be used to rebuild land off the parish's west bank might be blocked. Consisting of a 2-mile long gated, concrete channel, the Mid-Barataria Sediment Diversion would transport silt- and clay-laden water from a sand bar in the Mississippi River to the Barataria Basin. It's the one of the cornerstones of the state's 50-year, $50 billion plan to sustain a portion of Louisiana's lower third amid severe coastal erosion, subsidence and rising seas. Located on the former St. Rosalie Plantation site, the crude oil terminal would store up to 20 million barrels on site and load them onto huge ocean-going "Panamax" ships and barges for export. It’s a joint project of Tallgrass Energy LP, headquartered in Leawood, Kansas; Drexel Hamilton Infrastructure Partners, LP, a New York-based investment firm; and the Plaquemines Port, Harbor and Terminal District, which is governed by the Parish Council. Interfering with the state's restoration project is just one of the terminal's challenges. Developers are also facing opposition from residents of nearby Ironton, who fear increased air pollution and oppose plans to excavate and build on top of gravesites of people formerly enslaved on the plantation. The study became public after the environmental group Healthy Gulf filed a public records request for it in May. Now, the nonprofit, joined by the Sierra Club, National Wildlife Federation, Environmental Defense Fund and Coalition to Restore Coastal Louisiana, have renewed calls for the Louisiana Coastal Protection and Restoration Authority to kill the proposed terminal by finding it inconsistent with the Coastal Master Plan.
Tellurian and Shell Finalize 10-Year LNG Deal -- Tellurian Inc. has announced that it has finalized liquefied natural gas (LNG) sale and purchase agreements (SPAs) with Shell NA LNG. The company outlined that the SPAs are on a free on board basis at Driftwood LNG for a combination of three million tons per annum (Mtpa) for a ten year period, indexed to a combination of two indices - the Japan Korea Marker (JKM) and the Dutch Title Transfer Facility (TTF), each netted back for transportation charges. The agreements mark the third deal Tellurian has finalized in ten weeks, totaling nine Mtpa and nearly all of the capacity of Driftwood LNG’s first two plants, Tellurian noted. In June, Tellurian announced that it had finalized LNG SPAs with Vitol Inc. for three Mtpa over a ten year period. In May, Tellurian and Gunvor Singapore Pte Ltd announced an LNG SPA for three Mtpa for a ten year period. “Tellurian welcomes Shell to the Driftwood project,” Tellurian President and Chief Executive Officer, Octávio Simões, said in a company statement. “Shell manages one of the largest and most diverse portfolios of LNG in the world and is leading the industry in delivering CO2e neutral LNG cargoes. Owing to Driftwood’s integrated project, our ability to accurately measure well to loading arm emissions and reduce emissions where operationally possible, further enables Shell’s CO2e neutral LNG offering,” the Tellurian head added. “With these SPAs, we have now completed the sales to support the launching of the first two plants. Tellurian will now focus on financing Driftwood, in order to give Bechtel notice to proceed with construction in early 2022,” he went on to say. Steve Hill, the executive vice president of Shell Energy, said, “this deal secures additional competitive volumes for our portfolio by the mid-2020s, enabling us to continue providing diverse and flexible LNG supply to our customers”. Driftwood LNG, which is Tellurian’s first project, is a 27.6 Mtpa LNG facility near Lake Charles, Louisiana. The project has all the required permitting to begin construction and has achieved “significant commercial momentum”, Tellurian notes on its website. The management team at Tellurian has collectively delivered over 79 million tons of LNG through over the past 50 years, Tellurian’s website notes.
Buyer for Port Arthur LNG switches to other Sempra projects - Sempra’s proposed Port Arthur LNG export facility has lost an investor. Citing delays on the project, Poland’s state-run energy firm, PGNiG, decided to end its proposed 20-year contract for liquid natural gas. Instead, PGNiG has opted to sign a contract with Sempra to receive the 2 million tons per year of LNG from the company’s other North American projects, it announced on Tuesday. “We highly value our relationship with Sempra LNG, and we are keen to continue it,” Paweł Majewski, CEO of PGNiG SA, said in a statement. “The (memorandum of understanding) allows for shifting the volumes originally contracted at Port Arthur LNG to other facilities from Sempra LNG’s projects portfolio.” Sempra LNG owns a 50.2% interest in Cameron LNG, a 12-Mtpa export facility operating in Hackberry, Louisiana, and already is working on an expansion at that facility. The company also is working with IEnova and TotalEnergies on a project in Baja California, Mexico. The first phase of that project is expected to start production by the end of 2024. There are plans for an expansion at that facility as well, which are in the early phases of development. Meanwhile, Sempra in May, for the second time delayed its final investment decision on moving forward with the Port Arthur LNG, shifting the timeline sometime into 2022. In a statement from the company, Sempra LNG’s top executive was positive about the changes, marking it as a reflection of growing demand from energy buyers for reduced carbon emissions attached to the products they purchase. Sempra executives told investors and analysts in a May investor’s call that impacts to the natural gas industry during the pandemic and demand for more environmentally-friendly projects from global customers would require it to delay for another year while it continued to refine plans. Although work on an actual LNG facility for Sempra in Sabine Pass may be tentative, the company’s ongoing work on Texas 87 is nearing the finish line.
FERC Ordered to Revisit South Texas LNG Authorizations as Court Finds Environmental Analyses Lacking --A federal court on Tuesday ordered FERC to review its approvals of two planned liquefied natural gas (LNG) export projects in South Texas, saying the agency had not adequately explained its approach in evaluating the potential impacts on climate change and environmental justice (EJ) communities. The decision handed down from the U.S. Court of Appeals for the District of Columbia (DC) Circuit remands the Federal Energy Regulatory Commission’s authorizations, clearing the facilities for construction and operation, but it does not vacate them. That leaves the authorizations in place, allowing the developers to continue work on the facilities while the review proceeds.“We find it reasonably likely that on remand, the Commission can redress its failure of explanation with regard to its analyses of the projects’ impacts on climate change and environmental justice communities, and its determinations of public interest and convenience” under the Natural Gas Act (NGA) “while reaching the same result,” Circuit Judge Robert Wilkins wrote in an opinion on behalf of the court.The facilities in question, NextDecade Corp.’s Rio Grande LNG and an associated pipeline, and the privately owned Texas LNG development, received FERC authorization in 2019. Neither has reached a final investment decision. A coalition of environmentalists and local activists has long opposed the projects and challenged FERC’s authorizations in court.In the Tuesday decision, the court agreed with project opponents that the FERC assessment of the projects’ impacts on climate change were deficient. The opponents, which include environmental groups and local activists, argued that FERC should have used a “social cost of carbon” protocol to calculate impacts.While commissioners had said the projects would contribute “incrementally” to climate change, FERC also said it could not calculate the actual impacts because the means of making those calculations were unknown. The court determined that the law required FERC to evaluate climate change impacts based on “theoretical approaches or research methods generally accepted in the scientific community.
Gas projects reveal FERC’s environmental justice conundrum - Two liquefied natural gas terminals under development at the tip of Texas’ Gulf Coast could either lift low-income residents out of poverty or destroy local fishing and tourism economies, depending on whom you ask.The disparate views on the planned LNG projects — Rio Grande LNG from Houston-based NextDecade and the independently owned Texas LNG — underscore a tension for the Federal Energy Regulatory Commission and Chair Richard Glick’s recent pivot to address environmental justice: How should FERC determine whether the costs of a proposed project outweigh its benefits? Under what circumstances should projects in disadvantaged communities be approved or denied? And will FERC’s decisions survive legal scrutiny?FERC greenlighted the two LNG projects, which are slated to be built in the majority Latino region of Cameron County, Texas, in the fall of 2019. At the time, then-Chair Neil Chatterjee, a Republican, touted the projects as a win for the climate and U.S. foreign policy.“The Commission has now completed its work on applications for 11 LNG export projects in the past nine months, helping the United States expand the availability of natural gas for our global allies who need access to an efficient, affordable and environmentally friendly fuel for power generation,” he said in a statement at the time.To some legal experts and environmental activists, however, FERC’s analysis of the potential health and economic impacts of the projects on nearby communities was a textbook example of the agency’s inadequate consideration of environmental justice issues. Currently, the agency considers environmental justice within broader environmental impact statements, but there have been complaints that those analyses are insufficient and don’t fully assess impacts to low-income areas and communities of color.Glick, a Democrat who became chairman in January, vowed to make environmental justice a greater priority for the commission throughout its decisionmaking processes. At the same time, industry has questioned whether the agency has the legal authority to do so.The developers of Texas LNG and Rio Grande LNG each estimates that the terminals could bring thousands of new jobs to the region. Many elected officials — from Sen. John Cornyn (R-Texas) to the Cameron County Commissioners Court — have also touted the projects’ economic benefits, including the tax revenue they could bring in.The facility will also be powered by “electric drives” rather than gas turbines to lower its carbon emissions, Texas LNG added. Rio Grande LNG, meanwhile, is incorporating carbon capture and storage into its design to cut “permitted emissions” at its facility by over 90% (Energywire, March 19). Developer NextDecade did not respond to requests for comment.
Tribes, enviros sue Corps over Texas oil terminal expansion permit -(Reuters) – Indigenous tribes and environmental groups sued the Army Corps of Engineers in Corpus Christi, Texas, in federal court for issuing a permit to Moda Midstream, alleging it issued the permit for the expansion of the marine oil export terminal without studying the effects of the project on seagrass and wetlands. In a lawsuit filed Tuesday, Indigenous Peoples of the Coast Bend and others accused the Corps of violating the National Environmental Policy Act (NEPA) and the Clean Water Act (CWA) with a CWA permit that would allow Moda to dredge about 3.9 million cubic meters. of material out of Corpus Christi Bay. “One of my main concerns as a fisherman and bird watcher is that MODA’s expansion will destroy many acres of vital seagrass,” said Patrick Nye, chairman of the plaintiff group Ingleside on the Bay Coastal Watch Association in a statement. if green comment then The Corps did not immediately respond to a request for comment. Steven Davidson, a spokesperson for Moda, said: “We are satisfied that the nearly one-and-a-half-year application review process has been complete and that the U.S. Army Corps of Engineers permit has been properly delivered. “ The Houston-based company had planned to expand its Ingleside oil terminal, which connects Permian and Eagle Ford’s crude oil production to international markets, as early as 2017. Construction on the project has not started, Davidson said. The complaint says the expansion of the “largest export terminal in the United States by volume” would add five berths for tankers and barges, effectively doubling the capacity of its vessels. The plaintiffs, represented by Lauren Ice of Perales, Allmon & Ice, argue that the Corps violated NEPA because, although its environmental review of the project notes that seagrass and wetlands will be affected, it does not study this impact with the type of detailed reporting on NEPA’s mandates for major federal actions, known as environmental impact statements.
John Kerry questions long-term future of natural gas - Climate envoy John Kerry says natural gas is not “anything near a long-term solution” to help address climate change even while it can help replace coal in certain countries in the near-term.Kerry’s stance, declared in an interviewwith the New Yorker published last night, is notable because the Biden administration has struggled to articulate a consistent position on the role of natural gas.Here is the entire quote: “Russia has an option of quickly closing coal plants that are more than forty years old, not working that effectively, and not needed, in favor of transitioning to gas for the moment. I emphasize ‘for the moment’ because gas is still a fossil fuel, and gas is mostly methane, so it leaks and also produces CO2. It’s not, in our judgment, anything near a long-term solution, unless somebody discovers one-hundred-percent abatement.” Energy Secretary Jennifer Granholm has repeatedly said that shipping U.S. liquified natural gas abroad can play an important role in replacing dirtier coal, especially in Asia. She has also pressed the oil and gas industry to do a better job of reducing methane emissions associated with LNG in order to make that case credible. But she has not definitively said how long gas can continue playing a useful role in the clean energy transition.Still, liberal climate activists who have been pushing the administration to reject natural gas, even as a replacement for dirtier coal abroad, are interpreting Kerry’s comments as being closer to their position."Special Envoy Kerry’s comments were definitely encouraging,” Collin Rees, senior campaigner with Oil Change U.S., told me. “It’s good to see a recognition from Kerry that ‘slightly less dirty’ won’t cut it — and that zero emissions means no gas or other fossil fuels."
