distillate inventories at a 38 year high even as refinery utilization stays near 30 year low...

oil prices ended 1.7% higher this past week on hopes for a virus vaccine and on economic reports that suggested the demand recovery was intact.... after rising 4 cents, or 0.1% to $40.59 per barrel last week as big drop in US crude supplies was offset by OPEC's announcement that they'd increase production, the contract price of US light sweet crude for August delivery opened lower on Monday, weighed down by reports of an increase in the rate of new coronavirus infections, but rebounded to close 22 cents higher at $40.81 a barrel after reports of safe human clinical trials of a new Covid-19 vaccine....oil prices then jumped nearly 3% on Tuesday, buoyed by positive news about vaccine trials and the completion of an new EU economic stimulus deal, with trading in the August US oil contract expiring $1.15 higher at $41.96 a barrel, while the new front month September oil contract rose $1.00 to close at $41.92 a barrel....with reports now quoting the contract price of US light sweet crude for September delivery, oil prices slipped lower overnight after a surprisingly large crude inventory build was reported by the API, but recovered to finish just 2 cents lower at $41.90 a barrel despite the EIA's confirmation of that surprise build in U.S. oil supplies....concerns over rising supplies of crude and products and alarming growth in US coronavirus cases weighed on prices Thursday, and September oil ended down 83 cents at $41.07 a barrel as new claims for unemployment benefits unexpectedly rose for the first time in nearly four months...oil prices initially moved lower on rising US / China tensions Friday, but later rallied on strong economic data in Europe and the US to settle 22 cents higher at $41.29 a barrel, thus posting its third positive week in four on demand recovery hopes...

natural-gas also ended the week higher, supported by a widespread heatwave and a tropical storm in the Gulf of Mexico that threatened to disrupt offfshore production in the region....after falling 4.8% to $1.718 per mmBTU on moderating temperature forecasts and rising natural gas output last week, the contract price of natural gas for August delivery opened lower on Monday and tumbled 7.7 cents or 4.5% to a three week low of $1.641 per mmBTU, as natural gas output increased even as gas stockpiles remained about 16% over the five-year average....but gas prices regained 3.4 cents of that loss on Tuesday as power generators burned record amounts of gas as the heat wave blanketing much of the country intensified...however, gas prices only rose six-tenths of a cent on Wednesday even after forecasts that the heat wave would continue through early August...but prices spiked on Thursday as Tropical Storm Hanna strengthened, threatening natural gas production in the western Gulf, and the August gas contract finished 10.4 cents higher a $1.785 per mmBTU ...prices extended that rally by 2.3 cents on Friday, after signs of an improving liquefied natural gas (LNG) export environment and as Hanna was forecast to become a hurricane as it moved westward toward the Texas coast...natural gas prices thus finished the week with a 5.2% gain at a two week high of $1.808 per mmBTU, as forecasts continued to call for hotter weather and higher-than-expected air conditioning demand over the next two weeks.

the natural gas storage report from the EIA for the week ending July 17th indicated that the quantity of natural gas held in underground storage in the US rose by 37 billion cubic feet to 3,215 billion cubic feet by the end of the week, which left our gas supplies 656 billion cubic feet, or 25.6% greater than the 2,559 billion cubic feet that were in storage on July 17th of last year, and 436 billion cubic feet, or 15.7% above the five-year average of 2,779 billion cubic feet of natural gas that have been in storage as of the 17th of July in recent years....the 37 billion cubic feet that were added to US natural gas storage this week was more than the average 33 billion cubic feet increase that was forecast by analysts polled by S&P Global Platts, but it was less than the 45 billion cubic feet addition of natural gas to storage during the corresponding week of 2019, and it matched the average of 37 billion cubic feet of natural gas that has been added to natural gas storage during the same week over the past 5 years...

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending July 17th indicated a large addition to our stored commercial supplies of crude oil for the 5th week of the past seven, following a large withdrawal from supplies last week, despite little net change in the other metrics that effect oil supplies....our imports of crude oil rose by an average of 373,000 barrels per day to an average of 5,567,000 barrels per day, after falling by an average of 1,827,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 450,000 barrels per day to an average of 2,993,000 barrels per day during the week, which mean​s that our effective trade in oil worked out to a net import average of 2,948,000 barrels of per day during the week ending July 17th, 77,000 fewer barrels per day than the net of our imports minus our exports during the prior week...over the same period, the production of crude oil from US wells reportedly rose by 100,000 barrels per day to 11,100,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 14,048,000 barrels per day during this reporting week..

meanwhile, US oil refineries reported they were processing 14,206,000 barrels of crude per day during the week ending July 17th, 103,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA's surveys indicated that a net of 699,000 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 857,000 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 inserted a (+857,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a fudge factor that they label in their footnotes as "unaccounted for crude oil"....that followed the insertion of a (-768,000) barrel per day figure into last week's oil balance sheet, when there was a supply surplus of 768,000 barrels per day, and hence from last week to this week the the EIA's fudge factor swung by a total of 1,625,000 barrels per day, thus rendering the week over week oil supply & demand comparisons statistical nonsense....however, since the media usually treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill for oil, we'll continue to report them, just as they're watched & believed as accurate by most everyone in the industry....(for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....   

further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,218,000 barrels per day last week, which was 13.5% less than the 7,187,000 barrel per day average that we were importing over the same four-week period last year....the 699,000 barrel per day net addition to our total crude inventories came as 699,000 barrels per day were being added to our commercially available stocks of crude oil while the supplies in our Strategic Petroleum Reserve remained unchanged....this week's crude oil production was reported to be 100,000 barrels per day higher at 11,100,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states rose by 100,000 barrels per day to 10,600,000 barrels per day while a 4,000 barrel per day increase in Alaska's oil production to 461,000 barrels per day wasn't enough to impact the rounded national total....last year's US crude oil production for the week ending July 19th, which was impacted by a Gulf storm, was rounded to 11,300,000 barrels per day, so this reporting week's rounded oil production figure was about 1.8% below that of a year ago, yet still 31.7% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016...    

meanwhile, US oil refineries were operating at 77.9% of their capacity while using 14,206,000 barrels of crude per day during the week ending July 17th, down from from 78.1% of capacity during the prior week, but excluding the 2005, 2008, and 2017 hurricane-related refinery interruptions, still one of the lowest refinery utilization rates of the last thirty years...hence, the 14,206,000 barrels per day of oil that were refined this week were still 16.6% fewer barrels than the 17,034,000 barrels of crude that were being processed daily during the week ending July 19th, 2019, when US refineries were operating at 93.1% of capacity....

with the decrease in the amount of oil being refined, gasoline output from our refineries was a bit lower, decreasing by 16,000 barrels per day to 8,079,000 barrels per day during the week ending July 10th, after our refineries' gasoline output had increased by 50,000 barrels per day over the prior week... with our gasoline production still recovering from a multi-year low, this week's gasoline output was 10.0% lower than the 10,089,000 barrels of gasoline that were being produced daily over the same week of last year....at the same time, our refineries' production of distillate fuels (diesel fuel and heat oil) decreased by 97,000 barrels per day to 4,763,000 barrels per day, after our distillates output had increased by 104,000 barrels per day over the prior week... after this week's decrease in distillates output, our distillates' production was 8.7% less than the 5,219,000 barrels of distillates per day that were being produced during the week ending July 19th, 2019....

with the decrease in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 9th time in 13 weeks and for the 17th time in 25 weeks, falling by 1,802,000 barrels to 246,733,000 barrels during the week ending July 17th, after our gasoline supplies had decreased by 3,147,000 barrels over the prior week...our gasoline supplies decreased by less this week because the amount of gasoline supplied to US markets decreased by 98,000 barrels per day to 8,550,000 barrels per day and because our imports of gasoline rose by 49,000 barrels per day to 542,000 barrels per day and because our exports of gasoline fell by 122,000 barrels per day to 479,000 barrels per day....but even after this week's inventory decrease, our gasoline supplies were still 6.1% higher than last July 19th's gasoline inventories of 232,526,000 barrels, and roughly 7% above the five year average of our gasoline supplies for this time of the year...  

however, even with the decrease in our distillates production, our supplies of distillate fuels increased for the thirteenth time in 27 weeks and for the 18th time in 42 weeks, rising by 1,047,000 barrels to a 38 year high of 177,883,000 barrels during the week ending July 17th, after our distillates supplies had decreased by 453,000 barrels over 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 469,000 barrels per day to 3,223,000 barrels per day, even while our exports of distillates rose by 107,000 barrels per day to 1,439,000 barrels per day and while our imports of distillates fell by 47,000 barrels per day to 52,000 barrels per day....after this week's inventory decrease, our distillate supplies at the end of the week were 30.0% above the 136,816,000 barrels of distillates that we had in storage on July 19th, 2019, and about 27% above the five year average of distillates stocks for this time of the year...

with distillate inventories now at a 38 year high, we'll include a graph of their historical levels and explain why that's particularly remarkable for this time of year​..​

the above graph, which originally came from Bloomberg, was copied from the Zero Hedge coverage of this week's EIA report, and it shows US distillate supplies in millions of barrels, from mid-1982 to this week...while it's difficult to decipher from that graph, if you check out the EIA's interactive graph of distillate inventories and the accompanying spreadsheet, you'd find that the fluctuation we see in that graph is an annual pattern, with the yearly high in ​distillate ​supplies most often occurring when heat oil is being stockpiled just before midwinter, while the annual lows most often occur in late spring after cold winters have depleted the heat oil stockpile, or in mid-summer, when diesel fuel consumption is strongest...hence, that this week's 38 year high in distillate inventories should occur during the normally depleted summertime makes this week's record all the more remarkable...

finally, with the increase in unaccounted for oil, our commercial supplies of crude oil in storage rose for the 21st time in twenty-six weeks and for the 36th time in the past year, increasing by 4,892,000 barrels, from 531,688,000 barrels on July 10th to 536,580,000 barrels on July 17th....after that increase, our our commercial crude oil inventories were around 19% above the five-year average of crude oil supplies for this time of year, and about 59% above the prior 5 year (2010 - 2014) average of our crude oil stocks for the ​third weekend of July, with the disparity between those comparisons arising because it wasn't until early 2015 that our oil inventories first topped 400 million barrels....since our crude oil inventories have generally been rising since September of 2018, except for during last summer, after generally falling until then through most of the prior year and a half, our crude oil supplies as of July 17th were 20.6% above the 445,041,000 barrels of oil we had in commercial storage on July 19th of 2019, 32.5% more than the 404,937,000 barrels of oil that we had in storage on July 20th of 2018, and 11.0% above the 483,415,000 barrels of oil we had in commercial storage on July 21st of 2017...    