Exxon Lobbyist Caught on Tape Is an Advisor to Congressional Black Caucus Foundation – ExxonMobil senior lobbyist Keith McCoy was caught on video more than a month ago saying that he and his employer fight congressional climate action by using “shadow groups” and centrist think tanks. But the Congressional Black Caucus Foundation has so far decided to keep McCoy on as an advisor. McCoy is a member of the Congressional Black Caucus Foundation’s (CBCF) corporate advisory council, which “[advises] the CBCF’s Board of Directors on policy, special initiatives, and leadership development.” The CBCF’s Board of Directors currently includes six members of the House of Representatives, some of whom hold positions on the House committee with jurisdiction over legislation related to environmental protections and climate change. The CBCF is a nonprofit affiliate of the Congressional Black Caucus that researches how policies affect Black communities, publishes legislative reports, and hosts an annual legislative conference that it describes as “the leading policy conference on issues impacting African Americans and the global Black community.” On June 30, a Greenpeace-affiliated outlet released video of McCoy, a senior director of federal relations for Exxon, telling an undercover reporter that his company works behind the scenes to stall action on climate change even as it claims publicly to support the Paris Agreement and policies like a carbon tax. McCoy, who believed he was giving advice to someone who was looking to hire a lobbyist, said that the company backs a carbon tax because it believes it will never happen but gives it a good talking point.Sludge asked the CBCF if it would keep McCoy on its advisory board and if it would continue to take donations from Exxon, but did not receive a response.The Congressional Black Caucus has 57 members, all Democrats, including both representatives and senators.
CenterPoint customers will pay price for pipeline company profits during Texas freeze - Texans are on the hook for $3.6 billion in natural gas costs incurred by utilities during one freezing week in February — a burden consumers will bear for a decade or longer.During that same winter week, several natural gas pipeline companies and traders made billions of dollars as they transported and sold natural gas at sky-high prices when supplies were short. Pipeline companies Energy Transfer of Dallas and Kinder Morgan of Houston made $2.4 billion and $1.1 billion, respectively, while British oil major BP made more than $1 billion from its natural-gas trading business during the deadly, historic storm, according to company filings and analyst estimates. Houston pipeline company Enterprise Products Partners said it made $250 million for transporting and selling natural gas at high prices to utilities, industrial customers and power generators during the storm.Ultimately, Texans will fund these companies’ profits, “It’s pretty clear this is a wealth transfer from the public to investors and traders who could capitalize on the high prices,” Krane said. “The frustrating thing is, even though people were shivering in their homes, their (natural gas) bills are going up anyway. They’re still going to have to pay for this. It’s really a slap in the face.”More than 1.8 million CenterPoint Energy customers in the Houston area are responsible for the $1.14 billion natural gas bill incurred by the Houston utility when it had to quickly buy natural gas at sky-high prices after demand soared and supplies plunged during the storm.Natural gas wells and pipelines, many of which weren’t weatherized to handle prolonged freezing temperatures, froze and lost pressure during the storm. Weather-related problems and power outages at distant oil wells, caused natural gas production to plunge by almost half just as Texans were trying to stay warm during days of below-freezing temperatures.
Phillips 66 sees wider crude quality differentials going forward | S&P Global Platts Phillips 66's record second-quarter chemical results were countered by poor refining segment results, due in part to high RINs costs, weak market capture and narrow light-heavy crude differentials, company executives said Aug. 3. Phillips 66 ran its refineries at 88% of capacity in the second quarter, up from first quarter's 74%, but posted lower margin capture quarter on quarter on its distillate-focused refinery configuration, CFO Kevin Mitchell said during a call to discuss Q2 results.. "Realized margin was $2.92/b and resulted in an overall market capture of 22%," Mitchell said. During the third quarter, the company will run at rates dictated by market conditions, he added. First quarter refinery margin capture was 33%, Mitchell said. "Market capture is driven by the configuration of our refineries," he said. "Our refineries are more heavily weighted to distillate production than the [3:2:1 crack] market indicator." During the quarter, the gasoline crack improved $5.68/b, while the distillate crack increased only improved by $2.20/b. Also, Phillips 66 had "quite a bit of planned FCC downtime this year," CEO Greg Garland said, putting downtime at about 2% of the company's gasoline-making fluid catalytic cracking capacity, further reducing gasoline output and lowering margin capture However, Garland said that the RIN-adjusted crack – which does not include the cost of compliance credits for the Environmental Protection Agency's Renewable Fuel Standard – needs to get back to the $12/b to increase market capture to take advantage of rising demand as the coronavirus pandemic lockdowns ease. The increase in heavier crude supply, due in part to higher production quotas agreed by OPEC+ members, will benefit distillate-heavy Phillips 66. The company, which runs a lot of heavy crude, will benefit from the widening of light-heavy crude differentials. "For the second quarter, it was a gasoline-driven market without much differential on heavy crude," said Robert Herman, Phillips 66's head of refining. "We've seen those widen out here now in July to a much more respectable level." So far in the third quarter, US light sweet Gulf of Mexico benchmark Light Louisiana Sweet is holding a $2.59/b premium to US Gulf of Mexico medium-sour Mars, according to S&P Global Platts assessments. This compares with the $2.04/b and $1.58/b premium held in the second and first quarters, respectively.
Devon and Conoco Study $10B Shell Permian Assets-- Devon Energy Corp. and ConocoPhillips are among potential suitors studying Royal Dutch Shell Plc’s portfolio of Permian Basin oil fields, which could be worth as much as $10 billion in a sale, people familiar with the matter said. Chevron Corp. is also among companies considering bids for the assets, which are largely located in West Texas, the people said. Suitors have been invited to Shell’s data room to examine information on the business, the people said, asking not to be identified discussing confidential information. The Permian Basin of West Texas and New Mexico is the world’s busiest shale patch and accounts for roughly half the activity in U.S. oil fields today. Deliberations are ongoing, and there’s no certainty any of the suitors will decide to proceed with formal proposals, according to the people. Representatives for Chevron, ConocoPhillips, Devon and Shell declined to comment. The sale comes amid shifting strategies at oil and gas majors looking to less carbon intensive operations. BP Plc last year completed the sale of its business in Alaska to Hilcorp Energy Co., while in early 2021 Equinor ASA agreed to sell its interests in the Bakken field in Montana and North Dakota to Grayson Mill Energy for $900 million. In May, Shell was ordered by a Dutch court to slash its emissions harder and faster than planned after losing a court case against Milieudefensie, an arm of Friends of the Earth. Shell said it will appeal the verdict, while asserting a willingness to accelerate its transition to a net-zero emissions business. Meanwhile, investors in the U.S. have been pushing for more company tie-ups within each of the shale basins as a way to cut costs and get more bang for their drilling buck. Bonanza Creek Energy Inc. bought its Colorado rival Extraction Oil & Gas Inc. for about $1 billion, while Midland, Texas-based Diamondback Energy Inc. announced a pair of deals late last year to bulk up in the Permian.
US oil, gas drilling rig count up four at 603 on stronger Permian activity - The US oil and gas rig count climbed four to 603 in the week ended Aug. 4 amid an uptick in Permian basin drilling activity, rig data provider Enverus said Aug. 5. The number of oil-focused rigs was up six at 463, while the number primarily chasing gas fell two to 140. The rig count climb was centered in the Permian Basin, where operators added five rigs for a total 258, leaving the plays rig count just one shy of the 15-month high of 259 seen during the week ended July 21. But rig counts in the other major named oil-focused basins were flat to lower. The SCOOP-STACK and Denver-Julesburg play rig counts were steady at 29 and 15, respectively. The South Texas Eagle Ford Basin shed two rigs, putting the total active there down to 40, a six-week low. Meanwhile, the Bakken rig count fell one to 22. Among the major named gas plays, the Utica shale saw an increase in drilling rig count, which climbed one to 13. The nearby Marcellus basin shed one rig for a total 32, while in the Haynesville, operators idled one rig, leaving a total 55 active. The lower overall gas rig count snapped three consecutive weekly builds that had seen gas-focused drilling activity reach the highest level since March 2020. Even after pullback in the week ended Aug. 4, the gas rig count is just 5% below pre-pandemic levels. Oil-focused rigs, in contrast, despite holding near April 2020 levels are still down around 33% from pre-pandemic levels. Permian growth eyed Notably, Permian Basin rig count is down nearly 40% from pre-pandemic levels, significantly lagging the broader oil and gas rig count, which is down just 28% over the same period. But despite laggard drilling activity, improved efficiencies have pushed Permian production to near pre-COVID levels. The basin’s crude output exceeded 4.8 million b/d before the pandemic, falling to a low of about 4.15 million b/d last August, before rebounding back up to about 4.7 million b/d this August, according to the US Energy Information Administration.
New Mexico’s Oil Output Rises Signaling a Modest Shale Recovery -- New Mexico’s oil production surged to a record in May highlighting the Permian Basin’s role as the shale industry sees some recovery from the pandemic.The southwestern state produced about 4% more crude in the month to reach a record 1.22 million barrels a day, according to U.S. government data released Friday. It also topped North Dakota, to become America’s second-biggest onshore oil supplier. New Mexico has churned out more than North Dakota for three straight months, the longest stretch since 2008.New Mexico’s rising status as a key supplier reflects its cost advantage. U.S. oil and gas companies have been judicious in raising output after many producers pledged to cap spending and focus on returning more capital to shareholders. To that end, the Permian’s New Mexico is being favored over North Dakota, where higher production costs have historically curbed profits.The promises on capital restraint are likely to hold further production gains in check, even with higher oil prices providing an incentive to expand. In its latest earnings report, Chevron Corp. which has sizable acreage in the New Mexico, expects its Permian output in 2021 to be comparable to 2020 despite announcing that it would be adding more rigs and completion crews through the rest of this year. U.S. oil production stood at 11.2 million barrels a day in May, nearly a million barrels a day less than the same month in 2019.
Comment period extended for listing lesser prairie chicken as endangered --The public will have a month longer to weigh in on the proposed listing of the lesser prairie chicken under the Endangered Species Act. The U.S. Fish and Wildlife Service is extending the deadline for public comment to Sept. 1 for the grouse, which has seen its populations dwindle from 2 million in the 1800s to about 38,000 across five states because of climate change, industrial development and agriculture. In late May, federal wildlife managers proposed relisting the bird — known for its colorful spring mating display — to comply with a court order spurred by conservation groups suing the agency. A 60-day comment period that began June 1 will increase to 90 days. The proposal calls for listing the bird’s southern population, including in Eastern New Mexico, as endangered and those occupying the northern rangelands as threatened. Its habitat can be found in parts of New Mexico, Colorado, Kansas, Oklahoma and Texas. An abrupt 50 percent drop in the bird’s numbers in 2014 prompted the agency to list the bird as threatened that year. But two years later, a brief 25 percent surge in population led to a federal judge removing protections in response to a lawsuit by a petroleum company. Environmentalists have pushed for renewed federal protections while the oil and gas industry has staunchly opposed relisting the grouse, saying the voluntary programs to protect and grow the birds’ habitat are working. Wildlife officials say the lesser prairie chicken faces a number of external threats, including from climate change prolonging droughts, especially in the southern region where the bird could become extinct.
Shale Drillers Leave $12B on Table-- Shale explorers are facing almost $12 billion in losses this year from bad bets on oil after a global rally, according to BloombergNEF. Of the 50 U.S. drillers surveyed by BNEF, Devon Energy Corp., Pioneer Natural Resources Co. and Diamondback Energy Inc. are on track to rack up the steepest losses, with more than $1 billion in underwater hedges apiece. The sector as a whole hedged almost one-third of estimated 2021 output and the practical impact is that they are locked in to reap about $5 less than the American benchmark crude, West Texas Intermediate. “One of the negatives of this quarter has been some horrible hedging; guys locked in at $42 a barrel,” Paul Sankey, the veteran oil-industry analyst and founder of Sankey Research LLC, said during an interview on Bloomberg TV. Hedging helps producers of raw materials mitigate the risk of major price fluctuations and lock in relatively stable cash flows. But the practice carries the risk of leaving money on the table during bull markets. The losses haven’t been limited to crude drillers. EQT Corp., America’s biggest natural-gas producer, irritated investors last week by boosting hedges at a time when the commodity also is surging. The company already has booked a $1.3 billion non-cash second-quarter loss on swaps and options contracts.