This Week's Rig Count

the US rig count fell for the 20th week in a row during the week ending July 24th, and is now down by 68.3% over that​ twenty week period....Baker Hughes reported that the total count of rotary rigs running in the US decreased by 2 rigs to 251 rigs this past week, which again was the fewest active rigs in Baker Hughes records going back to 1940 and 153 fewer rigs than the all time low prior to this year​...it was also down by 695 rigs from the 946 rigs that were in use as of the July ​26th report of 2019, and 1,678 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business....

the number of rigs drilling for oil increased by 1 rig to 181 oil rigs this week, after falling by 1 oil rig the prior week, which was still 595 fewer oil rigs than were running a year ago, and less than an eighth of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014....at the same time, the number of drilling rigs targeting natural gas bearing formations fell by 3 rigs to 68 natural gas rigs, which was the least natural gas rigs running in at least 80 years, and down by 101 natural gas rigs from the 169 natural gas rigs that were drilling a year ago, and was less than a twentieth of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008...in addition to those rigs drilling for oil & gas, two rigs classified as 'miscellaneous' continued to drill this week; one on the big island of Hawaii, and one in Sonoma County, California... a year ago, there was just one such "miscellaneous" rig deployed...

the Gulf of Mexico rig count was unchanged at 12 rigs this week, with 10 of those rigs drilling for oil in Louisiana's offshore waters and two of them drilling for oil offshore from Texas...that was 11 fewer rigs than the 23 rigs drilling in the Gulf a year ago, when 22 rigs were drilling offshore from Louisiana and one rig was operating in Texas waters...while there are no rigs operating off other US shores at this time, a year ago there were two rigs deployed offshore from Alaska, so this week's national offshore count is down by 13 from the national offshore rig count of 25 a year ago

the count of active horizontal drilling rigs was unchanged at 215 horizontal rigs this week, which matches the fewest horizontal rigs drilling in the US since November 18th, 2005, and was also 608 fewer horizontal rigs than the 823 horizontal rigs that were in use in the US on July 26th of last year, and less than a sixth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014...on the other hand, the vertical rig count was down by one to 14 vertical rigs this week, and those were also down by 42 from the 56 vertical rigs that were operating during the same week of last year....in addition, the directional rig count also fell by 1 rig to 22 directional rigs this week, and those were also down by 45 from the 67 directional rigs that were in use on July 26th of 2019....

the details on this week's changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes...the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of July 24th, the second column shows the change in the number of working rigs between last week's count (July 17th) and this week's (July 24th) count, the third column shows last week's July 17th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running 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 26th of July, 2019...    

we continued to see more changes in drilling activity this week, even as it remains subdued vis-a-vis the norm...checking the rig counts in the Texas part of Permian basin, we find that two rigs were added in Texas Oil District 8, or the core Permian Delaware, and another rig was added in Texas Oil District 7C or the southern Permian Midland, while a rig was shut down in Texas Oil District 8A or the northern Permian Midland, and another rig was shut down in Texas Oil District 7B, which includes a few counties in the far eastern Permian Midland...since the national Permian basin rig count was up by 2 rigs, that ​strongly ​suggests that the rig that was added in New Mexico would have been set up to drill in the western Permian Delaware, to account for the national increase...elsewhere in Texas, there was a rig added in Texas Oil District 2, but there were also three rigs shut down in Texas Oil District 3, which are both part of the region we ​normally ​associate with activity in the Eagle Ford shale, which stretches in a relatively narrow band through the southeastern part of the state and touches on four Oil Districts...since the Eagle Ford shows an increase of one rig, that would suggest that the three rigs shut down in Texas Oil District 3 were not targeting the Eagle Ford, but rather some basin that Baker Hughes does not track...however, checking the breakout for the Eagle Ford basin, we find that one natural gas rig was shut down in that basin, while two oil rigs were added at the same time...that could have occured ​with any number of combinations of offsetting start-ups and shutdowns in those disticts that wouldn't show up in the district totals...in addition, since the panhandle Texas Oil District 10 currently shows no activity, that means that the oil rig that was added in the Granite Wash was across the state line in south central Oklahoma...however, Oklahoma shows no net change because a rig drilling for oil in the Cana Woodford was shut down at the same time...lasly, for the three rig decrease in natural gas rigs, we first have the natural gas rig that was removed from the Eagle Ford, and then the two rigs that were removed from the Marcellus, one each of which had been drilling in Pennsylvania and West Virginia...

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PTTGC, Mountaineer agree on Ohio NGL storage project -- PTT Global Chemical (PTTGC; Bangkok, Thailand) has entered into a precedent agreement with Mountaineer NGL Storage to develop storage and pipeline infrastructure that would support PTTGC’s proposed petrochemical complex in Belmont County, Ohio. Under the agreement, Mountaineer, a subsidiary of Energy Storage Ventures, will develop multiple 500,000 bbl salt caverns capable of storing natural gas liquids (NGLs) or ethylene on a 200-acre site in Monroe County, Ohio. The $250-million storage project will come in two phases of around 1.5 million bbl of capacity each. Mountaineer says it has the necessary permits to begin construction on the first phase, which is slated for completion by 2022–23. PTTGC America is working with Mountaineer on 1 million bbl of ethane storage and a pipeline that will link the storage facility to the project 8 miles away. If realized, this would represent the first underground NGL storage site in the Marcellus and Utica shale formations in the US Northeast. Mountaineer first floated the project in 2016 following a successful open season and, according to local news reports, has been courting PTTGC America as a potential customer since at least 2019. "Ethane storage and transportation will be a crucial element of a world-scale petrochemical complex," PTTGC America president and CEO Toasaporn Boonyapipat says in a statement. "Mountaineer NGL Storage will provide essential infrastructure and capabilities to our project. Our impending partnership with this first-rate organization brings us one step closer to a final investment decision." The agreement comes after PTTGC America announced on 14 July that it was searching for a new partner in its 1.5-million metric tons/year ethane cracker and associated derivatives units following the withdrawal of South Korea's Daelim Chemical USA as an equity partner. In June, PTTGC America announced it would delay its final investment decision on the project until late 2020 or early 2021 due to oil price volatility and the COVID-19 pandemic. PTTGC America has completed the first stage of preparation, engineering, and design work for the petrochemical complex and has invested around $200 million into front-end engineering design. The Ohio Environmental Protection Agency has also issued air and water permits for the project following an environmental review. The project would take four to five years to construct once the company makes a final investment decision. It would be the second major petrochemical development in the US Northeast. Shell's 1.5-million metric tons/year ethane cracker and polyethylene complex is under construction in Monaca, Pennsylvania, about 60 miles north of the PTTGC site. A Shell presentation earlier this year put the target completion date for the Monaca plant in 2022.

PTTGC signs deal to develop NGL storage in northeast US --PTTGC America signed a precedent agreement that outlines the terms and conditions to develop underground natural gas liquids (NGL) storage in northeastern US. This is a critical piece of infrastructure for a proposed polyethylene (PE) complex that the company could develop in the region, it said on Wednesday. It would be the first underground site to store ethane and other NGLs in the Marcellus and Utica shale formations of the northeast US, PTTGC said. Under the agreement, Mountaineer NGL Storage will develop the underground salt caverns on a 200-acre (81 ha) site in Monroe county, Ohio, eight miles (13 km) south of PPTGC's proposed petrochemical complex in Belmont county, Ohio. Mountaineer will own and operate the storage facility. The storage facility is valued at $250m, and it will be developed in two phases by creating multiple caverns in an existing underground salt formation. Each cavern can store 500,000 bbl of material, including ethane, propane, butane and ethylene. PTTGC did not specify how many caverns will be built. A pipeline will connect the proposed PTTGC complex to 1m bbl of ethane storage. The first phase could store as much as 1.5m bbl of NGLs. PTTGC did not specify if this would be a mix of NGLs. Mountaineer already has all the permits needed to start construction on the first phase, which will take two to three years to complete. Phase two could hold another 1.5m bbl of NGLs, PTTGC said. The facility could also be further expanded in order to meet market demand. It is unclear whether the first phase alone would include 1m bbl of ethane storage, or whether the two phases would combine to reach that level. The storage facility could serve other prospective customers in addition to PTTGC, said David Hooker, president of Mountaineer. Mountaineer is a subsidiary of Energy Storage Ventures LLC. The storage deal brings PPTGC one step closer to making a final investment decision (FID) on the project, said CEO Toasaporn Boonyapipat, CEO of PTTGC America.

PTT Global/Mountaineer agreement a good thing for proposed cracker plant - — The Belmont and Monroe County commissioners see good signs in the future of PTT Global Chemical’s operations in the area now that a storage hub is being proposed to support an ethane cracker plant many are hoping to see built in Dillies Bottom.On Wednesday morning, the Belmont County commissioners referred to a press release just issued from PTT, announcing PTT’s agreement with Mountaineer NGL Storage to provide infrastructure for the proposed cracker plant. The NGL facility would provide storage and transportation services for the proposed plant. The facility will be the first underground NGL storage site in the heart of the Marcellus and Utica shale formations. Mountaineer will develop the underground salt caverns for NGL storage on a 200-acre site in Monroe County. The site, owned and operated by Mountaineer, is located approximately eight miles south of Dilles Bottom. PTT is working with Mountaineer on one million barrels of ethane storage and a pipeline that will link the storage facility to the project. “Ethane storage and transportation will be a crucial element of a world-scale petrochemical complex,” PTT President and CEO Toasaporn Boonyapipat said. “Mountaineer NGL Storage will provide essential infrastructure and capabilities to our project. Our impending partnership with this first-rate organization brings us one step closer to a final investment decision. We deeply appreciate all the support we have received from our federal, state and local partners, including Belmont and Monroe counties, which have brought us to this point.”“We are pleased to partner with PTTGCA as it works toward the development of the second petrochemical plant to be located in the Ohio River Valley,” said David Hooker, president of Mountaineer NGL Storage. “Our storage facility will have an important role in managing the plant’s supply portfolio, along with offering PTTGCA and other prospective customers an option to manage seasonal and operational demand with competitive locally priced production. The PTTGCA team has been great to work with, and we look forward to a long and successful relationship.”

Thailand's PTT moves closer to decision on Ohio petrochemical plant with storage deal - State-owned Thai oil and gas company PTT Pcl said its U.S. unit took a step forward on its proposed chemical plant in Ohio that will turn ethane into plastics with an agreement to develop a natural gas liquids storage facility. PTT Global Chemical America (PTTGCA) signed an agreement with Energy Storage Ventures LLC to build a facility to store and transport natural gas liquids (NGL) for PTTGCA's proposed complex."Our impending partnership ... brings us one step closer to a final investment decision," PTTGCA President and Chief Executive Toasaporn Boonyapipat said in a statement on Wednesday.In June, PTTGCA said it delayed making a final investment decision to build the ethane cracker, which analysts estimate will cost $5.7 billion, from the first half of 2020 to the first half of 2021 due to the coronavirus.   Analysts said the pandemic reduced expected growth in global demand for plastics. Energy Storage Ventures' Mountaineer NGL Storage subsidiary will develop the underground salt caverns on a 200-acre (80-hectare) site in Ohio's Monroe County about 8 miles (13 kilometers) from the PTTGCA site.PTTGCA said it is working with Mountaineer on 1 million barrels of ethane storage and a pipeline linking the storage facility to the project. PTTGCA said Mountaineer will develop the $250 million storage facility in two phases by creating multiple caverns in the existing underground salt formation. Each phase will be able to hold about 1.5 million barrels. PTTGCA said it is seeking new partners for its ethane cracker project after South Korea's Daelim Industrial Co Ltd pulled out earlier this month.

Pennsylvania Governor Signs $667 Million Fracking Tax Credit -A bipartisan bill giving tax breaks to Pennsylvania manufacturers that use dry natural gas to make petrochemicals and fertilizers was signed into law Thursday by Gov. Tom Wolf. The measure (HB 732), a compromised version passed last week after the Democratic governor vetoed a similar measure in March, allows for approval of tax credits for four projects a year, adding up to nearly $667 million over the 25-year span of the economic development incentive program. The annual cap will be $26.7 million. Applicants must invest at least $400 million in a project facility using dry natural gas...

More sinkholes develop alongside Mariner East construction in Chester County -Sinkholes and land subsidence have developed alongside Sunoco’s Mariner East pipeline construction in West Whiteland Township, Chester County. About half a dozen sinkholes along the pipeline’s path began appearing June 13, close to active pipelines carrying natural gas liquids, a pipeline valve station and a public hiking trail, according to local officials. The most recent subsidence occurred Friday afternoon, with growing cracks on the busy Route 30, near a sinkhole that had developed last week, according to the Pennsylvania Public Utility Commission. The PUC’s Safety Division of the Bureau of Investigation & Enforcement is on-site and conducting an investigation. “No active pipelines were exposed as a result of the subsidences and engineers from the Safety Division continue to closely monitor the situation,” according to a statement released Friday afternoon by the PUC. The PUC says it is in contact with the Pennsylvania Department of Environmental Protection and PennDot. All of the sinkholes have been filled with cement, according to Township manager Mimi Gleason. Gleason says pipeline builder Energy Transfer, formerly known as Sunoco Logistics, continues to conduct testing and has an employee walking the area around the clock to check for any newly formed sinkholes or subsidence. The PUC says the company is using ground penetrating radar three times a day near the roadway and the hiking trail to detect any new subsidence. “The Township is very concerned,” said Gleason. “We’re glad the PUC is requiring additional testing to make sure the infrastructure is safe going forward.” Gleason says Energy Transfer finished the underground drilling needed to install the pipeline, and reported the drill went through “very hard rock.” The area around Exton is known for its limestone, or karst, geology, which is soft and porous. The state issued permits for the pipeline in 2017, despite warnings by Department of Environmental Protection employees that the area’s geology could trigger sinkholes. Gleason says Energy Transfer also discovered a void 30 feet below the surface, which it filled with cement. It’s unclear whether that void existed before construction, or was caused by it, she said. The Township says it is now safe to use the Chester Valley Trail, which had been closed.

‘Dark money’ groups spent $517,000 against two Philly-area candidates who oppose the Mariner East pipeline --Conservative nonprofit groups that have advocated for the natural gas industry funded hundreds of thousands of dollars worth of attack ads in last month’s primary election in two state House races in the Philadelphia suburbs. Outside political groups spent at least $517,000 on Democratic primary races in Chester County, according to newly disclosed campaign records and data compiled by the ad tracking firm Advertising Analytics. The targets of the attack ads were first-term state Rep. Danielle Friel Otten and Ginny Kerslake, both Democrats and outspoken opponents of Sunoco’s Mariner East pipeline project, which carries natural gas liquids from the Marcellus and Utica shale formations to the company’s terminal in Marcus Hook. Otten won her primary. Kerslake lost to incumbent Democratic Rep. Kristine Howard. That much spending in state House races is unusual — and it came so late in the campaign that one of the political groups involved didn’t have to disclose its donors until a month after the June 2 election. Tracing the funding is almost impossible, as the nonprofits behind it are not required to disclose donors. The spending underscores the influence of “dark money” in seemingly low-profile races, as well as the stakes associated with the controversial pipeline project, a political and legal flash-point in the debate over energy and the environment.

AG charges two pipeline companies over spills in Washington County - Pennsylvania Attorney General Josh Shapiro charged two pipeline companies with polluting groundwater and streams in a series of spills in 2015 along a pipeline project in Washington County. Shapiro said grand jury evidence obtained in the case showed that the pipeline builders chose to ignore a spill along the pipeline, failing to report it on a daily log. The charges stem from a construction project for a 24-inch natural gas pipeline in Robinson Township, about 30 miles west of Pittsburgh. The attorney general is charging two companies, New York-based National Fuel Gas Supply, and its subcontractor, Arizona-based Southeast Directional Drilling, for violating the state’s Clean Streams Law. “I made a commitment to Pennsylvanians that I would protect their constitutional right to clean air and pure water,” Shapiro said, in a statement. “These companies turned a blind eye to that right and will be held accountable.” According to court documents, the crews building the pipeline lost control of fluids used to bore underground tunnels for the pipeline, and the fluid surfaced in a nearby stream. The fluid commonly contains water, a form of clay called bentonite, as well as other chemicals and additives to assist in lubricating the drill and returning the drill cuttings to the surface. Neighbors also began noticing their private drinking water became cloudy and discolored, and tests later confirmed contaminants in the drinking water. A nearby stream that was normally clear became milky. One of the neighbors reporting problems with his water was former township supervisor Brian Coppola. Coppola, who is suing the companies in Washington County court, still can’t use his drinking water, according to the court documents. Pennsylvania Attorney General's office A grand jury presentment charging two pipeline companies with environmental crimes related to a drilling fluid spill included this photo of a Washington County stream affected by the spill. The documents say that even though the Pennsylvania Department of Environmental Protection tested Coppola’s drinking water, Coppola “never received anything other than the lab results” from the DEP. A subsequent test performed by a private lab found elevated levels of solids and chemicals in Coppola’s water. Other neighbors reported problems. One found “cloudy, white-colored water” when he began filling his pool with a garden hose. Another, Brenda Vance, told the grand jury her water supply had turned white, but when a DEP water quality specialist came to her house, he tested it for contaminants associated with fracking and gas drilling, not pipeline drilling. The DEP later told her that even though “common pollutants associated with oil and gas fluids” were found in her water, it was “not adversely affected by the drilling, alteration, or operation of an oil and gas well.”

West Liberty man indicted, accused of dumping waste –   A federal grand jury has indicted a West Liberty man accused of illegally importing radioactive sludge produced by a fracking site in north central West Virginia. The jury sitting in Ashland indicted Cory David Hoskins, the former owner of Advanced TENORM Services LLC on five counts of mail fraud and 22 counts of violating the Hazardous Materials Transportation Act. The federal government has charged Hoskins in connection with a series of shipments and payments between July 2015 and December 2015 for waste dumped in Estill County. The indictment is just the latest in a case that has played out since West Virginia authorities alerted the Commonwealth about the dumping of TENORM waste in January 2016. TENFORM (Technologically Enhanced Naturally Occurring Radioactive Material) is a by-product of fracking. According to the EPA, most oil and gas found inside the earth are actually on the sites of ancient oceans. The actual petroleum products are the remains of sea life that died millions of years ago. The wastewater produced by a fracking operation may contain harmful materials like uranium, thorium, radium and lead, according to the EPA. According to the federal indictment, Hoskins approached Fairmont Brine Processing in West Virginia in July 2015 about trucking the sludge to Kentucky. The feds allege Hoskins lied to Fairmont Brine about having U.S. DOT compliant trucks — those need special placards and certified drivers — and also having engineers, physicists and nuclear experts on staff. He then told federal regulators and the trucking companies he hired out to run the radioactive rubbish that the waste wasn’t hazardous and therefore was exempt from any special regulations, according to the federal indictment. Federal authorities even accuse Hoskins of intentionally approaching trucking outfits, including one in Ashland, that didn’t have the hazardous certifications in order to get a cheaper rate. When the waste made it to a landfill in Irvine, the indictment sates Hoskins provided fudged paperwork showing the radioactive waste to be non-hazardous. The 22 counts of violation of the hazardous materials act are for runs identified by federal authorities. The five fraud counts reflect payments that changed hands between Fairmont Brine and Advanced TENFORM. 

State Legislature closes hazardous waste loophole - The State Legislature passed A.2655/S.3392, a statute that closes a loophole that allowed hazardous hydrofracking waste to be dumped in New York even while hydrofracking itself was banned. The legislation passed the Assembly on Monday and the Senate on Wednesday. It must be signed by Gov. Andrew Cuomo to become a law. Shale fracking has polluted drinking water sources throughout the country—in Pennsylvania’s Monongahela River, for example—and Cuomo’s ban defended both public health and the environment. However, the fracking ban still allowed shale oil and gas waste—which can be highly flammable, toxic, and occasionally radioactive—to be imported. Formerly, the loophole let such waste avoid the label of “hazardous,” so it was regularly accepted to be spread on roads, or to be disposed of improperly at dumpsites and landfills throughout the state. A June 2019 report showed that New York had accepted over 638,000 tons and about 23,000 barrels of fracking waste from Pennsylvania fracking operators since 2011.

Plugging abandoned oil and gas wells could be a jobs boon for the U.S. - There's a lot of jobs potential if the federal government gets serious about plugging what could be as many as 3 million abandoned oil-and-gas wells nationwide, a new report from Resources for the Future and a Columbia University energy think tank concludes. Abandoned wells can leak methane — a very potent planet-warming gas — and other pollutants. If it tackles 500,000 of those, this could mean up to 120,000 more jobs.The idea comes as oil-and-gas industry workers are reeling from layoffs due to the price and demand collapse.Estimates for the number of abandoned wells nationwide range from hundreds of thousands to 3 million, "depending on the definition of such wells needing attention," the report notes."A significant federal program to plug orphan wells could create tens of thousands of jobs, potentially as many as 120,000 if 500,000 wells were plugged," it finds. It points out that the oil industry has equipment and labor available for the job, given that the sector shed more than 76,000 jobs (and counting) this year. They estimate that the costs of plugging the "known inventory" of roughly 57,000 wells could range from $1.4 billion to $2.7 billion, while identifying and plugging 500,000 wells could plausibly cost $12 billion to $24 billion.

US Marcellus and Utica Shales Market Report- Size, Trends, Drivers, Restraints, Opportunities, and Challenges - The US Appalachian Basin located in Pennsylvania, Ohio, West Virginia and New York continues to be the driver in natural gas production within the United States. During May 2019, it produced around 31 billion cubic feet per day (Bcfd) and is forecast to reach a rate of approximately 35 Bcfd by the end of 2019. The basin comprises the two main formations – the Marcellus, and the Utica. The majority of the activity in the Marcellus continues to take place in north east and south west Pennsylvania while the hotspot for the Utica is in eastern Ohio. Fracking activity in the Marcellus and Utica formations is driven by the large demand for natural gas from the nearby populated areas and although natural gas prices have experienced some volatility during recent years, Appalachian producers are generally able to sell their natural gas at a premium in trading hubs located in the North East. The competitive landscape of the Marcellus play is largely dominated by EQT Corp., the largest natural gas producer in the US, whereas, Ascent Resources LLC and Gulfport Energy Corp. lead the natural gas production in the Utica play. The report analyzes the natural gas appraisal and production activities in the Marcellus and Utica shale plays. The scope of the report includes –
– Comprehensive analysis of natural gas production across major counties in Pennsylvania, West Virginia, Ohio, and New York during 2013-2018, as well as production outlook from 2019 to 2023
– In-depth information of well permits issued in the Pennsylvania region of the Marcellus and Utica shale, by county and by company from January 2018 to March 2019
– Detailed understanding of IP rates and type well profiles in Marcellus and Utica formations
– Exhaustive analysis of competitive landscape in the Marcellus and Utica shale in terms of net acreage, gross production, cost trends and planned investments.
– Comparison of type well economic metrics of major players were also analyzed
– Up-to-date information on major mergers and acquisitions in the Marcellus and Utica shales between 2013 and 2019
– Overview of existing and upcoming pipelines and LNG terminals in the Marcellus and Utica.

FERC approves Leidy South gas pipeline project to fuel power in Atlantic states - Natural gas infrastructure firm Williams gained federal regulatory approval for a pipeline project bringing gas for home heating and power generation in the Atlantic Seaboard region. The Federal Energy Regulatory Commission gave permission to proceed with the Leidy South Project which will deliver 582,400 dekatherms per day—enough to serve more than two million homes—of additional pipeline takeaway from the gas-rich Marcellus and Utica shale regions of Pennsylvania. Tulsa-based Williams says the project will help utilities convert from coal-fired power capacity to natural gas, which has half the carbon emissions. “As the United States switches to clean power to energize our electric grids, Williams is excited and proud to be the backbone that connects the best supplies of dry gas with our country’s largest demand centers,” said Alan Armstrong, president and CEO of Williams. “This project represents one of many opportunities to further reduce greenhouse gas emissions with right here, right now available solutions as coal-fired electric generation plants are replaced with natural gas units to reliably balance the intermittency of new renewable resources.” The Leidy South would basically use the same corridor as the company’s interstate Transco pipeline system in that area, so it would reduce the amount of new infrastructure and land use needed. Transco is the nation’s largest-volume interstate natural gas pipeline system, delivering natural gas through a 10,000-mile pipeline network whose mainline extends nearly 1,800 miles between South Texas and New York City. Williams added that there are still more than 80 coal-fired power plants in the states served by the Transco pipeline system. Natural gas fuels more than 35 percent of the nation’s electricity generation mix, while coal has dropped from its once preeminent position to about 25 percent amidst a growing number of plant retirements. Cabot Oil & Gas and Seneca Resources will be producing the natural gas connecting to the Leidy South expansion. Atlantic Seaboard states form one of the fastest growing gas generation regions in the U.S., according to BTU Analytics. Environmental challengers, however, have forced the cancellation of Duke and Dominion’s planned Atlantic Coast Pipeline which would have crossed the Appalachian Trail. The two utilities said the cost of legal challenges make the already multi-billion-dollar project uneconomical for them. Williams says the construction phase will create more than 600 jobs, while operations will support $4.2 million in annual economic impact for origin state Pennsylvania.