Environmental Groups Want Agency To Review Climate Impacts Of Superior Gas Plant -Environmental and indigenous groups want a federal agency to take another look at the environmental and climate impacts of a proposed $700 million natural gas plant in Superior. Four organizations, including the Sierra Club and Clean Wisconsin, are petitioning the Rural Utilities Service to conduct a supplemental environmental assessment of the project proposed by La Crosse-based Dairyland Power Cooperative and Duluth-based Minnesota Power. Dairyland Power plans to seek a loan from the agency for its share of the project.The agency previously found that construction and operation of the 625-megawatt plant would have no significant environmental impact. But the groups argue the agency didn't evaluate cumulative climate impacts of the plant in its environmental assessment"This facility would emit 3 million tons of carbon every year for at least 30 years if it's built, and there's just no way to get to zero carbon if we keep building things that emit carbon," said Katie Nekola, general counsel for Clean Wisconsin. Clean Wisconsin and the Sierra Club are also suing the Wisconsin Public Service Commissionover its approval of the project, noting regulators didn’t review the climate impacts of the proposal. They say the U.S. Department of Agriculture Rural Utilities Service must respond to their petition before making a decision on financing for the project.Gov. Tony Evers has set a goal for Wisconsin to go carbon-neutral by 2050. At the federal level, President Joe Biden has set a goal for the power sector to go carbon-neutral by 2035 and reach net-zero emissions by 2050.The two power providers are seeking to build the plant as part of plans to transition away from coal to renewable energy.
Minnesota regulators scold natural gas providers for cost run-up during February storm - Minnesota utility regulators Thursday approved a plan that would give consumers extra time to pay a colossal $660 million natural gas tab stemming from a historic February storm — while ripping the gas industry's role in the fiasco. In fact, the Minnesota Public Utilities Commission (PUC) indicated that some of that $660 million could eventually be recouped by consumers as an investigation continues into how the state's utilities might have mishandled the February gas-supply crisis. Several PUC commissioners Thursday questioned the functionality of a market that allowed Midwest wholesale prices to spike at least 4,500% — and saddle some Minnesota consumers with extra charges amounting to 50% of their annual gas bill. "This kind of behavior in the marketplace is inappropriate in a regulated industry," said Commissioner John Tuma, pointing out reports of price gouging by gas industry middlemen during the storm. "We need to figure out what happened and figure it out quickly." Then, talking specifically about Minnesota's utilities, Tuma said: "I don't think you realize how significant this was and how it will move us away from gas. ... It has changed my worldview as to how natural gas fits into our energy [system] in Minnesota." Commissioner Joe Sullivan concurred, saying the gas system "is extremely vulnerable."
Enbridge Sees Space for Fossil Fuel Infrastructure in Energy Transition, Expects Line 3 Gains by Year’s End - Enbridge Inc. has assured shareholders that it would stay strong by adapting to the energy transition even as the Canadian midstream giant faces ongoing opposition from fossil fuel foes over its projects. “We believe that in all practical scenarios our assets will remain critical to supporting long-term energy demand,” said Enbridge President Al Monaco as the firm’s Calgary head office released mid-year financial results.“Existing infrastructure is going to play a key role in the transportation and storage of future energy supplies, ensuring affordable and reliable access to conventional and low-carbon energy.”Enbridge reported that the biggest, most contested item on its project agenda – the $2.6-billion Minnesota leg in its Line 3 oil pipe replacement project – has stayed on track by defeating court challenges and surviving right-of-way protest rallies.“With the Canadian, North Dakota and Wisconsin segments complete, and Minnesota construction progressing well, we expect Line 3 to be fully in service during the fourth quarter,” Monaco said. “Line 3 is first and foremost a critical integrity project that will improve safety and further reduce environmental risks.”Financial gains from the project are expected by the end of this year as shippers pay tolls to use the new pipe that will add 370,000 barrels daily to Line 3capacity by enabling it to restore full operating pressure after a decade of safety restrictions on the old conduit.Monaco added that Enbridge continues to advance a C$17-billion array of pipeline, gas utility, hydrogen, and renewable power projects across Canada and the United States, and overseas in France.
Line 3 pipeline to be in service by end of year, despite legal challenges: Enbridge-- Enbridge Inc.'s Line 3 pipeline replacement is on track to be in service by the end of the year despite ongoing protests and recent court challenges, the Calgary-based company said Friday. The $9.3-billion project — which is expected to add about 370,000 barrel per day of crude oil export capacity from Western Canada into the U.S. — was handed a victory last month by the Minnesota Court of Appeals, which affirmed the approvals granted by independent regulators that allowed construction on the Minnesota leg to begin last December. However, Indigenous and environmental groups opposed to the project have appealed to the Minnesota Supreme Court, asking it to overturn the lower court's ruling. The Minnesota Supreme Court has until mid-September to decide whether or not to hear the case. In a conference call with analysts Friday, Enbridge chief executive Al Monaco said in spite of the recent legal challenges, Line 3 remains on schedule and is now 80 per cent complete. "Construction-wise, we're tracking to schedule," Monaco said. "We're moving along well and continue to work on water crossings. All that to say, we're on track for a Q4 in service." The Line 3 replacement will carry oil from Alberta to Enbridge's terminal in Superior, Wisconsin. The Minnesota leg of the project — the last section remaining to be completed — has been met by protests along the route, with more than 500 demonstrators having been arrested or issued citations since December. Opponents of the project — including Indigenous groups the White Earth Band of Ojibwe and the Red Lake Band of Chippewa, as well as environmental groups like the Sierra Club and Honor the Earth — say the Line 3 expansion will accelerate climate change and also poses a risk of oil spills in environmentally sensitive areas. The Line 3 expansion is a critical project for Canada's energy sector, which has been hamstrung by a lack of pipeline infrastructure in recent years. An IHS Markit report from December found that delays in the expansion of the export pipeline capacity have contributed to lower prices in Western Canada, representing a loss of $17 billion for the crude oil industry over the last five years.
Public may not know Enbridge's progress on Line 3 jobs promises until construction ends - Enbridge pledged to hire thousands of local workers for its Line 3 pipeline project. But we may not know whether they fulfilled that promise until the pipeline is completed. The Canadian energy company’s pledge to create jobs in rural communities was a major selling point for the $4 billion project. But Enbridge only has to publicly report worker residency numbers annually, according to a Public Utilities Commission project permit, and an update isn’t due until after November 2021. The pipeline is more than 60% complete and scheduled to be operational by the fourth quarter of this year, Enbridge says. When asked Tuesday if Enbridge would share recent worker residency numbers or planned to provide an update before November, spokesperson Juli Kellner said the company is “on track with reporting per the PUC Line 3 Replacement permitting requirements.” Enbridge signed an agreement with four unions in December 2019 that guaranteed only union workers would be hired for Line 3 construction jobs. The company has repeatedly said it expected to fill about half the 4,200 jobs with local workers. Enbridge’s worker residency report filed in February covered hiring through Dec. 31, the first month of construction. About 33% of the 4,600 workers were from Minnesota, and they had put in roughly 28% of hours worked on the project. Kellner said Tuesday the labor agreement stipulates that contractors supply half the workforce, and local union halls provide the other half. The local union halls often include members in neighboring states, she said.
Indigenous TikTok Creators Banned Over Pipeline Protest --After live streaming police violently crashing a religious ceremony and Pipeline 3 protest at Red Lake Treaty Camp—where cops threw down a protestor and ripped their shirt—TikTok banned the account of the person who filmed it, @Quiiroi, a Two Spirit Indigenous educator.The ban lasted for over a week.“About halfway during the ceremony, I went to sit down and take a break, I hear screams [and] I come rushing with my camera, I immediately [turned] my live stream on. Police were there holding a line,” they told the Daily Dot.Pipeline 3 is a pipeline expansion by oil company Enbridge that cuts across native land in the Midwest.The livestream by Quiiroi showed police officers from local counties attacking and arresting protestors. That including five to six officers slamming Alex Golden Wolf, a Two Spirit Indigenous leader of the White Earth Nation, to the ground and tearing their shirt before arresting them. “They showed up with tear gas and rubber bullets and guns. We’re in camping gear. I was wearing this camisole and flip flops. And a bandana to keep the sun off the top of my head,” Quirroi said. “Why are [the police] in riot gear?”Over 20 protestors were arrested in the police raid and taken to Pennington County, Minnesota jail.
Pipeline protester convicted -- Brock Hefel, 25, of Dubuque, Iowa, was found guilty in Hubbard County District Court of charges related to his opposition to the Line 3 pipeline replacement project.According to a press release from the Hubbard County Attorney’s Office, Hefel was charged with one count each of unlawful assembly and obstructing a public right of way, based on incidents that occurred on June 15.Assistant County Attorney Anna Emmerling prosecuted the case. After a two-day trial, the jury found Hefel guilty of both charges and was taken into custody to await sentencing, the release states. According to the Hubbard County Sheriff’s Office, Hefel was also arrested on July 27 in Hubbard County after he and another man locked themselves in a “sleeping dragon” device and crawled more than 1,500 feet inside a section of pipe at a Line 3 work site in Straight River Township.
Shot with Rubber Bullets, Hospitalized, Jailed: Line 3 Protester Tara Houska Decries Police Attack | Democracy Now! - (video & transcript) At least 20 water protectors were brutally arrested in Minnesota as resistance to the Enbridge Line 3 pipeline continues, and they say state and local police have escalated their use of excessive force, using tear gas, rubber and pepper bullets to repress opposition to Line 3, which, if completed, would carry Canadian tar sands oil across Indigenous land and fragile ecosystems. “The level of brutality that was unleashed on us was very extreme,” says Indigenous lawyer and activist Tara Houska, who suffered bloody welts after she was shot with rubber bullets, then arrested and held in Pennington County Jail over the weekend, where several water protectors say they were denied medical care for their injuries, denied proper food and some reportedly held in solitary confinement. AMY GOODMAN: We end today’s show in Minnesota, where at least 20 water protectors were brutally arrested over the weekend as resistance to the Enbridge Line 3 pipeline continues. Water protectors say state and local police have escalated their use of excessive force, using tear gas, rubber and pepper bullets to repress Line 3 protesters. On Sunday, Indigenous lawyer and activist Tara Houska published photos of herself on social media with bloodied welts on her arms after she was shot with rubber bullets during an action last week. Houska and 19 others were held in Pennington County Jail over the weekend, where several water protectors say they were denied medical care for their injuries, were denied proper food, and some were reportedly held in solitary confinement.Well, Tara Houska joins us now for more from the Namewag Camp in Minnesota, founder of the Giniw Collective and is Ojibwe from Couchiching First Nation.Welcome back to Democracy Now!, Tara. Can you describe what happened when you were arrested and the escalation of force that the police are using against you?
New front in Line 3 legal fight: Wild rice is plaintiff in lawsuit against DNR - Opponents of the new Line 3 oil pipeline being built across northern Minnesota have argued for years that it endangers dwindling stands of wild rice, a plant sacred to many Indigenous people.Now, the wild rice is speaking up for itself. The water-dwelling plant is the lead plaintiff in a novel lawsuit by the White Earth Band of Ojibwe against the Minnesota Department of Natural Resources (DNR). The legal action comes during a summer of intense protest and demonstration as the pipeline nears completion.The complaint, filed Wednesday in White Earth Nation Tribal Court, advances a paradigm-shifting legal theory that nature itself has rights to exist and flourish and is not simply human property.Some might call the argument extreme, others might call it ancient.It's the first "rights of nature" case brought in a tribal court in the U.S., according to Frank Bibeau, a lawyer for the White Earth tribe, and the second such case to be filed in any court in the U.S. In April, what is considered the first case of its kind was filed in Florida.Plaintiffs include manoomin (the Ojibwe word for wild rice that translates to "good berry"), several White Earth tribal members and Indian and non-Indian Water Protectors who have demonstrated along the 340-mile Line 3 construction route in Minnesota.They accuse the DNR of failing to protect the state's fresh water by allowing Calgary-based Enbridge to pump up to 5 billion gallons of groundwater from construction trenches during a devastating drought. Further, they assert the regulator has violated the rights of manoomin along with multiple treaty rights for tribal members to hunt, fish and gather wild rice outside reservations.They want the state to stop the extreme water pumping and for authorities to stop arresting people for trying to defend codified rights."We're not protesting, we're defending," Bibeau said. "It's 2021 now and a bunch of us have been to law school. We're not going to let this happen to us. We know what our rights are."To date, more than 700 people have been charged in demonstrations along the Line 3 construction route, according to Bibeau. Some have chained themselves to equipment or taken other actions to disrupt construction. There have been claims of police brutality.