Transco Expansion Approved to Connect Marcellus, Utica Natural Gas to Eastern Markets - FERC last Friday approved the Williams Leidy South natural gas pipeline project that would connect Marcellus/Utica shale supply to demand markets along the Atlantic Seaboard ahead of the 2021-2022 winter. The 582,400 Dth/d pipeline, an extension of the massive Transcontinental Gas Pipe Line system, aka Transco, would source gas produced by Cabot Oil & Gas Corp. and Seneca Resources Co. LLC. The project is to include six miles of large-diameter pipeline loop, two compressor stations and associated facilities in Pennsylvania’s Clinton, Columbia, Lycoming, Luzerne, Schuylkill and Wyoming counties. Williams CEO Alan Armstrong said the project represents one of many opportunities to further reduce greenhouse gas emissions, noting that “there remain more than 80 coal plants in the states Transco serves that can potentially be displaced” by gas. By maximizing the use of the existing Transco transmission corridor and expanding existing facilities in Pennsylvania, Leidy South would “substantially reduce” the amount of new infrastructure and land use required to meet these needs, minimizing community and environmental impact, Armstrong said. “With the growing urgency to transition to a low-carbon fuel future, Williams and its natural gas-focused strategy provide a practical and immediate path to reduce industry emissions, support the viability of renewables and grow a clean energy economy,” the CEO said.Approval by the Federal Energy Regulatory Commission for Leidy South comes at an uncertain time for oil and gas pipelines across the country. Earlier this month, Dominion Energy Inc. and Duke Energy Corp. canceled the proposed Atlantic Coast gas pipeline project, citing ongoing delays and increasing cost uncertainty. Meanwhile, the future of the Dakota Access crude pipeline, three years after entering service, is increasingly unclear amid an ongoing legal battle over key water-crossing permits. 

'People Need to Fight It for Everything They're Worth' – Battles over Pipelines Are Far from Over - Theresa “Red” Terry and her daughter spent 34 days living in the treetops trying to block construction of a 42-inch-wide gas pipeline through her family’s property in Virginia’s Blue Ridge Mountains. They were eventually forced down by a court order, and the minute Red’s feet touched the ground, chainsaw crews emerged to cut down her oak and maple trees. They were thwarted by an angry crowd of Red’s supporters and police who intervened to prevent violence, but early the next morning, the crews returned to finish the job.That was more than two years ago. The trees remain on the ground today, piled the way they fell in May of 2018.“Every time I go out there, I feel like someone stomped my heart,” said Terry in mid-July. “I feel like the whole mountain has been given cancer.”The Terry property, which has been in the family for seven generations, contains family residences, an orchard, a multitude of wildlife, and the upper reaches of Bottom Creek, a pristine mountain stream that forms the headwaters of the Roanoke River. The land also falls in the path of the Mountain Valley Pipeline (MVP), a planned 303-mile natural gas pipeline running from the fracking fields of the Marcellus and Utica shale formations in northern West Virginia to a terminal in southern Virginia that feeds into the East Coast pipeline network.  MVP was announced in 2014 as part of a wave of similar projects, including the 600-mile Atlantic Coast Pipeline (ACP) from West Virginia through Virginia to North Carolina, and the Western Marcellus Pipeline, planned to run along a similar path as MVP.   Western Marcellus never got off the drawing board, and the ACP was canceled in early July after six years of regulatory and legal battles, which caused the project’s cost to balloon from roughly $5 billion in 2014 to $8 billion in 2020. The day after the ACP was canceled, a federal court ordered the Dakota Access oil pipeline to shut down.  Anti-pipeline activists celebrated the double shot of good news and enjoyed renewed hope that other pipelines like the MVP might be stopped.  But since the wins in early July, a series of twists suggest the fight against natural gas infrastructure will continue for some time. A U.S. Appeals Court granted DAPL an administrative stay so it can continue to operate while the court deliberates. Additionally, the U.S. Supreme Court dramatically reduced the scope of a U.S. District Court ruling that factored into the ACP’s cancellation.  In a case involving the Keystone XL pipeline, the lower court had ruled in April that the Army Corps of Engineers failed to adequately consider endangered species when it issued what’s known as Nationwide Permit 12. That particular permit was used by dozens of pipelines because it allowed them to win approval to cross multiple waterways through a single process, instead of applying for individual permits for each stream and river. The U.S. District Court not only halted the use of Nationwide Permit 12 for Keystone XL but applied the ruling nationwide. The Supreme Court restored the use of the permit everywhere except with regard to Keystone XL. These developments are only the current hotspots in a long-running legal, political and regulatory battle that’s playing out around the construction of natural gas infrastructure throughout rural America.

Columbia Gas seeks more time to build pipeline --Columbia Gas Transmission Corp. is asking for more time to finish a pipeline that would cross part of Washington County. The Federal Energy Regulatory Commission issued a notice of the request on Wednesday. The company states that, “due to unforeseen delays in acquiring an easement from the government of Maryland across the Western Maryland Rail Trail, additional time is now required in order to complete the construction of the authorized project facilities,” according to the notice. Columbia is asking for an extension, until July 18, 2023, to complete the pipeline. Columbia Gas Transmission, a subsidiary of TC Energy, has proposed running the pipeline from existing facilities in Pennsylvania to a new Mountaineer Gas Co. pipeline in West Virginia. Proponents have said the new pipeline is critical to economic development in West Virginia’s Eastern Panhandle. Opponents have said the pipeline, which would burrow more than 100 feet under the Potomac River, would threaten the environment and drinking water while bringing little benefit to the state. The pipeline would go under the Cheasapeake and Ohio Canal Historical Park, which is owned by the National Park Service, and the Western Maryland Rail Trail, which is owned by the state. The project received green lights from state and federal regulators. But the Maryland Board of Public Works has denied the company’s request for a right-of-way permit to bore under the Western Maryland Rail Trail. In August, a federal court in August upheld that denial. This week’s notice from FERC establishes a 15-calendar day intervention and comment period deadline. Comments are due before 5 p.m. Eastern Time on July 30, according to the notice.

Completion of regional natural gas pipeline project may be delayed — The underground TransCanada natural gas pipeline from Pennsylvania through Maryland into West Virginia may take longer to complete.Columbia Gas, the TransCanada subsidiary building the project, has asked the Federal Energy Regulatory Commission (FERC) to have until the summer of 2023, a decision which must be approved by FERC. For regional industry here, however, officials say the pipeline is important to attract business.“It’s very important that we have another source of natural gas into Berkeley County and our region,” says Sandy Hamilton, head of the Berkeley County Development Authority. “We are at capacity. We have new customers that are looking to come to our area and if they’re a heavy natural gas user I have to give them a ‘no’ or, at least, we have to find them an alternative.”The public is invited to submit public comment to FERC by the end of this month.\Pipeline firms scale back plans amid legal protests - - A decade ago, when the shale boom was still in its infancy, developers lined up to build long-distance natural gas pipelines to supply distant markets with low-cost energy to replace aging, dirty coal and oil-burning power plants.But after years of legal fights with environmental groups trying to eradicate carbon-emitting fossil fuels, pipeline companies are backing off large-scale pipeline projects. The decision by its developers earlier this month to cancel the 600-mile Atlantic Coast Pipeline project is just the beginning, experts say. “There’s so much uncertainty on the project timeline and the cost you are unlikely to see another major natural gas pipeline built (that crosses state lines),” said Sam Andrus, executive director of North American gas at the consulting firm IHS Markit. “These environmental groups have made it their explicit goal to delay these projects and raise the costs. And they’re getting better at it as time goes on.” If more pipelines go the way of the Atlantic Coast, it would limit markets for natural gas producers in states such as Texas, which produces more gas than any state and has watched its economy thrive under oil and gas boom brought on by hydraulic fracturing. A recent study by the American Petroleum Institute predicts that demand from oil and gas producers would support the construction of more than 17,000 miles pipelines during the next five years. But between legal fights with environmentalists and Democratic state politicians such as New York Gov. Andrew Cuomo moving to block pipelines from their states to address climate change, it looks unlikely that anywhere close to that amount will be built. “We need infrastructure to get our production out to areas with the most demand,” said Frank Macchiarola, senior vice president at API. “It’s essential we get these projects up and running.”

PIPELINES: Federal court hands FERC more time to use delay tactic -- Friday, July 24, 2020 --  A federal court yesterday granted the Federal Energy Regulatory Commission extra time to comply with a recent ruling barring the commission from using a procedural stalling tactic in legal challenges. FERC now has until Oct. 5 to comply.

Environmental justice concerns stall Va. power project -- Thursday, July 23, 2020 --A $350 million gas project spanning much of eastern Virginia has been put on hold, in part due to environmental justice concerns. Virginia's State Corporation Commission (SCC) recently deferred action on the proposal by Southern Co. subsidiary Virginia Natural Gas (VNG). The agency told the company to come back by the end of the year with more details on financing and environmental justice issues. The project, a series of pipelines, compressor stations and other infrastructure stretching from the exurbs of Washington to Hampton Roads in southern Virginia, has come under fire from environmental groups for potentially locking in years of natural gas use. They've been joined by a group of residents of Charles City County, a poor, majority-minority county east of Richmond. The project is designed to supply a natural gas power plant in the county, and another plant has been proposed. While supporters say the facilities would bring economic development, opponents say developers are pushing big polluters on a vulnerable population. "We were an easy target. They knew exactly what they were doing," said La'Veesha Rollins, a Charles City County native who is part of the group fighting the project. "We get nothing out of this deal." Officials at VNG say they remain committed to the project. Spokesman Rick DelaHaya said the company intends to work with the SCC and other agencies "to develop a model project that meets all regulations." At the center of the project is a proposed 1,060-MW combined-cycle natural gas power plant known as C4GT, a merchant plant that would sell electricity to the wholesale market through grid operator PJM Interconnection. Another plant, called the Chickahominy Power Station, was announced in 2018 and is to be located within a mile of C4GT. Called the Header Improvement Project (HIP), VNG's plan involves 6 miles of new pipeline for an interconnection to the Transco line in Prince William County, Va. The plan would also add 18 miles of pipelines in existing corridors and three new or expanded compressor stations. One of the compressor stations would be built in an existing metering location in a minority neighborhood of Chesapeake, Va., south of Norfolk. VNG officials say the project would bring jobs, development and tax revenue to Charles City County and beyond, along with gas and electric reliability, noting that gas burns cleaner than coal. They call C4GT among the most efficient natural gas-fueled power plants to be built in Virginia. Environmental groups say the project moves Virginia toward continuing dependence on natural gas, when the Democrats who now run the state have been trying to put it on track for more renewable energy.

Developers: With pipeline canceled, big factories will reject Eastern North Carolina - They say high energy users want natural gas; opponents of the Atlantic Coast Pipeline reject that argument. While environmentalists and private property advocates celebrated the cancellation of the Atlantic Coast Pipeline this month, economic developers said the state literally lost fuel that North Carolina needs to attract large employers to lower-income areas in the eastern part of the state. Over the past three years, Cumberland County and the Fayetteville area were considered for more than $1 billion worth of industrial projects “that either won’t be coming or could not come because we did not have the natural gas structure that they needed,” “Some of them located in other parts of the state and other parts of the Southeast. But once it came down to profiling their energy load, we just weren’t able to accommodate it,” Van Geons said, declining to name the companies.The Atlantic Coast Pipeline would have run about 600 miles and carried natural gas from West Virginia to central and eastern Virginia and Eastern North Carolina. Construction was underway, and it was supposed to be completed this year. But the project was stalled by lawsuits and other efforts by its opponents. The estimated construction price rose from $5 billion in 2015 to $8 billion this year.Duke and Dominion announced the end of the project on July 5. They said ongoing delays and “increasing cost uncertainty” threatened the project’s economic viability.The opposition included a variety of critics.Some were property owners who were angry at being forced to give up land for the pipeline. Others were residents along the route who worried about natural gas leaks, fires and explosions near their homes.And many were environmental activists. They oppose the use of fracking techniques to extract natural gas and they want the world to move away from fossil fuels that exacerbate climate change by adding to the amount of heat-trapping gases in the atmosphere.

U.S. natgas futures drop over 4% to 3-week low as output rises - (Reuters) - U.S. natural gas futures dropped more than 4% on Monday to a three-week low as output increases and stockpiles remain about 16% over the five-year average. Some analysts said the market was starting to write off the rest of the summer after prices dropped about 5% last week even though this is the hottest time of year and the weather is expected to remain hotter-than-normal through at least early August. Front-month gas futures fell 7.7 cents, or 4.5%, to settle at $1.641 per million British thermal units, their lowest close since June 26. Refinitiv said production in the Lower 48 U.S. states averaged 88.4 billion cubic feet per day (bcfd) so far in July, up from a 20-month low of 87.0 bcfd in June but still well below the all-time monthly high of 95.4 bcfd in November. Traders noted output was rising as EQT Corp boosted production in Appalachia. Refinitiv forecast U.S. demand, including exports, will rise from 92.5 bcfd this week to 94.1 bcfd next week. That is higher than Refinitiv's outlook on Friday. Pipeline gas flowing to U.S. LNG export plants averaged 3.3 bcfd (34% utilization) so far in July, down from a 20-month low of 4.1 bcfd in June and a record 8.7 bcfd in February. Utilization was about 90% in 2019. U.S. pipeline exports, meanwhile, rose as consumers in neighboring countries cranked up their air conditioners. Refinitiv said pipeline exports to Canada averaged 2.4 bcfd so far in July, up from 2.3 bcfd in June, but still below the all-time monthly high of 3.5 bcfd in December. Pipeline exports to Mexico averaged 5.56 bcfd so far this month, up from 5.44 bcfd in June and on track to top the record 5.55 bcfd in March.

UPDATE 1-U.S. natgas futures rises as consumers crank up air conditioners -  (Reuters) - U.S. natural gas futures rose 2% on Tuesday as power generators burned record amounts of gas this week to keep air conditioners humming during the hottest part of a heat wave blanketing much of the country. That increase, however, came after prices fell over 4% to a three-week low on Monday on forecasts for less hot weather next week. Front-month gas futures rose 3.4 cents, or 2.1%, to settle at $1.675 per million British thermal units. On Monday, the contract closed at its lowest since June 26. As the weather turns hotter, data provider Refinitiv forecast U.S. demand, including exports, will rise from 92.3 billion cubic feet per day (bcfd) this week to 93.6 bcfd next week. The power industry consumed more than half of that gas, gobbling up a one-day record of 47.5 bcfd on Monday. Pipeline gas flowing to U.S. LNG export plants averaged 3.4 bcfd (35% utilization) so far in July, down from a 20-month low of 4.1 bcfd in June and a record 8.7 bcfd in February. Utilization was about 90% in 2019. U.S. pipeline exports, meanwhile, rose as consumers in neighboring countries cranked up their air conditioners. Refinitiv said pipeline exports to Canada averaged 2.4 bcfd so far in July, up from 2.3 bcfd in June, but still below the all-time monthly high of 3.5 bcfd in December. Pipeline exports to Mexico averaged 5.58 bcfd so far this month, up from 5.44 bcfd in June and on track to top the record 5.55 bcfd in March. Refinitiv said production in the Lower 48 U.S. states averaged 88.3 bcfd so far in July, up from a 20-month low of 87.0 bcfd in June but still well below the all-time monthly high of 95.4 bcfd in November.

US working natural gas volumes in underground storage rise 37 Bcf: EIA | S&P Global Platts - US natural gas in storage inventories ticked up slightly more than expected last week, prompting slight gains to the NYMEX Henry Hub balance-of-summer prices, which remained nearly 10 cents lower than the week prior. The amount of natural gas in US underground storage facilities increased 37 Bcf to 3.215 Tcf in the week that ended July 17, according to US Energy Information Administration data released July 23. The injection was above consensus expectations of analysts S&P Global Platts surveyed, which called for a 33 Bcf build. The injection was 8 Bcf below the 45 Bcf build reported for the same week in 2020, but matched the five-year average injection, according to EIA data. Storage volumes now stand 656 Bcf, or 25.6%, above the year-ago level of 2.559 Tcf and 436 Bcf, or 16%, above the five-year average of 2.779 Tcf. The build was less than the 45 Bcf injection reported the week prior as total supplies averaged 91.4 Bcf/d, up only 100 MMcf/d from a week earlier, as nominal changes in production were boosted slightly higher by net Canadian imports, according to S&P Global Platts Analytics. Downstream, total demand averaged 85.6 Bcf/d, with gains mostly centered on the power generation and residential-commercial markets, but widespread gains were limited across downstream sectors. The NYMEX Henry Hub balance-of-summer contract — August through October — rose 2 cents to $1.76/MMBtu in trading following the release of the weekly storage report, although that was 8 cents below the week-ago close. The gains have not extended into next winter, though, with the November-March contract strip holding flat at about $2.65/MMBtu as spreads between the two seasons are holding steady around 90 cents/MMBtu. Platts Analytics' supply-and-demand model currently forecasts a 20 Bcf injection for the week ending July 24, which would be 13 Bcf below the five-year average.

U.S. natgas jumps over 6% as heat keeps air conditioners cranked up - (Reuters) - U.S. natural gas futures jumped over 6% on Thursday, with a couple of storms brewing in the Gulf of Mexico and on forecasts for high air conditioning demand during a heat wave expected to blanket much of the country through at least early August. Prices rose despite a federal report showing an expected near-normal storage build. The U.S. Energy Information Administration (EIA) said U.S. utilities injected a near-normal 37 billion cubic feet (bcf) of gas into storage in the week ended July 17. Front-month gas futures rose 10.4 cents, or 6.2%, to settle at $1.785 per million British thermal units, their highest close since July 10. Tropical Depression 8 is expected to strengthen into a Tropical Storm in the Gulf of Mexico over the next day or two as it moves toward the Texas coast. Refinitiv said production in the Lower 48 U.S. states averaged 88.4 billion cubic feet per day (bcfd) in July, up from a 20-month low of 87.0 bcfd in June but still well below the all-time monthly high of 95.4 bcfd in November. With the weather expected to remain hot, Refinitiv projected U.S. demand, including exports, will hold around 92.7 bcfd this week and next. The outlook for next week was a little lower than Refinitiv's forecast on Wednesday. "Gas has been the fuel of choice for power generators looking to meet peak demand this month, and this fuel switching has helped absorb excess gas left by (coronavirus demand) destruction in the LNG and industrial sectors,"

August Natural Gas Futures Extend Rally as Demand Picture Brightens - Natural Gas Intelligence - August natural gas futures on Friday continued a rally ignited a day earlier as storage capacity concerns eased and robust power burns pointed to continued strong summer demand. The August Nymex contract gained 2.3 cents day/day and settled at $1.808/MMBtu Friday. That followed a double-digit advance on Thursday, which pushed futures to a two-week high. September climbed 3.2 cents to $1.867. NGI’s Spot Gas National Avg. rose 4.5 cents to $1.655. The pricing momentum gathered after signs of an improving liquefied natural gas (LNG) export environment and the U.S. Energy Information Administration’s (EIA) latest storage assessment, released Thursday, which showed an injection of 37 Bcf for the week ending July 17. It extended to four weeks a run of sub-100 Bcf additions to gas stockpiles. Shipbroker Fearnleys AS noted news reports of fewer U.S. LNG export cancellations heading into the fall and said the trend signals a potential recovery in the making. “After a very weak summer, expectations of an improving LNG trading environment appear to be bearing fruit as early estimates suggest September U.S. Gulf cargo cancellations are down considerably,” Fearnleys said. Traders surveyed by Bloomberg estimated that between 20 and 30 U.S. LNG export cargoes would not get loaded in September, but that would represent notable and continuing improvement. There were an estimated 50 cancellations for July and between 35-40 for August. U.S. LNG demand from leading consumers in Asia and Europe is gradually recovering with prices on both continents recently trading at a premium to the U.S. benchmark.The latest storage figure, meanwhile, amplified market sentiment on the intensity and broad geographic reach of this summer’s heat. Scorching temperatures are driving strong cooling demand and allaying worries about fall containment challenges. “We see the probability of hitting storage capacity becoming increasingly unlikely,” analysts at Tudor, Pickering, Holt & Co. (TPH) said. TPH estimated that storage would crest at 4.08 Tcf this year. With supply running 1 Bcf/d below its forecasts, however, analysts expect to see an additional 100 Bcf buffer against containment. “Additionally, record power burn” is “lining up for a tight print” with the next EIA storage report, the TPH analysts said. Their early modeling points to a build “in the 20 Bcf range, about half of normal levels.”

Natural Gas Forwards Slide Shows Sweltering Heat No Match for Weak Export Demand, Covid-19 - In an ominous sign of what may evolve to the end of the year, scorching heat across most of the country failed to spark a rally in natural gas forward prices for the July 16-22 period, according to NGI’s Forward Look. Instead, persistently weak global exports and continued uncertainty over the level of economic recovery amid Covid-19 drove prices about a nickel lower through the balance of summer (August-October) and the upcoming winter (November-March), Forward Look data show. Smaller shifts were seen for next summer and beyond.  Dismal liquefied natural gas (LNG) demand and robust salt storage inventories stood ready to quell any uptick in prices, according to EBW Analytics. Meanwhile, the pandemic and ongoing economic weakness “took the edge off” strong power burn figures, effectively thwarting any attempt to move higher.  The front of the Nymex futures curve held steady in the low $1.70/MMBtu range to end last week. However, on Monday, the August contract slumped to around $1.64 as weather models continued to lower the intensity of heat for the remainder of the month. Prices recovered a few cents by midweek, with the August contract at $1.681, the balance of summer at $1.745 and the winter at $2.662.The latest weather data continued to be less supportive than advertised earlier in the month, while still showing a hotter-than-normal pattern for the next 15 days. The largest errors in the modeling were in the Midwest, where, outside of a few days here and there, the big heat has mostly been a “no-show,” a trend that looked to continue at least for the next couple of weeks, according to Bespoke Weather Services.The cooler medium-range shift, around the end of the month into the opening of August, fits with what Bespoke expects to be a “temporary relaxation of the La Niña base state.” The firm still sees August winding up another hotter-than normal month, but tropical activity could dampen the outlook as a system brewing in the Gulf of Mexico (GOM) was set to bring rain to Texas through the weekend, limiting demand. On Thursday, the market appeared to breathe a sigh of relief after the Energy Information Administration (EIA)’s latest storage injection figure reflected what Bespoke said were “decently tight” supply/demand balances.The EIA said inventories for the week ending July 20 rose by 37 Bcf, which compares with a 44 Bcf storage build in the same week last year and a five-year average increase of 37 Bcf. Prior to the report, a Bloomberg survey found injection estimates ranging from 28 Bcf to 46 Bcf, with a median of 36 Bcf. The average of a Wall Street Journal poll was 35 Bcf, with a low estimate of 28 Bcf and a high of 41 Bcf. A Reuters poll found estimates ranging from 28 Bcf to 46 Bcf with an average injection of 36 Bcf. NGI estimated a build of 35 Bcf.