Three wells on fire in Dakota Prairie Grassland -Three wells are on fire in the Little Missouri National Grassland a half mile south of Lake Sakakawea, according to reports heard Tuesday during the North Dakota Industrial Commission, and the North Dakota Department of Environmental Quality has issued an air quality advisory for residents of the area.Air quality in the area may be monitored athttps://www.airnow.gov. DEQ officials say the state’s ambient air-quality network is well positioned to monitor the air quality in the area around the fire.“Many weather apps specify local Air Quality Index (AQI). Air quality conditions can change hourly and may be impacted by local weather patterns — such as western forest fire smoke — or localized incidents,” said Environmental Scientist Adam Rookey.People sensitive to particle pollution should consider reducing their outdoor exposure during periods of moderate to poor AQI. Always contact your healthcare provider immediately if you are experiencing trouble breathing.Department of Mineral Resources Director Lynn Helms told NDIC Commissioners the fires can be seen all the way to Tioga, and that he has been told the wells should be out by the end of the week. The company, involved, Petro-Hunt, has brought in Wild Well Control to assist them in removing surrounding equipment to safely shut the wells down at the location.Petro-Hunt spokeswoman Beth Babb said the fire started about 1:35 p.m. Thursday, July 22 in McKenzie County.No injuries were caused by the fire, and no surface grassland or groundwater sources have been affected.“The company’s focus is to get the fire out as quickly and safely as possible,” Babb told the Williston Herald.The incident has been contained to the well pad so far, and a fire suppression plan is in place in case a wildland fire is triggered, according to a release from Dakota Prairie Grasslands. There is also a monitoring plan in place for when the incident is over. “Petro-Hunt, brought in resources and set up its incident command post as well as several med-evac and staging areas over the weekend,” Lucas Graf told the Williston Herald. “They expect the fire to continue for another week before conditions are safe enough to get their well specialist team in to reestablish control.”
Western North Dakota oil well fire burns into 12th consecutive day— An oil well fire bordering Lake Sakakawea in McKenzie County burned into its 12th day on Monday, Aug. 2, with emergency responders continuing to fight intense flames and temperatures in order to get three ruptured wells under control. Smoke has been visible from miles away since the fire began on Thursday, July 22, and state officials, local emergency responders and the company operating the wells said they have few updates to report on the status of the fire since the end of last week. The fire is burning in three of four oil wells on a well pad north of Keene and a half-mile south of the lake. The wells are operated by the Texas-based producer Petro-Hunt. Last week, North Dakota Oil and Gas Director Lynn Helms attributed the fires to the failure of a blowout preventer, a crucial mechanical valve used to stop the uncontrolled release of oil. Lucas Graf, a district ranger with the U.S. Forest Service in McKenzie County, said Petro-Hunt and responders are hoping to have the well pad under control and the fire extinguished “in the next couple of days” or by the end of this week, depending on weather conditions and other factors at the well site. Responders over the weekend made an unsuccessful attempt to plug the first blown-out well, Graf said, and are expecting to make a second attempt in the next couple of days. In an email, Petro-Hunt spokesperson Beth Babb said, “the situation is dynamic and completely dependent on well and weather conditions.” She added, “We are still focusing all of our attention on getting the fire extinguished, along with our well control contractor.” Last week Petro-Hunt brought in the oilfield emergency response company Wild Well Control, also based in Texas, for on-site assistance. Several local and state departments have also sent responders to the scene in the last week. As of Monday afternoon, Wild Well Control was still moving burnt equipment out of the way to establish a clear path to the wells, Department of Mineral Resources spokesperson Katie Haarsager said in an email. Graf said that responders have successfully killed the fourth well on the site to avert another blowout preventer failure, and have constructed a barrier blocking the three burning wells from the fourth. Graf added that Petro-Hunt has reported to the Forest Service that one of the three wells has blown-out more severely than the others, making that one the highest priority to plug. “It's still a highly technical and difficult process, of course, to regain control of the other two, but I think it's really the first one that will be the biggest challenge,” he said. Initial reports from Petro-Hunt to the state said 100 barrels of oil and 100 barrels of produced water spilled at the site. Dave Glatt, Director of the Department of Environmental Quality, said he’s taking those figures with a grain of salt for now, since it’s difficult to know the extent of the spill until the fire is extinguished.
That Petro-Hunt Pad Well Fire North Of Charlson -- It's Still Burning -- Update -- August 3, 2021 -- See this post for background to this story. See also this post. 12th consecutive day: the oil well fire continues to burn. This story was posted at 6:05 p.m., August 2, 2021, Monday night. Twelve days and they "hope" to have the fire out by the end of the week. Are we talking almost three weeks? Eighteen days? Responders have continued to battle intense flames and temperatures in an effort to extinguish fires in three oil wells near Lake Sakakawea in McKenzie County. Officials are aiming to regain control of the wells and douse the fires by the end of the week. ... in order to get three ruptured wells under control. ... fire began July 22, 2021, Thursday ... ... and the company operating the wells said they have few updates to report on the status of the fire since the end of last week ... ... one-half mile south of the lake .. ... NDIC Lynn Helms said the fires were due to the failure of a blowout preventer ...a valve used to stop the uncontrolled release of oil ... ... an unsuccessful attempt to plug the first blown-out well, Graf said, and are expecting to make a second attempt in the next couple of days. .... As of Monday afternoon, Wild Well Control was still moving burnt equipment out of the way to establish a clear path to the wells, Department of Mineral Resources spokesperson Katie Haarsager said in an email. Graf said that responders have successfully killed the fourth well on the site to avert another blowout preventer failure, and have constructed a barrier blocking the three burning wells from the fourth. ...one of the three wells has blown-out more severely than the others, making that one the highest priority to plug.
Dakota oil pipeline expansion completed: Update - An expansion of Energy Transfer's 570,000 b/d Dakota Access crude pipeline (DAPL) is complete, adding takeaway capacity out of the Bakken shale.The capacity on DAPL has been increased by 180,000 b/d to 750,000 b/d, Energy Transfer said today.There has been a "significant increase" for August nominations as minimum volume commitments on the expanded DAPL capacity kicked in at the start of the month, Energy Transfer said.The company has said previously that it plans to expand DAPL to as much as 1.1mn b/d by adding pump stations. Other partners in the Bakken system include Enbridge and Marathon Petroleum's midstream affiliate, MPLX.The expansion will include the entire Bakken system which includes DAPL from the Bakken shale to Patoka, Illinois, and the connecting Energy Transfer Crude Oil pipeline (ETCOP) to the US Gulf coast. The expansion does not require any construction on the mainline or building new pipeline segments.Earlier today, a partner in the Bakken system, Phillips 66 Partners said that the Bakken optimization project "continues to progress with the next phase of incremental capacity commencing service in August."The increased capacity is supported by minimum volume commitments from long-term contracts, Phillips 66 Partners said.A US judge in June closed out a long-running lawsuit that sought to halt operations of DAPL, two months after ruling the pipeline could remain in service while the government prepares a new environmental review.US district court judge James Boasberg dismissed the rest of a lawsuit filed by Native American tribes led by the Standing Rock Sioux who oppose the pipeline. The order brought an end to a high-profile case that attracted national attention because of its potential to shut a major conduit of Bakken crude to the US midcontinent and Gulf coast. Energy Transfer said today that it continues to cooperate with the Army Corps of Engineers on the new DAPL environmental review.
Company fined $35M in North Dakota drilling wastewater spill — An oil company that waited more than five months to investigate and report a 2014 pipeline spill in North Dakota that discharged more than 29 million gallons of drilling wastewater has agreed to pay more than $35 million in civil and criminal fines. the U.S. Department of Justice said Thursday. Federal officials said it's the largest inland drilling spill of produced water, a waste product of hydraulic fracturing, or fracking. The spill from the 96-mile (154.50-kilometer) underground pipeline contaminated more than 30 miles of Missouri River tributaries as well as land and groundwater, the complaint said. It was visible in photographs taken by satellites.The complaint against Summit Midstream Partners LLC says the data collected by the company in August 2014 showed a significant drop in the pipeline pressure, indicating a rupture in the newly built line. Despite concerns raised in October 2014 by Summit's construction manager and engineer, the company did not identify the leak until January 2015, after an employee walked the line.Court documents show that Summit’s construction manager sent an email to other employees in October 2014 about “extreme low pressure” on the system. The facilities engineer responded: “Not good. We may want to consider shutting it down.” Summit continued to operate the line.Summit eventually reported a 2.9 million gallon spill of produced water even though the leak was 10 times larger, according to the civil complaint filed against Summit and related companies, Meadowlark Midstream Company LLC and Summit Operating Services Company LLC.
Trump’s ANWR Drilling Leases Under Review: Biden Admin Looking at 'Legal Deficiencies,' Environmental Impacts
Biden administration kicks off second look at Arctic refuge drilling -The Biden administration is formally launching its review of the Trump administration’s opening of the Arctic National Wildlife Refuge to drilling after a prior determination that its predecessor’s action had “legal deficiencies” The Interior Department announced the review in a notice of intent scheduled to be published in the Federal Register on Wednesday, which indicated that it would carry out a rigorous environmental review known as an environmental impact statement. The review will serve “to identify the significant issues, including any legal deficiencies in the Final EIS [Environmental Impact Statement],” Laura Daniel-Davis, principal deputy assistant secretary for land and minerals management, said in the notice. The supplemental EIS ordered by the department will analyze the potential effects of leasing on surface waters, wetlands and vegetation, as well as wildlife such as caribou, birds and polar bears and the greenhouse gas emissions caused by leasing activity. It will also consider possible alternatives such as declaring some areas of the Coastal Plain off-limits to leasing, banning surface infrastructure in “sensitive areas” and barring more than 2,000 acres of surface development across the Coastal Plain. The formal announcement in the Federal Register notice follows an announcement made in June that there will be a further environmental review after the Biden administration said that it found the legal deficiencies in the formal decision that opened up the refuge for drilling. This included what Interior Secretary Deb Haaland described as a “failure to adequately analyze a reasonable range of alternatives" in the prior environmental review. A 2017 law passed during the Trump years required at least two lease sales — one of which has already occurred — by the end of 2024, so an attempt to completely reverse could present legal difficulties. But the Biden administration could put new stipulations on drilling. It has also indicated that it may seek to make changes to existing leases, saying in June that after the review they would either be reaffirmed, voided or subject to additional measures to lessen their environmental impacts. In the meantime, the leases are suspended. The Federal Register notice formally starts the public scoping process for the review, during which the public is allowed to weigh in with comments. While many environmentalists oppose drilling in the refuge, some called on the Biden administration and Congress to go even further. “The Trump administration aggressively moved to get leases into the hands of oil companies prior to the end of its only term, and until those leases are canceled and the Arctic Refuge drilling mandate reversed, one of the wildest places left in America will remain under threat,” Kristen Miller, acting executive director for the Alaska Wilderness League, said in a statement. "We call on the Biden administration to work with Congress to repeal the oil leasing mandate and buy back those leases as part of the upcoming budget package, restoring protections to the Arctic Refuge coastal plain.”
Groups Welcome Biden Review But Demand Congress Permanently Protect Arctic Refuge From Drilling - Alaska Native News -Indigenous and environmental groups on Tuesday welcomed the U.S. Interior Department’s decision to review the Trump administration’s controversial move opening up previously protected land in Alaska to drilling despite threats to local communities and wildlife as well as the global climate. The department’s notice says the new environmental review of the leasing program for oil and gas drilling in the Coastal Plain of the Arctic National Wildlife Refuge (ANWR) will “identify the significant issues, including any legal deficiencies” in a Trump-era analysis. In a statement, Sovereign Iñupiat for a Living Arctic (SILA) expressed appreciation for “the Biden administration’s intention to address the insufficiencies and legal violations in the prior administration’s oil and gas leasing program.” The group also called for Congress to repeal the program entirely, noting the key role that federal lawmakers played in opening ANWR up to the fossil fuel industry. “We look to our representatives in Congress to now step up and do their share of the work in protecting this land that provides for Iñupiat and Gwich’in communities,” SILA said. “It is time to protect the refuge and rescind the leasing program from the Tax Cuts and Jobs Act of 2017.” “We remind members of Congress that traditional Iñupiat values include hunting traditions, respect for nature, and spirituality, all of which this law impacts in our communities,” SILA added. “Please, act now to move to change laws that will impact Iñupiat communities, Gwich’in communities, and the rest of the world.”