Will Buffett's $10 Billion Bet On Natural Gas Go Bust? - On the day on which Dominion Energy and Duke Energy canceled the Atlantic Coast natural gas pipeline, Dominion Energy said it would be selling substantially all of its gas transmission and storage assets to an affiliate of Berkshire Hathaway.  For Dominion Energy, the nearly US$10-billion deal, including debt assumption, is part of the company’s push to zero-carbon electric generation by 2050.     For Warren Buffett’s conglomerate Berkshire Hathaway, it was the first major acquisition since the start of the coronavirus pandemic, and the biggest acquisition in four years.  While there are growing calls from environmentalists that natural gas should follow coal’s fate and start being dumped from power generation because it’s not as clean as the ‘cleaner-than-coal bridge fuel toward renewables’ narrative would like us to think, Warren Buffett is unfazed.  Buffett is looking at the asset the way he has always done with his investments – buy cheap assets that very few others are willing to buy. And betting that these assets will deliver returns. Buffett’s bet on natural gas comes at a time when U.S. natural gas prices slumped to a 25-year-low, while natural gas is set to continue to dominate utility-scale electricity generation for years to come.  In 2019, natural gas accounted for 38 percent of utility-scale electricity generation in the United States, followed by coal with 23 percent, nuclear with 20 percent, and renewables including hydroelectric with 17 percent, according to EIA data.   Natural gas continues to displace coal-fired electricity generation, and so do wind and solar, but still, natural gas is expected to be the biggest source of power generation over the next few years.  Buffett’s US$10-billion bet on natural gas infrastructure shows that the billionaire investor believes that natural gas hasn’t run its course, regardless of what environmentalists and climate-conscious investors think.  Berkshire Hathaway Energy is buying Dominion Energy’s assets that include over 7,700 miles of natural gas transmission lines, 900 billion cubic feet of operated natural gas storage with 364 billion cubic feet of company-owned working storage capacity, and 25 percent in the Cove Point LNG export, import, and storage facility in Maryland.  Berkshire Hathaway Energy will thus own 18 percent of all interstate natural gas transmission in the United States, up from 8 percent now, according to CNBC.    The fact that this acquisition was the first one that Buffett saw as attractive after the pandemic sent markets into turmoil in March suggests that the Omaha investor believes in the future of natural gas.   “a bet that the future doesn’t come as fast as some people think,” Jim Shanahan, an analyst who covers Berkshire Hathaway at Edward Jones, told Bloomberg.

BOEM proposes Gulf of Mexico oil and gas lease for November 2020 --The Bureau of Ocean Energy Management (BOEM) is proposing to offer approximately 78.8 million acres for a region-wide lease sale scheduled for November 2020. Lease Sale 256, scheduled to be livestreamed from New Orleans, Louisiana, will be the seventh offshore sale under the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Program. Lease Sale 256 will include approximately 14 755 unleased blocks – all of the available unleased areas in federal waters of the Gulf of Mexico.“The Gulf of Mexico provides a fundamental role for our nation’s energy portfolio,” said Mike Celata, Director of BOEM’s Gulf of Mexico Region. “As one of the most productive basins in the world, the development of its resources is essential to our nation’s energy security.”The Gulf of Mexico Outer Continental Shelf (OCS), covering about 160 million acres, is estimated to contain about 48 billion bbl of undiscovered technically recoverable oil and 141 trillion ft³ of undiscovered technically recoverable gas.Revenues received from OCS leases (including high bids, rental payments and royalty payments) are directed to the US Treasury, certain Gulf Coast states (Texas, Louisiana, Mississippi, Alabama), the Land and Water Conservation Fund, and the Historic Preservation Fund.Leases resulting from this proposed sale would include stipulations to protect biologically sensitive resources, mitigate potential adverse effects on protected species, and avoid potential conflicts associated with oil and gas development in the region. In addition, the following areas are unavailable and excluded from the lease sale: blocks subject to the congressional moratorium established by the Gulf of Mexico Energy Security Act of 2006, blocks adjacent to or beyond the US Exclusive Economic Zone in the area known as the northern portion of the Eastern Gap, and whole blocks and partial blocks within the current boundaries of the Flower Garden Banks National Marine Sanctuary.

June spill at New Orleans East oil terminal still being cleaned up - Workers continue to clean up the remains of more than 2,000 barrels of crude oil that leaked out of a storage tank at the Gulf Gateway Terminal on Terminal Road in New Orleans East on June 22, according to company officials and the state Department of Environmental Quality. Oil was still visible from the air on July 12 in a small area adjacent to the tank that is surrounded by an earthen containment dam, according to a photo taken by representatives of the Healthy Gulf environmental group. The terminal is the interim destination for dozens of tank cars moved by rail by the New Orleans Public Belt railroad and by BNSF Railway. More than 100,000 barrels of crude a day can be transferred from the cars to barges and ships docking at the terminal. Many of the railcars travel through the French Quarter on their way to the terminal. In an email sent to DEQ soon after the spill, terminal manager Stephen Champagne said 2,032 barrels of light sweet crude leaked from the storage tank, and that company officials immediately pumped the remaining 73,746 barrels of crude oil out of the leaking tank and into barges on the waterway. The company also transferred oil from several railcars at its site to barges "to create space for storage of the collected product as well as the remaining product sucked off the tank bottom." The oil that spilled was being collected and stored in either small temporary holding tanks or railcars at the site, he said. "The collected product will be sampled to determine if it can be processed by refineries," Champagne said in the note. If not, it would be properly disposed offsite, he said. The company also reported the spill to the U.S. Coast Guard National Response Center and the Louisiana State Police. DEQ inspectors who visited the site said in an initial report that a contractor was hired by the company to collect a combination of oil and rainwater from inside the earthen containment area. Air monitoring by the inspectors found 20 parts per million of volatile organic compounds in the air on the day of the spill and 10 parts per million of benzene the next day.

Oil & gas company BJ Services to lay off 273 in Shreveport following bankruptcy filing -– Another Northwest Louisiana employer in the oil and gas industry has filed for bankruptcy and announced layoffs.According to the latest Worker Adjustment and Retraining Notification (WARN) notice updated by the Louisiana Workforce Commission, BJ Services plans to lay off 273 employees in Shreveport on August 2.Under federal law, employers are required to provide advance notice of plant closures or mass layoffs.The Texas-based company provides hydraulic fracturing and cementing services to upstream oil and gas companies and has operations in every major basin throughout the U.S. and Canada. The company filed the WARN notice with the LWC on Sunday and filed for voluntary Chapter 11 bankrupcty on Monday.  According to a statement released by the company, the plan is to sell its assets and is in active discussions with bidders regarding both the cementing business and portions of the fracturing business. The statement said the company believes the sales would reduce the number of jobs impacted by this process. “The industry continues to face unprecedented uncertainty caused by volatile commodity markets and significantly reduced demand due to the COVID-19 pandemic. Despite maintaining a leading market position and strong client support, the severe downturn in activity and subsequent lack of liquidity resulted in an unmanageable capital structure. After exhausting every possible alternative to address these issues and improve our liquidity, we have made the very difficult decision to proceed with a Chapter 11 process,”

'A win-win': Plugging Louisiana's 4,300 'orphaned' wells could boost industry, cut emissions --A federally funded stimulus program aimed at plugging the growing number of “orphan” oil and gas wells could greatly reduce pollution while giving a much-needed boost to the state’s ailing oil industry, a new report says. As Congress considers a new stimulus package of several trillion dollars to assist with the economic impacts from the coronavirus pandemic, a group of energy policy experts has published a report making the case that a fraction of the money should go toward plugging the millions of wells that have been abandoned by their owners and are now the responsibility of state governments. Louisiana has documented nearly 4,300 such wells, and the number is expected to rise as more companies shut down wells due to low oil prices and a faltering economy.“Plugging wells is a win-win opportunity that would provide good work for people negatively affected by the downturn in the economy and provide environmental benefits,” said Daniel Raimi, a public policy researcher and co-author of a report by Columbia University and Resources for the Future, a Washington D.C. environmental policy think tank.Plugging all of Louisiana’s orphan wells could employ just over 1,000 oil workers full-time for one year. It would also cut methane emissions by 558 metric tons per year, according to the report’s metrics. That’s the equivalent of the annual greenhouse gas emissions from more than 3,000 cars.Gifford Briggs, president of the Louisiana Oil and Gas Association, supports a federal stimulus for well plugging. He said many unemployed oil workers and struggling companies in Louisiana have the skills and equipment to begin doing such work today.“There are multiple layers of benefits,” he said. “It gives the opportunity to put people back to work and money back in our communities … and it continues to improve our environment.”

Tellurian evaluates changes to Driftwood LNG project, plans shares issue -(Reuters) - Tellurian Inc is considering changes to its Driftwood LNG export project in Louisiana that could significantly reduce the overall Phase 1 costs, the U.S. liquefied natural gas producer said on Wednesday. The company also disclosed plans to issue 35 million shares at $1 each, a 37% discount to Tuesday’s close, sending its stock plunging 27%. Shares surged more than 50% on Tuesday after sources said India’s Petronet LNG renewed a deal to give the parties more time to finalize an investment in the project. LNG developers have delayed numerous projects as the COVID-19 pandemic sapped overall fuel demand and hammered gas prices. Natural gas was trading at $1.65 per million British thermal units, about 30% lower than a year earlier. Tellurian has said the Driftwood project, designed to produce 27.6 million tonnes per annum of LNG, is expected to cost $27.5 billion, including pipelines. About $15.4 billion of the estimate is for a contract with Bechtel Oil, Gas and Chemicals Inc to build the export plant. Tellurian did not provide details on the cost cuts, but Scotiabank analysts said the reduction could mean the potential removal of the Permian pipeline, which could lead to savings of $4.2 billion. The equity offering will boost Tellurian’s liquidity to about $123 million on a pro forma basis, and Scotiabank analysts estimated could provide the company “sufficient runway until July 2021” based on a $6 million monthly cash burn.

INVESTIGATION: Lethal fog smothers Texas oil sites as inspections lag -- Tuesday, July 21, 2020 --  ODESSA, Texas — Permits are rising for handling hydrogen sulfide — a toxic byproduct of oil production that has killed workers. But an E&E News investigation shows little attention is being paid to making sites safer.

Oil-and-gas money flows to Railroad Commission nominee who pledged to recuse himself -  Back in March, when Jim Wright, with little money in his campaign account, was an obscure Republican primary challenger to a sitting state oil and gas regulator, he pledged to recuse himself from matters involving campaign contributors. But Wright is now qualifying his pledge as recent campaign finance reports show hundreds of thousands of dollars from oil and gas interests flowed his way after his out-of-nowhere upset primary victory in March. In an interview Wednesday, Wright told the American-Statesman that should he be elected in November to the Railroad Commission, the state agency that regulates the oil and gas industry, he would recuse himself only on matters that involved contributors who give money directly ahead of a commission vote. Environmentalists and watchdog groups have long referred to the Railroad Commission as a “captured agency” — its three elected commissioners, all Republicans, receive the bulk of their campaign contributions from the industry they regulate and have historically been sympathetic to its interests. The close relationship — coziness, say critics — between industry and its chief regulators runs through to the Legislature. In 2016, the staff of the Sunset Advisory Commission, which reviews agency functions, recommended the commission, which no longer has anything to do with railroads, change its name to the Texas Energy Resources Commission to make its work more transparent. The move was opposed by oil and gas interests, and state Rep. Tom Craddick, R-Midland, the long-serving influential member representing the oil-rich Permian Basin — and father of Christi Craddick, one of the three current railroad commissioners — successfully led the effort to quash it.

Watchdog group sues Railroad Commission over oil storage crisis orders - The Austin office of watchdog group Public Citizen has sued the Texas Railroad Commission, the state's oil and gas regulator, over emergency orders in May that waived fees and relaxed regulations for the storage of crude. In response to a glut of crude and rapidly dwindling room to store it, the agency's three commissioners voted May 5 to enact orders that waived fees and charges for construction of new oil storage projects through the end of the year. Commissioners also gave oil companies more time to store waste in open pits and to plug abandoned wells. Public Citizen filed its suit Wednesday in state district court alleging that commissioners used the coronavirus pandemic to give handouts to industry — and that they did so without public input, skirting laws such as the Texas Public Meetings Act. Record low oil prices have caused a drop in demand for oil and natural gas and an uptick in bankruptcy filings, which Public Citizen argues will mean that more tax dollars will be spent on cleaning up abandoned wells. The Railroad Commission does comment on litigation but the agency contends that all the action taken during its May 5 meeting complied with state and federal laws. “These legal, emergency actions protect the Texas Miracle while ensuring the environment is protected," Railroad Commission Chairman Wayne Christian said in a statement. "This complaint is no more than a proxy for fringe extremists to advance their goal of eliminating the domestic production of fossil fuels, a move that would kill 3.2 million jobs, increase energy and gasoline costs by $2,500 a year for American families, and cost Texas $1.5 trillion in GDP between 2021-2025.”

Permian Gains Give Oomph to US Drilling Permits in June, but Recovery to 2019 Levels Not in Sight - Requests for U.S. drilling permits improved in June following a brutal April and May, with the Permian Basin still the top region for operators, according to Evercore ISI. The analyst firm each month compiles permitting statistics for the Lower 48 and offshore using federal and state data. Covid-19 and low commodity prices had crushed permit requests in April, with May possibly the bottom, analyst James West said. According to Evercore, 1,238 permits were approved in June, up by 166 month/month (m/m). However, permitting was off by 66% year-to-date and 77% from June 2019. Most of the new permitting activity in June was focused on the Permian, with 109 more m/m, and in the Bakken Shale, which had 11 more requests than in May.“Permian operators received approval for 381 wells with 70% generated by public companies, 2% by equity sponsored operators, and the remainder originated from private ones,” West noted. The Bakken permit count improved in June to 67, 11 higher m/m. Public E&Ps requested 94% of all the permits, Evercore noted. Operators also increased their permit requests in the Mississippian Lime, up by 11 from May, and in Oklahoma’s Woodford formation, with nine more permits requested.The year-to-date oil permit count at mid-year stood at slightly under 10,000, with more than one-third (36%) for the Permian, Evercore noted. However, Permian permitting remained sharply lower, off by around 32% year/year at 3,618 to date. While the permit count is down from 2019, there has been a “steep fall” in the Powder River Basin, off by 97% year/year, and in the Denver-Julesburg (DJ)/Niobrara formation, which has seen permitting decline by 80%, Evercore analysts noted.Natural gas permitting also has slumped sharply, with the mid-year total at 1,128 in June, down by 48% year/year. The decline was blamed primarily on a deceleration in the Marcellus Shale, which had seen permits decrease by 54%.Meanwhile, in the other big dry gas play, the Haynesville Shale, private operators drove an uptick in permits during June, with 25 more requests m/m. Gas permits in the play stood at 142 in June, up by 40 m/m.Meanwhile,  Ohio regulators, who oversee permitting in the Utica Shale, authorized 16 wells to be drilled, up by 15 m/m, with 36% for plugging and abandonment (P&A), according to Evercore.

Texas regulator proactively inspects Permian Highway Pipeline construction - Inspectors with the Railroad Commission of Texas are continuing critical inspections of the Permian Highway Pipeline (PHP), one of the largest pipeline projects under construction in Texas in 2020. Stretching more than 400 miles from the Permian Basin to the Houston area, the pipeline will bring West Texas’ natural gas to the world market. Given the sheer scale of the PHP and its route through the sensitive Texas Hill Country, RRC has engaged in a comprehensive response to ensure that the pipeline is constructed safely in a manner protective of public health and the environment. Since March inspectors from two key RRC divisions, Oil and Gas and Pipeline Safety, have conducted more than 75 inspections and investigated close to 20 complaints related to the pipeline. Currently RRC inspectors are on-site near the Pedernales River in Gillespie County as the pipeline operator, Kinder Morgan, works to excavate a pathway for the pipeline beneath the river. “Our inspectors have been hard at work, even during the COVID-19 pandemic, to ensure Kinder Morgan is compliant with Commission rules that are in place to protect public safety and natural resources,” said RRC Executive Director Wei Wang. “In addition to the all-hands efforts within the agency, we are also in contact with resident groups and the company as construction progresses. When it is complete, this pipeline will add vital capacity to convey natural gas, which in turn will also help ongoing efforts to further reduce flaring in West Texas.” New pipelines are important to efficiently and safely transport large amounts of natural gas and oil. The Texas Pipeline Association estimates that a 20-inch pipeline running 50 miles can replace 1,650 tanker trucks carrying oil on the road. Pipelines also help reduce flaring by alleviating potential backing up of supply at the point of production.

Kinder Morgan posts $637 million loss in second quarter - Houston pipeline operator Kinder Morgan saw its second-quarter bottom line take a billion dollar swing from a profit to a loss as it wrote down $1 billion in assets.The company lost $637 million in the three months ended in June compared with a profit of $518 million in the same period a year earlier. The company’s results translated into a loss per share of 28 cents, compared with an earnings per share of 23 cents one year earlier. Facing a significant reduction in energy demand during the second quarter, Kinder Morgan’s second quarter revenue declined by 20 percent to nearly $2.6 billion from $3.2 billion in the same period a year earlier. Kinder Morgan wrote down the value of $1 billion worth of intrastate and gathering pipelines that move natural gas in states such as North Dakota, Oklahoma and Texas. Without that non-cash impairment, the company would have made a $363 million profit in the second quarter.The write down follows first quarter move where the company marked down the value of equipment from its carbon dioxide business and its oil production operations in the Permian Basin of West Texas by $950 million. Despite the second quarter loss, the company is keeping its dividend for stockholders at 26.5 cents per share. As part of a plan to maintain that dividend, the company is cutting $660 million of a $2.4 billion budget that was marked for expansion projects this year.

Oil and gas experts believe more layoffs could happen soon due to pandemic - (KTRK) -- Industry experts said with the recent spike in COVID-19 cases, and as the pandemic continues to ravage the oil and gas industry, there will be more job cuts. Ramanan Krishnamoorti is a professor at the University of Houston Department of Chemical and Biomolecular Engineering. He said with people traveling less, the demand for fuel took an immediate hit as soon as the lockdowns started. Demand picked up some when the reopening phases began, but with the resurgence of the virus in many states, the tide has turned again. "The industry is in big trouble," Krishnamoorti said. "You're going to see a lot of bankruptcies, a lot of furloughs, more than furloughs. You're going to see layoffs. You're going to see people leave this entire industry because there aren't going to be jobs." Along with even more job losses on the horizon, Krishnamoorti said to expect consolidation from big companies taking over smaller ones, like Chevron's buyout of Noble Energy. In a call with the Texas Oil and Gas Association, Chevron CEO Michael Wirth spoke about the acquisition of Noble Energy, saying the companies are a good fit. He also addressed the grim situation the industry's facing. "Gasoline demand has come back significantly, and aviation fuel not so much, because there's still a reluctance on the part of many people to get on airplanes," Wirth said. Wirth remained more optimistic about the longer term outlook. "The demand for energy is going to grow," he said.

New Emails Show How Energy Industry Moved Fast to Undo Curbs - The New York Times — Not long after President Trump’s inauguration, the head of a fossil fuels industry group requested a call with the president’s transition team. The subject: Barack Obama’s requirement that oil and gas companies begin collecting data on their releases of methane.That outreach, by Kathleen Sgamma, president of the Western Energy Alliance, appeared to quickly yield the desired results.“Looks like this will be easier than we thought,” David Kreutzer, an economist who was helping to organize the new president’s Environmental Protection Agency, wrote of canceling the methane reporting requirement in an email to another member of the transition team on Feb. 10, 2017.Three weeks after that email, the E.P.A. officially withdrew the reporting requirement — and effectively blocked the compilation of data that would allow for new regulations to control methane, a powerful climate-warming gas. The emails are included in hundreds of pages of E.P.A. staff correspondence and interviews recently made public in a lawsuit that 15 states have brought against the agency over the regulation of methane. Led by Massachusetts and New York, the states say the documents prove that fossil fuel industry players, working with allies in the early days of Mr. Trump’s E.P.A., engineered the repeal of the methane reporting requirements with no internal analysis, then created the rationale for the decision after the fact.That repeal, the states assert, illegally delayed the development of additional regulations to reduce methane emissions that the administration did not want.If the states succeed, a judge could, as early as this summer, order the federal government to impose restrictions on thousands of oil and gas wells, storage facilities and pipelines across the United States. Just last week, a federal court, restoring an Obama-era regulation, struck down a Bureau of Land Management effort to weaken restrictions on methane gas releases from drilling on public lands.In that case, Judge Yvonne Gonzalez Rogers ruled that the Trump administration, in its “haste” and “zeal,” failed to properly justify its rollback.“In the early days they did very little justification,” said Richard Revesz, a professor of environmental law at New York University and director of the Institute for Policy Integrity, the university’s nonpartisan think tank. So far, only about 10 percent of the Trump administration’s deregulatory efforts have held up in court, according to the institute, compared to an average of 70 percent for other administrations, both Republican and Democratic.“They justify their policies on analytically flimsy or sometimes nonexistent grounds, thinking, I guess, that they will get away with it,” Mr. Revesz said. “But time and again, the courts say no.”Methane, which leaks from oil and gas wells, accounts for about 10 percent of greenhouse gas emissions from human activity in the United States, according to E.P.A. data. But it is about 30 times more potent over the course of a century than carbon dioxide in altering the Earth’s climate and is responsible for about a quarter of man-made global warming..”

Now that half of Oklahoma is officially Indian land, oil industry could face new costs and environmental hurdles - On top of all the turmoil Oklahoma oil producers have had to deal with since the start of the coronavirus pandemic, the Supreme Court has added another item to that list: a landmark decision declaring nearly half of eastern Oklahoma to be Native American land.With the high court’s ruling, oil and gas drillers in the nation’s fourth largest oil-producing state suddenly find themselves operating within the Muscogee (Creek) Nation and four other tribal reservations.About a quarter of Oklahoma’s recent oil and gas wells and around 60 percent of its refinery capacity now lie within the territory of five tribes — the Cherokee, Chickasaw, Choctaw, Creek and Seminole. Perhaps more importantly, the network of pipelines pumping crude to and from Cushing, Okla. — a crucial oil terminal for the Keystone XL — spider-web across the redrawn reservation borders. Instead of dealing with business-friendly regulators from the state of Oklahoma, oil producers may soon have to contend with both tribes and the federal government, which often manages land for Native Americans. “The reality is that there’s something potentially that could be very detrimental to the oil and gas industry,”  With Americans driving and flying less during the viral outbreak, U.S. oil prices have dropped by a third since the start of the year. Oklahoma’s shale fields, where extraction costs are relatively high, are among the hardest hit during the pandemic. One of the state’s biggest energy firms, the fracking pioneer Chesapeake Energy, has already declared bankruptcy.  The 5-to-4 decision, written by Justice Neil M. Gorsuch and joined by the court’s liberals, ostensibly deals with criminal law for the ancestors of those forced to march the 19th century Trail of Tears into present-day Oklahoma. But the majority opinion writers acknowledge the ruling raises big questions over taxation and the enforcement of environmental rules across those 3 million acres — ones that may take years to settle.

What factors influence the likelihood of fracking-related seismicity in Oklahoma? -  The depth of a hydraulic fracturing well in Oklahoma, among other factors, increases the probability that fracking will lead to earthquake activity, according to a new report in the Bulletin of the Seismological Society of America.The researchers hope their findings, published as part of an upcoming BSSA special issue on observations, mechanisms and hazards of induced seismicity, will help oil and gas operators and regulators in the state refine drilling strategies to avoid damaging earthquakes.During hydraulic fracturing, well operators inject a pressurized liquid into a rock layer after drilling vertically and often horizontally through the rock. The liquid breaks apart—fractures—the rock layer and allows natural gas or petroleum to flow more freely. A growing number of studies suggest that this process can induce seismic activity large enough for people to feel, possibly by increasing fluid pressures within the rock that relieve stress on faults and allow them to slip.In one rock layer examined in the BSSA study, the likelihood that hydraulic fracturing triggered seismic activity increased from 5 to 50 percent as well operations moved from 1.5 to 5.5 kilometers (0.9 to 3.4 miles) deep, the researchers found.Although the exact mechanisms linking well depth and seismic probability are still being examined, Michael Brudzinski and colleagues suggest that the overpressure of fluids trapped inside the rock may be important."The deeper the rock layers are, the more rock that is sitting on top of a well, and that is going to potentially increase the fluid pressures at depth," said Brudzinski, the study's corresponding author from Miami University in Ohio.Oklahoma has been at the center of a dramatic increase in earthquake activity over the past decade, mostly caused by oil and gas companies injecting wastewater produced by drilling back into deeper rock layers. However, a 2018 study identified places in the state where significant amounts of seismic activity were linked to nearly 300 hydraulic fracture wells.Hydraulic fracturing is associated with a magnitude 4.6earthquake in Canada and a magnitude 5.7 earthquake in China, although fracking-induced earthquakes tend to be smaller in magnitude than those caused by wastewater disposal. As a result, oil and gas operators and regulators would like to know more about why some wells trigger seismic activity, and how to adjust their operations to prevent damaging earthquakes.