ConocoPhillips Posts Highest Profit Since 2018 -- ConocoPhillips beat estimates as rising commodity prices led America’s biggest independent oil producer to the highest profit in nearly three years. Conoco posted adjusted earnings of $1.27 a share in the second quarter, compared with the $1.13 estimate in a Bloomberg survey of analysts. The stock rose 1.9% in pre-market trading. U.S. energy companies are using buybacks and dividends to attract investors to the sector after years of poor performance left it making up just 2.6% of the S&P 500, down from more than 12% a decade ago. Conoco became one of the first large energy companies to increase shareholder returns in response to high commodity prices when it lifted its share buyback by two thirds to $2.5 billion a year in June. As such there was little expectation the company would further increase cash returns. CEO Ryan Lance has been lowering capital spending and slowing production growth as part of a pledge to reinvest only half of its cash flow in new drilling and return the rest to shareholders. The promise underscores how U.S. oil producers are maintaining production discipline and are unlikely to go back to high growth rates seen in the past. A key question is what Conoco executives plan to do with the company’s cash pile worth about $7 billion. The company is said to be among several suitors for Royal Dutch Shell Plc’s Permian Basin assets, worth as much as $10 billion, people familiar with the matter said last month. The U.S. shale patch has become a hotbed of merger activity this year, and Conoco secured the biggest deal to date with the $13 billion stock purchase of Concho Resources Inc.
Oil giant BP ups dividend and confirms share buybacks as it posts better-than-expected profit— Oil and gas giant BP beat second-quarter earnings expectations on Tuesday, while expanding its dividend and share buyback program. The U.K.-based energy major said it will buy back $1.4 billion of its own shares in the third quarter on the back of a $2.4 billion cash surplus accrued in the first half of the year. It also increased its dividend by 4% to 5.46 cents per share, having halved it to 5.25 cents per share in the second quarter of 2020. It anticipates buybacks of around $1 billion per quarter and an annual dividend increase of 4% through 2025, based on an estimated average oil price of $60 per barrel. The energy major posted full-year underlying replacement cost profit, used as a proxy for net profit, of $2.8 billion. That compared with a loss of $6.7 billion over the same period a year earlier and $2.6 billion net profit for the first quarter of 2021. Analysts polled by Refinitiv had expected second-quarter net profit of $2.06 billion. CEO Bernard Looney told CNBC on Tuesday that a combination of strong underlying performance, an improving balance sheet and higher commodity prices had enabled the company to up its returns to shareholders. "We have raised our own plan from $50 to $60 (average oil prices) for the next several years — that is on the back of strong demand. GDP is back to pre-pandemic levels and the vaccines are clearly working, OPEC+ is holding discipline and supply is tightening, particularly in U.S. shale," he said. The results reflect a broader trend across the oil and gas industry as energy majors seek to reassure investors they have gained a more stable footing amid the ongoing coronavirus pandemic. The British-Dutch multinational Royal Dutch Shell, France's TotalEnergies and Norway's Equinor all announced share buyback schemes last week. Share prices of the world's largest oil and gas majors are not yet reflecting the improvement in earnings, however, and the industry still faces a host of uncertainties and challenges.
Subsidies really do prop up the oil and gas industry. Here's the most important one to get rid of -Fossil fuel subsidies are a vexed and peculiar topic. On one hand, everyone seems to agree they're bad and should be eliminated (Biden’s jobs bill takes aim at them, for instance). On the other hand, they never go away.In part, this is because we lack a clear understanding of what constitutes a subsidy and what impact subsidies have. Analysts are forever arguing over exactly what counts, trying to tally up the total subsidies fossil fuels receive, but there are very few bottom-up attempts to document the concrete effects of subsidies on the economics of oil and gas projects.That’s why I was interested in this new paper in Environmental Research Letters, by Ploy Achakulwisut and Peter Erickson of the Stockholm Environment Institute and Doug Koplow of Earth Track. It breaks down the effect of 16 specific, direct U.S. fossil fuel subsidies on the profitability and emissions of U.S. oil and gas production.As for those subsidies, there are three basic categories: “forgone government revenues through tax exemptions and preferences; transfer of financial liability to the public; and below-market provision of government goods or services.” (Note that this study does not get into unpriced environmental externalities like air pollution and greenhouse gases, which are themselves a kind of subsidy.)To take just a couple of examples, the effect a subsidy will have on the decision of whether to invest in a new oil and gas project will depend on oil and gas prices and the hurdle rate. (The hurdle rate is the rate of return investors require to fully cover risks; more aggressive decarbonization efforts will presumably mean more risk and thus a higher hurdle rate.) The study actually runs several different scenarios based on different values for those variables, producing a cost curve for each region of the U.S. It gets complicated.What’s interesting is that the benefits to oil and gas are not spread evenly over different subsidies. In fact, one in particular dwarfs the others: the expensing of intangible exploration and development costs (“intangible drilling costs,” or IDC), a policy that’s been around for over a century. The chart below shows the “average effect of each subsidy on the internal rate of return (IRR) of new, not-yet-producing oil and gas fields, at average 2019 prices of USD2019 64/barrel of oil and USD2019 2.6/mmbtu of gas.”
Democrats Seek $500 Billion in Climate Damages From Big Polluting Companies – NYTimes - Under a draft plan Democrats are circulating, the Treasury Department would tax a handful of the biggest emitters of planet-warming pollution to pay for climate change. — Democrats in Congress want to tax Exxon, Chevron and a handful of other major oil and gas companies, saying the biggest climate polluters should pay for the floods, wildfires and other disasters that scientists have linked to the burning of fossil fuels. The draft legislation from Senator Chris Van Hollen of Maryland directs the Treasury Department and the Environmental Protection Agency to identify the companies that released the most greenhouse gases into the atmosphere from 2000 to 2019 and assess a fee based on the amounts they emitted. That could generate an estimated $500 billion over the next decade, according to Mr. Van Hollen. The money would pay for clean energy research and development as well as help communities face the flooding, fires and other disasters that scientists say are growing more destructive and frequent because of a warming planet. The bill for the largest polluters could be as much as $6 billion annually spread over 10 years, according to a draft of the plan. “It’s based on a simple but powerful idea that polluters should pay to help clean up the mess they caused, and that those who polluted the most should pay the most,” Mr. Van Hollen said in an interview. “Those who have profited the most should help now pay the damages that they’ve already caused.” The proposal comes as the Senate prepares to vote on a bipartisan $1 trillion infrastructure package that includes billions of dollars to help communities prepare for and recover from extreme weather driven by climate change. Democrats hope to later pass a separate $3.5 trillion budget package that will include measures to cut carbon dioxide, methane and other greenhouse gases that result from burning fossil fuels and that are helping to drive up global temperatures. A tax on polluting companies has the support of liberal lawmakers including Senator Bernie Sanders, the Vermont independent, as well as Senators Edward J. Markey and Elizabeth Warren of Massachusetts and Sheldon Whitehouse of Rhode Island, all Democrats. Mr. Van Hollen says he is optimistic that his legislation will find broad support within his party and be attached to the budget reconciliation package, which Democrats hope to pass without Republican votes. But that would require all Democrats in the narrowly divided Senate to back the measure, including Joe Manchin III of West Virginia, who has routinely argued against anti-fossil fuel legislation.
Big Oil spent $10 million on Facebook ads last year — to sell what, exactly? --Online advertisers are always trying to sell you something, and in the case of slip-on sneakers or leather handbags, that something is pretty clear. But other times, the motive behind a sponsored post is less transparent. Why, for instance, are oil companies buying prime space in your social media feed to prattle on about “innovative” climate solutions and visions of a “lower-carbon future”?A new report makes the case that the oil and gas industry is trying to sell you a story — one that casts these companies as paragons of sustainability and seeks to delay policies that would address climate change. Last year, the oil and gas industry spent at least $9.6 million on ads on Facebook’s U.S. platform, according to an analysis by the think tank InfluenceMap. Just over half of this spending came from one company, ExxonMobil.“The oil and gas industry is engaging in this really strategic campaign using social media and the tools available, particularly these targeting tools on Facebook, to reach a really broad audience pretty easily,” said Faye Holder, program manager at InfluenceMap.The report looked at roughly 25,000 of these ads, analyzing their messages and whom they were targeting. The decision to focus on Facebook ads, which represent only a fraction of the oil industry’s wider campaign to influence the discourse on climate change, was made for data reasons. “We just looked at Facebook,” Holder said. “That is because the other social media platforms don’t even offer this transparency.”Oil companies have long sought the help of public relations whizzes to burnish their reputations, painting themselves as environmental champions, plastering their logos all over science museums and jazz festivals, and even hiring Instagram influencers to tout the merits of gas stoves. In recent years, climate advocates have honed in on ways to counter these tactics — launching a campaign demanding that PR firms drop fossil fuel clients, for instance, or trolling oil companies on social media. Some climate groups have decided to fight fire with fire, recently funneling $1 million directly into anti-oil advertisements.The oil industry’s more recent ads use subtler messages than outright climate denial to undermine action on global warming, such as portraying natural gas as a green fuel source and arguing that decarbonization would make energy unaffordable. Last year, companies’ Facebook ad spending soared when it looked like the federal government might do something to address rising emissions. For example, spending jumped dramatically last summer when then-presidential candidate Joe Biden released his climate plan, and stayed high until after the November election.
Russian supply curbs exacerbate squeeze on European gas market -Russia has exacerbated a shortage of European natural gas supplies that has driven prices to a 13-year high by quietly limiting top-up sales to customers, according to executives and analysts.Pipeline exports of natural gas from Russia’s state-backed monopoly Gazprom to continental Europe have dropped roughly one-fifth in 2021 on pre-pandemic levels despite a sharp rebound in demand and low stockpiles of the important fuel. The imbalance has helped send prices in Europe to the highest levels since 2008, increasing energy costs for homes and businesses. The rise in prices comes during a period of volatile relations between Russia and the West. On Wednesday, Russia said its forces fired warning shots at a British destroyer off the coast of Crimea, claims the UK denied. At the same time, Germany and France sought this week to cool tensions with Russia, proposing a new EU plan for closer engagement with Moscow. Energy industry executives and analysts said that while Gazprom was meeting its long-term contractual obligations, its reluctance to boost supplies to Europe through more immediate measures such as spot market sales was putting pressure on the market. “Gazprom is just trying to maximise its profits at a time when spot prices are high, gas storage is empty and LNG demand in Asia is strong,” said one executive at a German energy company. “They’re just being opportunistic.”Gazprom said in a statement that it “supplies gas precisely in line with consumers’ requests”. “It is based on those very requests as well as the possibilities for portfolio capacity optimisation that the company books transportation capacity in particular directions,” it added.Several industry participants said Gazprom’s moves appeared designed to support prices and may be aimed at pressuring EU governments to approve the controversial Nord Stream 2 pipeline to Europe.“Gazprom is effectively saying to the EU: ‘give us the green light for Nord Stream 2 and we will send you all the gas you need’,” said Tom Marzec-Manser, lead European gas analyst at ICIS. “‘Don’t, and we won’t. We’re not going to send the extra gas via Ukraine and you’ve seen what that means for wholesale prices in a tight global [liquefied natural gas] market,’” he added.
Russia Oil and Condensate Output Rises-- Russia increased oil production in July for the first time in three months, after more generous quotas were extended to the entire OPEC+ alliance. Producers pumped 44.24 million tons of crude and condensate last month, according to preliminary data from the Energy Ministry’s CDU-TEK unit. That’s about 10.46 million barrels a day, or 0.3% higher than in June, Bloomberg calculations show, based on a 7.33 barrels-per-ton conversion rate. It’s difficult to assess Russia’s compliance with the output-cut deal between the Organization of Petroleum Exporting Countries and its allies, as CDU-TEK’s data don’t provide a breakdown between crude and condensate, which is excluded from the deal. If Russia produced the same level of condensate as in June -- about 900,000 barrels a day -- then daily crude-only output would be some 9.56 million barrels, slightly above its July quota of 9.495 million barrels. Deputy Prime Minister Alexander Novak told reporters on Friday that the nation’s adherence to the deal would be about 100% in July. Russia’s compliance increased to 96% in June from 94% in May and 91% in April, the International Energy Agency said in its latest monthly report. Planned maintenance led to a drop in June’s crude-only volumes, according to the IEA. Under the deal with OPEC+, Russia was allowed to raise its crude-only production by a total of 116,000 barrels a day from May to July. Last month the alliance agreed to raise output by 400,000 barrels a day each month starting August, continuing until all of its halted output has been revived. That means that, starting August, Russia can increase its daily crude production by 100,000 barrels each month, according to Novak.
In four years, Nigeria loses 2.5trn oil barrels - Nigeria has lost 4.5 trillion barrels of oil to theft in the last four years, according to data from the Nigeria Natural Resource Charter (NNRC).Another data from the National Oil Spill Detection and Response Agency (NOSDRA) showed that the country recorded 4,919 oil spills between the period of 2015 to March 2021.The Ministry of Environment said this issue is a huge detriment to the environment and leads to a significant loss of revenue.Global statistics show that Nigeria loses around 400,000 barrels of oil per day, more than any other country in the world. However, mitigation measures through the enforcement of laws, regulations and guidelines such as the Environmental Impact Assessment (EIA) Act, are being taken to lessen the oil losses. For both oil spills and oil theft, it is recommended that transparency and accountability should be adhered to in the relations among government, oil-producing communities and multinational corporations.
China-Australia tensions create LNG trade uncertainty Rising political tension is creating concern for the China-Australia liquefied natural gas (LNG) trade, with other global LNG suppliers the potential beneficiaries of this tension. LNG is a vital resource supporting China’s push towards a cleaner energy mix. Over the past five years, reinforced by gas market reforms and infrastructure development, the country recorded double-digit gas demand growth across all sectors. Wood Mackenzie’s gas and LNG consultant, Xueke Wang, said, “The absence of Australian LNG could disrupt supply stability and increase the call on coal in the near term. “But in the longer term, it may also force China to turn to suppliers elsewhere, opening the door for rival exporters to increase their share of Asia’s largest LNG market.” Over the past decade, both Chinese National Oil Companies (NOCs) and private companies have acquired Australian upstream positions. Following the pandemic and oil price crash, Chinese overseas investment has slowed. And with rising trade tensions and new challenges in obtaining Australian Foreign Investment Review Board approval, new investment by Chinese companies in Australia is slowing. Ms Wang said, “In May, China suspended the China-Australia Strategic Economic Dialogue shortly after Australia cancelled its Belt and Road agreement. According to our sister company Verisk Maplecroft, this is one of a series of events that have inflamed diplomatic tensions and triggered a deep freeze in China-Australia trade relations. “China and Australia are now locked in a cycle of tit-for-tat policy action, and energy trade has been a key battlefield. If the situation deteriorates further, this could have a profound impact on China’s LNG market as Australian LNG makes up around half of China’s total LNG imports.” Chinese companies have a long history of participation in Australian upstream and LNG projects. China’s three NOCs – CNOOC, PetroChina and Sinopec – all have a large Australian LNG footprint.
Covid Batters Leading Asia Importer-- Indonesia’s Covid-19 crisis is hammering gasoline demand in Southeast Asia’s leading economy, echoing a slump in India earlier this year. Strict curbs on travel amid a surge in virus cases are taking a toll on consumption, with gasoline and diesel usage plummeting during the initial phase of restrictions from July 3-25. Shipments of gasoline into Asia’s biggest importer of the fuel have sunk almost a quarter, according to Vortexa Ltd. The drop-off in consumption highlights the threat to the energy market posed by the rapid spread of the delta coronavirus variant, including a flare-up in China. Indonesia has surpassed Brazil and India in daily cases and death counts to become a new global virus center, with confirmed cases jumping and fatality numbers hovering near a record. The hot spots in Asia have weighed on crude oil futures, which retreated for a second straight day on Tuesday. Indonesia’s gasoline demand from July 3-25 sank 14% from the previous month, according to PT Pertamina Patra Niaga, a unit of the nation’s state-owned energy company. Diesel usage fell about 9%, said Putut Andriatno, corporate secretary at Patra Niaga. With demand shrinking, imports of gasoline into the archipelago fell more than 23% from previous month to about 190,000 barrels a day in July, Vortexa’s Asia lead analyst Serena Huang said, citing provisional data. Imports last month were the lowest since May 2020, she added. Diesel imports increased. So far the slump hasn’t affected Asian margins for converting crude into gasoline, with plunging exports from China and better demand from other markets such a now-recovering India have more than compensated for the loss in Indonesian consumption. However, heavy rains in India and China may crimp regional gasoline demand near term, while tighter restrictions in Thailand will also weigh on the recovery, industry consultant FGE said in a note.
Fuel demand picks up in July, petrol at pre-Covid level - India's fuel demand picked up in July as easing of pandemic-related restrictions accelerated economic activity, helping petrol consumption reach pre-Covid levels, preliminary sales data showed on Sunday. State-owned fuel retailers sold 2.37 million tonnes of petrol in July, up 17 per cent from the year earlier period. It was 3.56 per cent higher than pre-Covidpetrol sales of 2.39 million tonnes in July 2019.Sales of diesel - the most used fuel in the country - rose 12.36 per cent to 5.45 million tonnes over the previous year, but was down 10.9 per cent from July 2019.This is the second straight month that showed a rise in consumption since March.Fuel demand had recovered to near-normal levels in March before the onset of the second wave of COVID-19 infections led to the re-imposition of lockdowns in different states, stalling mobility and muting economic activity.Consumption in May slumped to its lowest since August last year amid lockdowns and restrictions in several states. Fuel demand showed signs of resurgence in June after restrictions began to be eased and the economy gathered pace.On July 30, S M Vaidya, Chairman of India's largest oil firm IOC, had stated that petrol consumption has risen over pre-Covid levels as people prefer personal transport over public transport.Diesel sales, he said, were likely to return to pre-pandemic levels by Diwali in November if a third wave of Covid infections does not lead to reimposition of lockdown. ATF consumption, which had seen the most severe fall as air travel was restricted beginning March 2020, is likely to return to normal by the end of the current fiscal in March, he had said.
Mumbai: Juhu beach's sand turns black following oil spill – India TV (video) The sand on over 5 kilometre stretch of Mumbai's Juhu Beach turned black due to an oil spill on Thursday. People, who came for a walk in the morning today, said that the oil in the seawater was flowing towards the shore that has turned sand in black. However, it is still not clear how the oil spilled into the sea water.Mumbai Mayor Kishori Pednekar said that the administration will inspect the situation at the beach."I will assign a ward officer to inspect the oil on the Juhu Beach. We don't know the reason yet but, whenever we have the information we will share it," she told reporters."Usually we put sand over it but first we will inspect the situation," she added.A Twitter user, Dr Rajesh Sarwadnya, who was at the beach, posted a video and wrote: "Waves of oil Spill today on entire 6 km Juhu Beach"Pramod Virkar, a local resident said: "We have never seen oil in the beach and in the seawater, it has happened probably due to breakdown of a steamer."Another resident, Hari said, "The sand is sticky and we cannot walk on it. It will also harm the marine life and the environment."
The Saudi Arabia-UAE rift that froze OPEC is a sign of things to come, experts say - — The unexpected rift between Saudi Arabia and the United Arab Emirates within OPEC in early July came as a shock to many in the Gulf region and those watching from abroad. The dispute over oil production levels temporarily froze the group's ability to lay out its plans for the markets, sending crude prices upward. But it wasn't the first appearance of tension between the Arab neighbors and longtime close allies, and likely will not be the last, experts who've long been watching the region say. "What is happening here is these are the two biggest economies in the region, in the Arab world," Abdulkhaleq Abdulla, a political science professor in the UAE, told CNBC. "And as Saudi Arabia wants to reform its economy, privatize, etc, there is bound to be competition between them." "Competition between the two biggest Arab economies is, I think, just starting," Abdulla said. "And it is bound to intensify in the days to come." The strategic alignment between Riyadh and Abu Dhabi, both of which have become increasingly active on the world stage, is evident in many areas. And it's often associated with what is said to be a close relationship — some have even called it a "bromance" — between Saudi Crown Prince Mohammed bin Salman and his Emirati counterpart Mohammed bin Zayed. But conflicting interests have cropped up in recent months that preceded the OPEC rift. In February, Saudi Arabia announced that its government would cease doing business with any international companies whose regional headquarters were not based within the kingdom by 2024. The move waswidely seen as targeting Dubai, the Middle East's current headquarters hub. The UAE last year announced a normalization deal with Israel, becoming the first Gulf country to do so, while Saudi Arabia has so far publicly refused to do the same. Saudi Arabia meanwhile has been working on a tentative rapprochement with rival Sunni power Turkey, with which the UAE has significant tensions as Ankara supports an Islamist ideology that Emirati leaders see as a threat. And the two Gulf powers had some diverging interests in the war in Yemen, despite being on the same side, with the Saudis supporting an Islamist party distrusted by the UAE and Abu Dhabi supporting separatist tribes that did not align with Riyadh's goals. The UAE drew down its military activity in Yemen in 2019, while Riyadh remains embroiled in the conflict. "It has been a common assumption that the UAE and Saudi Arabia have effectively indistinguishable worldviews and interests — that the UAE is sort of an appendage or dependency of Saudi Arabia," Hussein Ibish, a senior resident scholar at the Arab Gulf States Institute in Washington, wrote in a blog post in July. "That has never been the case." In early July, Saudi Arabia upped the ante by ending preferential tariffs for goods made in free zones or affiliated with Israeli manufacturers, also seen as a direct shot at the UAE, which is the free zone hub of the region. The move was followed by waves of patriotic Saudis launching a campaign via Twitter to boycott Emirati goods. This came despite the fact that the UAE is Saudi Arabia's second-largest trading partner after China by import value. "The idea once was to create a GCC market, but now there's the realization that the priorities of Saudi Arabia and the UAE are very different,"
Rapid Iran Oil Comeback Now Looks Less Likely-- Iran’s oil comeback, already taking longer than many traders expected, will be further complicated by last week’s deadly drone attack on a tanker in the Gulf of Oman, which the U.S., U.K. and Israel all blamed on Tehran. With talks held up by a change of presidency in Tehran, the incident adds friction to a process that could return 1 million barrels of oil a day to the global market within months. Even if the allies decide against a military response, Washington may be less willing to ease sanctions on the Islamic Republic’s energy exports. “It looks inevitable that this will cast a black cloud over nuclear talks” between Iran and world powers including the U.S., said Bill Farren-Price, a director at energy-research firm Enverus. The negotiations -- to revive a 2015 pact that limited Iran’s atomic program in return for sanctions relief -- had already stalled. A sixth round in Vienna broke up last month. Diplomats are waiting for Iran to re-enter talks now that Ebrahim Raisi, an austere cleric who has long argued against a rapprochement with the U.S., has become president. Restoring the Joint Comprehensive Plan of Action -- which then-President Donald Trump pulled the U.S. out of in 2018 -- is key to Iran’s ability to increase oil production. Its crude exports have plummeted to almost nothing from more than 2 million barrels a day in mid-2018. Many oil investors had expected a new nuclear deal before Iran’s elections in mid-June. While Raisi and Supreme Leader Ayatollah Ali Khamenei could resume negotiations soon, there’s still much for the sides to overcome. Iran wants a guarantee that future U.S. administrations won’t withdraw from any deal, as Trump did. It also insists sanctions are removed across the board -- on its shipping and banking industries as well as on energy exports. Washington is wary of both demands. Another sticking point is the JCPOA’s so-called “break out” clause. It was designed to constrain Iran’s nuclear activities enough that it would need a full year to build a bomb if it chose to exit the accord. Some U.S. officials believe Iranian scientists have made enough progress in the past three years to construct an atomic weapon within a few months. Still, Iran and the U.S. have both said they’ll continue to negotiate. Washington sees a deal a way to help stabilize the Middle East -- even if it doesn’t address Tehran’s ballistic missiles or support for proxy forces in the likes of Yemen and Lebanon -- while sanctions have battered the Iranian economy.
Oil Prices Slide As China's Manufacturing Slows - Oil prices fell more than 1 percent on Monday after a survey found that growth in factory activity slipped sharply in China, the world's second-largest oil consumer. Brent crude oil futures for October delivery fell 99 cents, or 1.3 percent, to $74.42 a barrel, while U.S. West Texas Intermediate (WTI) crude futures for September settlement dropped 117 cents, or 1.6 percent, to $72.78 a barrel. Data released Saturday by the National Bureau of Statistics showed China's official purchasing managers' index fell to 50.4 in July from 50.9 in June, adding to concerns about a slowdown in the world's second-largest economy. It was the slowest figure since the index slumped to 35.7 in February 2020. China's Caixin/Markit Manufacturing Purchasing Managers' Index (PMI) fell to 50.3 last month from 51.3 in June, marking the lowest level in 15 months and prompting concerns about demand. Elsewhere, manufacturing activity rose in export powerhouses Japan and South Korea, though firms suffered from supply chain disruptions and raw material shortages that pushed up costs. The euro area manufacturing sector growth moderated in July but the pace of expansion remained elevated, final data from IHS Markit showed. The final factory Purchasing Managers' Index fell to 62.8 from 63.4 in June. This was the lowest reading since March.
Oil prices slip 4 percent as supply grows - Oil prices tumbled about 4 percent on Monday as weak economic data from China and the United States, the world’s top oil consumers, and higher crude output from OPEC producers stoked fears of weakness in oil demand and oversupply. Brent crude oil futures slid by $2.65, or 3.5 percent, to $72.76 a barrel by noon. US West Texas Intermediate crude dropped fell $2.91, or 3.9 percent, to $71.04. “The complex is reacting pretty strongly from the more bearish economic data from China and the US,” said John Kilduff, partner at Again Capital in New York. China’s factory activity growth slipped sharply in July as demand contracted for the first time in more than a year, a survey showed on Monday. The weaker results in the private survey, mostly covering export-oriented and small manufacturers, broadly aligned with those in an official survey released on Saturday. “China has been leading economic recovery in Asia and if the pullback deepens, concerns will grow that the global outlook will see a significant decline,” said Edward Moya, senior analyst at OANDA. US manufacturing activity also showed signs of slowing. The pace of growth slowed for the second straight month as spending rotates back to services from goods and shortages of raw materials persist, according to data from the Institute for Supply Management (ISM). The ISM’s index of national factory activity fell to 59.5 last month, the lowest reading since January, from 60.6 in June. Also weighing on prices, a Reuters survey found that oil output from the Organization of the Petroleum Exporting Countries rose in July to its highest since April 2020. The United States will not lock down again to curb COVID-19, but “things are going to get worse” as the Delta variant fuels a surge in cases, mostly among the unvaccinated, President Joe Biden’s chief medical adviser, Anthony Fauci, said on Sunday.
Delta Variant Causes Oil Prices To Tumble -Oil tumbled by the most in two weeks as a fast-spreading delta variant posed a threat to demand and as economic data out of China signaled a slowdown. Futures in New York declined 3.6% on Monday. The virus is clouding the outlook for consumption as China faced a fresh outbreak and infections in Sydney matched a record. Amid the surge in cases, barrels from some key OPEC producers are hitting the market, also causing concern. Meanwhile, data indicated that China’s economic activity eased in July. The government in China has made steps to curb commodity inflation and those are having an impact, according to Rebecca Babin, senior energy trader at CIBC Private Wealth, US. “The next round of data from China on crude import numbers will be critical in figuring out how China is handling the most recent uptick in infections,” she said. Crude prices are off to a shaky start in August after July’s small gain with the resurgence of Covid-19 offsetting the global demand recovery. Saudi Arabia, Kuwait and the United Arab Emirates, three core OPEC oil exporters in the Middle East, boosted their crude shipments to multimonth highs in July, underscoring a return of the nations’ supply into an uncertain global market. Oil has “given back some of last week’s gains in response to weaker China data and continued worries about the spread of the delta variant,” Crude has settled into a range “with delta demand worries offsetting the current tight supply outlook.” : West Texas Intermediate crude for September delivery dropped $2.69 to settle at $71.26 a barrel in New York. Brent for October settlement fell $2.52 to end the session at $72.89 a barrel. Meanwhile, the U.S. and Israel vowed to respond to a deadly drone attack on a tanker last week in a major waterway for global oil shipments that they blamed on Iran. Middle East foes Iran and Israel have traded multiple accusations of shipping attacks in recent months. But Thursday’s strike off the coast of Oman, which Tehran denied carrying out, was the first to kill crew members -- a Romanian and a Briton.
Oil Prices Extend Decline -- Oil declined for a second day as the spread of Covid-19’s delta variant in China threatens to disrupt the recovery in global crude consumption. West Texas Intermediate futures ended Tuesday’s session down 1% at the lowest closing price in almost two weeks. Nearly half of China’s 32 provinces have been gripped by the latest outbreak in Asia’s largest oil market, with 5% of worldwde short-term oil demand potentially at risk, according to calculations by China National Petroleum Corp. The price drop was tempered somewhat by a rally in equities trading and the “potential hijack” of a ship in the Gulf of Oman. “China demand concerns because of the renewed restrictions from the viral spread were what caused the earlier weakness,” said Phil Flynn, senior market analyst at Price Futures Group. Crude rallied strongly in the first half of the year as the rollout of vaccines allowed major economies to reopen, boosting oil demand and draining the glut built up during initial waves of the pandemic. However, the fast-spreading delta variant has led to renewed restrictions in many countries. “Asia-Pacific is currently the focal point of lockdowns,” said Pavel Molchanov, an analyst at Raymond James & Associates Inc. “There are 887 million people worldwide are currently in lockdown, which is more than at the beginning of 2021, and 85% of them are in Asia-Pacific.” Crude’s decline also put the U.S. benchmark under technical pressure. WTI fell below its 50-day moving average and is edging closer to its 100-day moving average. Such moves can often spark additional selling from trend-following funds. Prices: WTI for September delivery fell 70 cents to settle at $70.56 a barrel in New York. Brent for October settlement lost 48 cents to $72.41 a barrel. The U.S. benchmark’s nearest timespread weakened on Tuesday. While the spread is still in a bullish backwardation structure -- with near-dated prices above those further out-- it narrowed to the smallest in about a week.
Oil Settles Lower in Volatile Trade on Worries About Delta Variant - (Reuters) -Oil settled lower on Tuesday, as concern about rising cases of the Delta coronavirus variant outweighed expectations for another weekly draw in U.S. inventories that had boosted prices early. Brent crude oil futures settled down 48 cents, or 0.66% at $72.41 a barrel. U.S. West Texas Intermediate (WTI) crude settled down 70 cents, or 0.98% at $70.56 a barrel. Prices held lower in post-settlement trade after market sources said preliminary data suggested crude stocks drew in the United States. [API/S] Concerns over the spread of Delta variant in the United States and China, the top oil consumers, weighed on prices, with both benchmarks falling more than 3% at one point. In China, the spread of the variant from the coast to inland cities has prompted authorities to impose strict measures to bring the outbreak under control. "The news flow out of China has been bearish since the weekend," said John Kilduff, a partner at Again Capital Management in New York. "There continues to be angst about the COVID-19 situation, which weighs on the petroleum complex the most." Earlier, Brent and U.S. crude had risen more than 60 cents. Brent has risen more than 40% this year, helping earnings of oil firms. "We're trying to price in how big the slowdown is going to be with the Delta variant," said Phil Flynn, senior analyst at Price Futures Group in Chicago. BP, ConocoPhillips , Diamondback Energy Inc and Continental Resources Inc all reported strong second-quarter earnings this week. Expectations of a return of Iranian crude to the markets also pressured prices. Iran and six powers have been in talks since April to revive a nuclear pact that could release its oil exports. But officials have said significant gaps remain. Iran's new president, Ebrahim Raisi, said on Tuesday his government would take steps to lift "tyrannical" sanctions imposed by the United States on its energy and banking sectors. The sixth round of indirect talks between Tehran and Washington adjourned on June 20, two days after Raisi was elected president. Parties involved in the negotiations have yet to announce when the talks will resume. A Reuters poll showed U.S. crude and product inventories likely declined last week, with both distillates and gasoline stockpiles predicted to have fallen for a third straight week. The American Petroleum Institute, a trade group, suggested U.S. crude stocks fell by 879,000 barrels in the week ended July 30, market sources said. The data showed that U.S. distillate inventories, including diesel, fell by 717,000 barrels for the week ended July 30, and U.S. gasoline stockpiles dropped by 5.8 million barrels.
Incident with multiple tankers in Gulf of Oman raises concerns in oil market -- U.S. officials say they are still trying to determine exactly what's happening, but numerous reports say there's potentially one hijacked ship in the Gulf of Oman and the status of several others is unclear. The situation occurred as tensions between the West and Iran have been rising, and as the U.S. and other world powers have been trying to reach a new deal with Iran over its nuclear program. At a briefing, U.S. State Department spokesman Ned Price said: "We are aware of the reports of a maritime incident in the Gulf of Oman. We are concerned. We are looking into it." Price said this was part of a disturbing pattern of belligerent behavior from Iran "including belligerents in the maritime domain."Price was referring to what military experts call a drone attack against a ship last week that killed a British crew member and a Romanian crew member aboard the ship Mercer Street.Other U.S. officials say the situation is moving quickly, but it appears armed Iranian gunmen had boarded the seized tanker.The incident has not moved oil prices, yet anyway. West Texas Intermediate crude futures for September settled down nearly 1% at $70.50 per barrel but they were off the lows of the day after the reports.Lloyds List reported that the Panamanian flagged Asphalt Princess was the ship that was reportedly seized by armed men. The British Navy earlier Tuesday had warned of a "potential hijack" in the Gulf of Oman, and the British military's United Kingdom Maritime Trade Operations warned ship operators that "an incident is currently underway" off of Fujairah, United Arab Emirates, according to news reports.The Associated Press had reported that at least four ships off the coast of the UAE broadcast warnings Tuesday that they had lost the control of their steering. The four vessels were identified as Queen Ematha, the Golden Brilliant, Jag Poofa and Abyss, according to the AP, citing MarineTraffic.com.Helima Croft, a former CIA analyst who heads global commodities strategy for RBC, said the activity is alarming and it appears to have been some sort of action that involves the Islamic Revolutionary Guard. The IRGC is a powerful military force that Iran wields separately from the standard Iranian armed forces and it reports directly to the ayatollah. "It is alarming given the fact we had two fatalities on Friday," she said. "You have to put it in the context of Iran continuing to make progress on the nuclear restart against the backdrop of a new hard-line government coming to power in Tehran. It raises the risk of unintended escalation, or one side not appreciating the other's red lines."
Harrowing Audio From Hijacked Tanker: "Iranians Are Onboard With Ammunition, We Are Drifting!" -Israel's national public broadcaster Kan News has obtained audio from Tuesday to Wednesday's harrowing events aboard the Panama-flagged tanker Asphalt Princess, believed to have briefly been under Iranian military control and headed for the Islamic Republic's territorial waters in the Persian Gulf. In the short audio recording released Wednesday crew of the distressed Asphalt Princess vessel are heard communicating with the UAE Coast Guard, frantically saying that between five and six armed Iranians were on board during the ordeal. It also seems the captain communicates that the tanker is drifting and not under the crew's control, confirming the initial reports that signaled something was wrong yesterday. The ship's transponder showed it was "not under command". The audio communication seems to have been made Wednesday just after the gunmen disembarked the ship. "Iranian people are onboard with ammunition," the crew member communicates. "We are... now, drifting. We cannot tell you exact our ETA to (get to) Sohar." But by later in the day Wednesday the hijackers departed the vessel, as ABC News reports: The hijackers who captured a vessel off the coast of the United Arab Emirates in the Gulf of Oman departed the targeted ship on Wednesday, the British navy reported, as recorded radio traffic appeared to reveal a crew member onboard saying Iranian gunmen had stormed the asphalt tanker. The incident — described by the British military’s United Kingdom Maritime Trade Operations the night before as a "potential hijack" — revived fears of an escalation in Mideast waters and ended with as much mystery as it began.
WTI Dips After Disappointingly Small Crude Inventory Draw - Oil prices fell for the second straight day, with WTI dropping back below $70 as the spread of COVID's delta variant in China threatens to disrupt the recovery in global crude consumption.“China demand concerns because of the renewed restrictions from the viral spread were what caused the earlier weakness,” said Phil Flynn, senior market analyst at Price Futures Group.However, the prices bounced somewhat by the “potential hijack” of a ship in the Gulf of Oman. API
- Crude -879k (-3mm exp)
- Cushing +659K
- Gasoline -5.751mm
- Distillates -717K
Analysts expected yet another sizable crude draw in the last week but were disappointed when API reported a surprisingly small 879k drop in stocks (vs 3mm exp).
WTI Extends Losses Below $70 After Unexpected Crude Inventory Build -Oil prices are down again this morning as demand anxiety grew amid 'Delta'-variant outbreaks in key consumer China,which countered improved sentiment in other risk assets. Additionally, for the second week in a row, the recovery in global air traffic has taken a step back, somewhat confirming the anxiety. After API reported a smaller than expected draw overnght "The risks to demand in China remain the number one topic. Some market observers are already reviewing their GDP forecasts for the third quarter. There is particular nervousness on the oil market because oil demand suffers considerably from mobility restrictions imposed in a bid to combat coronavirus.," On the 'bullish' side of oil, tensions continue to rise in the Middle East, supporting prices. Iran's newly elected hardline president, Ebrahim Raisi, took power on Tuesday, while hijackers briefly took control of an asphalt tanker in the Persian Gulf. Will the official data override algos' worries? DOE
- Crude +3.627mm (-3mm exp) - biggest build since March
- Cushing -543k
- Gasoline -5.291mm (-1.6mm exp)
- Distillates +832k (-500k exp)
Analysts expected a 10th weekly draw in the last 11 last week (even after API's much smaller than expected inventory drop), but they were wrong... very wrong. DOE reported a 3.627mm barrel build in crude stocks - the biggest since March.Distillates inventories also rose unexpectedly.
Oil Slumps As Covid Infections Dampen Demand Recovery-- Oil slumped in New York after a surprise increase in U.S. crude inventories added to renewed concerns about demand recovery as China battles the coronavirus resurgence. West Texas Intermediate futures tumbled 3.4% to close at the lowest in more than two weeks. The delta variant of Covid-19 has been detected in almost half of China’s 32 provinces in two weeks, and at least 46 cities have advised residents against non-essential travel. Meanwhile, American crude supplies increased by 3.63 million barrels, the biggest gain since March, government data showed. Key timespreads for futures contracts tumbled in response to weakening supply-demand fundamentals. “The resurgence in Covid infections in China is dampening perceptions of demand recovery,”said Peter McNally, global head of industrials, materials and energy at Third Bridge. After eking out a small advance in July, August is proving to be tough for crude. Tightened controls in some Asian nations to curb the spread of the virus risk eroding oil demand at a time when the Organization of Petroleum Exporting Countries and its allies are gradually increasing supply. The gloomy demand outlook continued to weaken timespreads in the U.S. oil market on Wednesday though the benchmark is still holding a bullish backwardation structure in which near-dated prices are trading at a premium to those further out. October futures traded at 44 cents a barrel above the November contract Wednesday, compared with more than $1 a month ago. Prices: WTI for September delivery slipped $2.41 to settle at $68.15 on the New York Mercantile Exchange. Brent for October settlement dropped $2.03 to end session at $70.38 a barrel. U.S. gasoline inventories fell 5.29 million barrels to the lowest volume since November, while a gauge of fuel demand, total products supplied, was steady, the Energy Information Administration said.
Oil drops for third day on concerns over spread of Covid-19 variant - Oil prices fell for a third day in a row to a two-week low on Wednesday on a surprise build in U.S. crude stockpiles and as the spread of the coronavirus Delta variant outweighed the impact of Mideast geopolitical tensions.The U.S. Energy Information Administration (EIA) said crude stockpiles rose 3.6 million barrels during the week ended July 30.That compares with the 3.1-million barrel draw analysts forecast in a Reuters poll and the 0.9-million barrel decline the American Petroleum Institute (API) reported on Tuesday.Brent futures fell $2.03, or 2.8%, to settle at $70.38 per barrel, while U.S. West Texas Intermediate (WTI) crude settled $2.41, or 3.4%, lower at $68.15 per barrel.That puts both benchmarks on track for their lowest since July 20. For Brent, it puts the contract down for a third day in a row for the first time since late May."Worries continue to grow over the spread of the Delta variant in China, which has weighed heavily on oil prices in recent days," analysts at bank ING said.The United States and China, the world's two biggest oil consumers, are grappling with rapidly spreading outbreaks of the highly contagious Delta variant that analysts anticipate will limit fuel demand at a time when it traditionally rises in both countries.In China, the spread of the variant from the coast to inland cities has prompted authorities to impose strict measures to bring the outbreak under control.Tensions in the Mideast Gulf, meanwhile, supported prices.On Tuesday, three maritime security sources claimed Iranian-backed forces seized an oil product tanker off the coast of the United Arab Emirates, though Iran denied the reports.This is the second attack on a tanker since Friday in the region, which includes the Strait of Hormuz. The United Kingdom and the United States are also blaming Iran for the earlier incident, in which drones crashed into the vessel and killed two sailors. Iran denies the reports.
Oil Up, but Surprise Build in U.S. Crude Supply Caps Gains - – Oil was up Thursday morning in Asia, with investors surprised by a build in U.S. crude oil supply, but still supported by ongoing tensions in the Middle East. Brent oil futures were up 0.24% to $70.565by 1:43 PM ET (5:43 AM GMT) and WTI futures gained 0.26% to $68.33. Both Brent and WTI futures fell by more than $2 a barrel on Wednesday. U.S. crude oil supply data from the U.S. Energy Information Administration on Wednesday showed a build of 3.636 million barrels in the week to Jul. 30. Forecasts prepared by Investing.com had predicted a 3.102-million-barrel draw, while a 4.089-million-barrel draw was recorded during the previous week. Crude oil supply data from the American Petroleum Institute released the day before showed a draw of 879,000 barrels. Some investors, though, focused on the bigger-than-forecast draw of 5.292 million barrels in gasoline inventories. "The fall in U.S. gasoline stockpiles to the lowest level since November 2020 suggests that fuel demand conditions in the U.S. are still quite resilient,". Brent oil prices are now expected to rise to $85 a barrel by the fourth quarter as oil demand outpaces supply growth, the note added. The latest tensions in the Middle East gave the black liquid a boost, however. "With tensions brewing amongst Iran and world powers over last week's drone attack, it seems nuclear deal talks will be lengthy and unlikely to provide imminent sanction relief for Iran," OANDA senior analyst Edward Moya told Reuters. The U.S. State Department said on Wednesday that it believed Iran was behind the hijack of the Panama-flagged Asphalt Princess tanker in the Gulf of Oman that look place last week, but that this could not be confirmed. Iran, however, had denied responsibility. Elsewhere in the region, Israeli aircraft struck what the country's military described as rocket launch sites in south Lebanon earlier in the day, as a response to earlier projectile fire towards Israel. Investors are also focused on the weather, with the risks of potential supply disruptions amid a forecast for more storms in the Atlantic also supporting prices, said Moya. The National Oceanic and Atmospheric Administration on Wednesday revised upward its outlook for the 2021 Atlantic hurricane season, with an estimated 65% chance of an above-normal season and between three to five major hurricanes.
Oil Up as Broad Market Rebound Offsets Delta Spread - Oil futures ended higher Thursday, snapping a three-day losing streak tied in part to worries that the spread of the delta variant of the coronavirus that causes COVID-19 may impact energy demand. West Texas Intermediate crude for September delivery gained 94 cents, or 1.4%, to finish at $69.09 a barrel on the New York Mercantile Exchange. October Brent crude , the global benchmark, rose 91 cents, or 1.3%, to close at $71.29 a barrel on ICE Futures Europe. WTI is nursing a week-to-date loss of more than 6%, while Brent is off 5.4%. The buy-the-dip approach remains a force in the oil market, analysts said. The bounce showed "crude oil bottom pickers stepping into the void today and pushing the barrel higher," said Robert Yawger, executive director of energy futures at Mizuho Securities. "That auto reaction to crude-oil pullbacks had largely been working since the vaccine announcement on Nov. 2." Recent weakness has been tied to concerns around surging cases of COVID-19 around the world tied to the delta variant, said Robbie Fraser, global research and analytics manager at Schneider Electric. "While demand levels have generally improved quicker than expected over the past year, record numbers of new cases in many countries threaten to halt or even unwind some of that progress in the weeks ahead," he said, in a note. Crude slumped on Wednesday after an unexpected uptick in U.S. crude stockpiles, although gasoline inventories showed a much larger-than-expected drop. A stronger dollar also weighed on crude. The dollar backed off Thursday, with the ICE U.S. Dollar Index , a measure of the currency against a basket of six major rivals, off 0.1%. The build in U.S. crude stocks was largely attributed to a fall in exports. Natural-gas futures ended lower after the Energy Information Administration said a net 13 billion cubic feet of the fuel was injected into storage last week. The September contract fell 0.4% to cloe at $4.14 per million British thermal units. It remains up nearly 6% for the week, boosted by hot weather and strong global demand. September gasoline rose 2% to close at $2.294 a gallon, while September heating oil was finished 1.5% higher at $2.106 a gallon.
U.S. oil set for biggest weekly loss since October - -Oil prices fell about 1% lower on Friday, posting to their steepest weekly losses in months, on worries that travel restrictions to curb the spread of the Delta variant of COVID-19 will derail the global recovery in energy demand. Crude futures also came under pressure as the dollar strengthened after monthly U.S. job growth came in higher than expected. A stronger dollar makes greenback-denominated oil more expensive for buyers in other currencies. Brent crude oil futures settled down 59 cents, or 0.8%, at $70.70, while U.S. West Texas Intermediate (WTI) crude futures fell 81, or 1.2%, to settle at $68.28 a barrel. For the week, global benchmark Brent shed more than 6%, its largest week of losses in four months, and WTI tumbled nearly 7% in its biggest weekly decline in nine months. "The price action we see now is really a function of the macro picture," said Howie Lee, an economist at Singapore bank OCBC. "The Delta variant is now really starting to hit home and you see risk aversion in many markets, not just oil." U.S. President Joe Biden said that COVID-19 cases in the United States, which have climbed to a six-month high, will go up before they come down and that the new Delta variant is taking a needless toll on the country. Japan is poised to expand emergency restrictions to more regions of the country, while China, the world's second-largest oil consumer, has imposed curbs in some cities and canceled flights. "Increased travel restrictions in China have come under the microscope of traders and could become a key oil price mover as this month proceeds," said Jim Ritterbusch, president of Ritterbusch and Associates LLC in Galena, Illinois. U.S. oil rigs rose two to 387 this week, energy services firm Baker Hughes Co said. Growth in the rig count has slowed in recent months as drillers continue to focus on capital discipline.
Oil Has Worst Week in 9 Months as Dollar Hobbles Crude’s Rebound -Oil posted its worst weekly loss in nine months as a soaring dollar on Friday hobbled any attempt by crude prices to rebound on Mideast tensions, after a week of negative news on Covid. New York-traded U.S. West Texas Intermediate crude, the benchmark for U.S. oil, settled Friday’s trade down 81 cents, or 1.2%, at $68.28 per barrel. For the week, WTI lost 7.7%, its most since the 10% drop during the week to Oct. 23, 2020. London-traded Brent, the global benchmark for oil, was down 85 cents, or 1.2%, at $70.44 per barrel by 2:55 PM ET (18:55 GMT). Brent lost almost 8% for the week, also its biggest weekly decline in nine months. Oil and most other commodities tumbled as the dollar sprung back from a recent spate of selling as a resilient U.S. jobs report for July raised questions about the continuance of the stimulus provided by the Federal Reserve to markets and the economy. Since the COVID outbreak of March 2020, the Fed has been buying Treasuries and other assets to the monthly tune of $120 billion to support the U.S. recovery from the pandemic. “A stronger dollar will likely prove to be a big drag over crude prices in the short-term,” said Ed Moya, who heads research for the Americas at New York-based broker OANDA. Crude prices were down for the first three days of the week amid a global surge in coronavirus cases from the Delta variant that cast a pall over the outlook for oil demand. In the United States, the world’s biggest oil consumer, Covid cases hit a six-month high with more than 100,000 infections reported earlier this week, according to a Reuters tally. Crude prices did manage to catch a break on Thursday on Mideast tensions as Israeli jets struck purported rocket launch sites in Lebanon in response to an earlier attack, allegedly by Tehran. That was before the dollar’s rebound on Friday, which put paid to any further rebound in oil.
Oil Caps Worst Week in 10 Months | Rigzone - Oil fell, capping the biggest weekly loss since October, as the spread of the delta coronavirus variant in China and elsewhere in the world is casting doubts on demand growth. West Texas Intermediate futures dropped 1.2% Friday and 7.7% for the week. The dollar rose following a better-than-expected U.S. jobs report, weakening the appeal of commodities priced in the currency. China has imposed increasingly strict restrictions on mobility to fight the spread of the deadly variant, while records in daily cases were set in Thailand and Sydney, Australia. “The market is reacting to the concern that the delta variant, particularly in Asia, may erode mobility significantly,” says Bart Melek, head of global commodity strategy at TD Securities. “That implies that we could see significantly less tightness in pricing than we saw prior to this big virus concern.” After crude soared in the first half of the year on surging demand, the latest chapter in the pandemic has capped prices of not just oil but some other commodities as well. The premium for the nearest WTI contract over second-month futures, known as the promt spread, narrowed to 18 cents after reaching 72 cents a week ago, pointing to ongoing concerns about demand. “On the one hand, markets worry about economic implications of the spreading of the delta variant, but on the other, policy accommodation gives a strong backdrop.” WTI for September delivery dipped 81 cents to settle at $68.28 a barrel in New York. Brent for October fell 59 cents to end the session at $70.70 a barrel in London. Despite the weak outlook for demand from Asia, there are some improved metrics in the U.S., where roads have remained busy. Vehicle miles traveled on highways in the week to Aug. 1 match the similar week in 2019, before the pandemic hit, according to the Department of Transportation. Gasoline deliveries to the Spanish market jumped above pre-pandemic levels last month.
No comments:
Post a Comment