Treaty rights at center of tribal opposition to Line 5 pipeline, tunnel --An oil spill in the Straits of Mackinac would not only be an environmental disaster, but also it would threaten the economic livelihoods of tribes who fish the area while devastating a vital cultural site.The five tribes composing the Chippewa Ottawa Resource Authority (CORA) say the the threat of a pipeline spill from Line 5 endangers their rights to hunt and fish in the area included under the 1836 Treaty of Washington, which effectively gives them property rights across a wide swath of the Lower Peninsula and the eastern half of the Upper Peninsula — all of which Line 5 runs through. While tribes say a plan finalized under the administration of former Gov. Rick Snyder to build a tunnel under the Great Lakes bottomlands also jeopardizes their treaty rights, CORA’s goal is to decommission the pipeline as it exists today.“The pipeline itself and any future tunnel project still present risk to the natural resources in the Straits,” said Whitney Gravelle, tribal attorney for the Brimley-based Bay Mills Indian Community. “Though the focus has been on the Straits of Mackinac … we feel Enbridge is specifically painting this picture of just a couple miles of pipeline. But if there was a rupture anywhere along the pipeline, it would threaten and diminish those treaty rights of the five tribes.” The CORA member tribes are the Bay Mills Indian Community, Grand Traverse Band of Ottawa and Chippewa Indians, Little River Band of Ottawa Indians, Little Traverse Bay Bands of Odawa Indiansand the Sault Ste. Marie Tribe of Chippewa Indians.Until now, the tribes haven’t been formally involved in Attorney General Dana Nessel’s two lawsuits challenging Enbridge Energy and the tunnel plan. However, they are seeking to formally intervene in proceedings before the Michigan Public Service Commission involving tunnel construction. The CORA tribes — along with environmental groups — also submitted written comments to the Army Corps of Engineers this month requesting a public hearing on the tunnel proposal.

Enbridge-contracted vessels among those suspected in Line 5 damage - Enbridge-contracted vessels may be to blame for recent damage to the east leg of the Line 5 pipeline in the Straits of Mackinac, according to a report written by the Canadian pipeline giant. Based on vessel tracking and marine experts, Enbridge narrowed down to five the list of "small to moderately-sized" vessels that could have dragged a cable in a north and south direction over Line 5. The cable scraped the east leg and damaging an anchor support holding up the segment. Four of the five boats are Enbridge-contracted vessels. Enbridge interviewed the operators of its contracted vessels, which were in the water to perform maintenance and activities related to the Great Lakes Tunnel Project, and obtained their logs, procedures and plans, according to a report submitted Wednesday to the state and the Pipeline and Hazardous Materials Safety Administration. In interviews, the vessel operators weren't aware of an incident that would have created the damage, according to the report. "As of now we can’t rule out their involvement," Enbridge spokesman Ryan Duffy said Thursday. "Enbridge will continue to investigate, but it may not be possible to definitively identify the specific vessel that caused the incident." Line 5, which transports up to 540,000 barrels a day of light crude oil, light synthetic crude and natural gas liquids, has been the subject of a years-long dispute over a possible rupture of the 67-year-old pipeline in the Great Lakes. Enbridge is in the process of constructing a tunnel to hold the pipeline, but has encountered headwinds from state regulators and leaders worried about the line's continued presence in the Straits. The state still is reviewing the 45-page report that summarizes the company's investigation into four separate areas of potential impact found in May and June inspections, all of which the company believes to have been caused by at least two "small to moderately-sized" ships dragging some sort of cable. The company maintains the damage done to the pipeline was not enough to threaten the safe operation of either segment. Under court order, Enbridge currently is only able to operate the west segment until federal regulators deem the east leg safe.

State calls for Enbridge to prove it can cover costs of potential Line 5 pipeline spill - The director of the Michigan Department of Natural Resources wants the owner of a controversial pipeline to promise to cover any losses related to the line.The Line 5 pipeline carries crude oil and natural gas liquids under the Straits of Mackinac.“As recent events have reminded us, we must get these pipelines that transport crude oil out of the Great Lakes as soon as possible,” said DNR Director Dan Eichinger in a statement. “In the meantime, Enbridge must provide full financial assurance to the people of Michigan that the company will meet its obligations in the event there is a spill or some other disastrous damage to the Great Lakes.”Eichinger said the state currently has a deal with Enbridge Inc., a subsidiary of Enbridge Energy Company Inc. to compensate the state for any damages and losses that come from the operation of Line 5, like a spill. But he said the subsidiary does not have the resources to cover the cost of a spill. The state wants the following, in writing, from the parent company, Enbridge Inc.:

• Enbridge Inc., the parent company, agrees to assume the indemnity obligations of Enbridge Energy Company, Inc.
• Enbridge Inc. agrees to a minimum of $900 million in liability insurance.
• Enbridge Inc. names the State of Michigan as an additional insured party on the identified policies so that Michigan’s right of recovery is not derivative.
• Enbridge Inc. will directly pledge its own assets for the remainder of the financial assurance requirements (to meet or exceed $1.878 billion, annually adjusted for inflation).

Whitmer: Enbridge dodging responsibility for potential spill — Gov. Gretchen Whitmer criticized Enbridge Inc. on Wednesday for what she described as the company's refusal to make an airtight pledge to pay for damages caused by a potential oil spill from its pipeline beneath a Great Lakes channel.The Democratic governor's administration is pressuring the Canadian pipeline company for an explicit acknowledgment of financial responsibility for any release from its Line 5 into the Straits of Mackinac. Enbridge insists it already made such an assurance under a 2018 agreement with former Republican Gov. Rick Snyder to construct an underground pipeline tunnel beneath the straits.“I’m shocked at Enbridge Inc.’s refusal so far to sign a written agreement promising to cover the costs of an oil spill in the Great Lakes if this unthinkable event were to happen,” Whitmer said in a statement.“When I was a kid, my parents taught me: ‘You break it, you pay for it.’ It seems that’s the bare minimum Enbridge owes every Michigander so long as the company continues to pump crude oil through the Straits of Mackinac.Line 5 carries oil and liquids used in propane from Superior, Wisconsin, to Sarnia, Ontario. A nearly 4-mile-long (6.4-kilometers-long) segment, laid in 1953 beneath the Straits of Mackinac, is divided into two pipes.The straits connects Lake Huron and Lake Michigan. It is a popular tourist draw and has cultural and economic importance to native tribes that operate commercial fishing vessels in the area.The state is asking Enbridge to carry $900 million of liability insurance and have about $1.88 billion in additional assets available for a worst-case rupture in the straits. Enbridge says it's doing so under the 2018 tunnel agreement with Snyder.

20 states sue over Trump rule limiting states from blocking pipeline projects  - A coalition of 20 states is suing the Environmental Protection Agency (EPA) over a rule that weakens states’ ability to block pipelines and other controversial projects that cross their waterways. The Clean Water Act previously allowed states to halt projects that risk hurting their water quality, but that power was scaled back by the EPA, a move Administrator Andrew Wheeler said would “curb abuses of the Clean Water Act that have held our nation’s energy infrastructure projects hostage.” The suit from California and others asks the courts to throw out the rule, which was finalized in June. “Let's be clear, this Trump administration rule is not about water quality. This is about pushing forward fossil fuel energy infrastructure,” said California Attorney General Xavier Becerra (D), calling the Clean Water Act “the only way to prove that these projects comply with state law.” The Clean Water Act essentially gave states veto authority over projects by requiring projects to gain state certification under Section 401 of the law. It applies to a wide variety of projects that could range from power plants to waste water treatment plants to industrial development. But that portion of the law has been eyed by the Trump administration after two states run by Democrats have recently used the law to sideline major projects. New York denied a certification for the Constitution Pipeline, a 124-mile natural gas pipeline that would have run from Pennsylvania to New York, crossing rivers more than 200 times. Washington state also denied certification for the Millennium Coal Terminal, a shipping port for large stocks of coal. The EPA would not comment on the litigation directly but said that “prior to issuing this final rule, EPA’s water quality certification regulations were nearly 50 years old.” “The agency’s recent action reflects the first comprehensive analysis of the text, structure and legislative history of Clean Water Act Section 401. As a result, the agency’s final rule increases the transparency and efficiency of the Section 401 certification process in order to promote the timely review of infrastructure projects while continuing to ensure that Americans have clean water for drinking and recreation," the agency said. The new policy from the Trump administration accelerates timelines under the law, limiting what it sees as state power to keep a project in harmful limbo. The need for a Section 401 certification from the state will be waived if states do not respond within a year. But states argue the new rule won’t give them the time necessary to conduct thorough environmental reviews of massive projects. Read more about the lawsuit here. 

Standing Rock seeks to keep Dakota Access shutdown order in place  - The Standing Rock Sioux Tribe is asking a panel of federal judges to keep in place a lower court’s ruling ordering the Dakota Access Pipeline to shut down while the decision is appealed, saying the pipeline’s continued operation exposes the tribe to “catastrophic risks.” Standing Rock, along with other Sioux tribes that are part of the lawsuit over the pipeline, filed a brief Monday in response to a plea by developer Energy Transfer and the U.S. Army Corps of Engineers to put the shutdown order on hold while they seek to overturn the ruling.  “The operation of the pipeline, on unceded lands yards upstream of the Standing Rock Sioux Reservation, compounds historical trauma and subjects the Tribes and their members to the stress of living under an existential catastrophe,” the tribes said in the brief.  The Standing Rock Sioux Reservation lies just south of the pipeline’s Missouri River crossing. Tribal members fear an oil spill at that site could devastate their water supply and affect their hunting, fishing and spiritual practices.  U.S. District Judge James Boasberg earlier this month revoked a key permit for the pipeline and ordered that the line be shut down and emptied of oil by Aug. 5. The pipeline would have to remain unused for the duration of a lengthy environmental review that he ordered this past spring. The study is expected to take at least 13 months. Energy Transfer and the Corps, which permitted the pipeline’s water crossings, are appealing his recent rulings to the U.S. Court of Appeals for the District of Columbia Circuit, where a panel of three judges last week immediately put a temporary “administrative” hold on the shutdown order until they could hear arguments from both sides. The tribes say the risks imposed by the pipeline “have never been properly examined as the law requires, and compounds a history of government-sponsored dispossession of Tribal lands and resources.” A formal response from Energy Transfer and the Corps is expected later this week. Energy Transfer has said it anticipates taking a revenue hit of at least $2.8 million every day the line sits idle during a shutdown. It expects additional costs associated with emptying the pipeline of oil and filling it with a gas such as nitrogen to prevent it from corroding.

Second Bakken pipeline shutdown further threatens shale recovery  --Earlier this month, a federal judge stunned the U.S. energy sector with an order to shut down the Dakota Access pipeline. Environmentalists hailed it as the first time a fully operating system had been forced to close by a legal challenge. As it turns out, it was actually the second time an oil pipeline was ordered shut in a matter of four days. On July 2, a lesser-known conduit called Tesoro High Plains was ordered shut for the first time in its 67 years of operation. Together, the two pipelines ship more than one-third of crude from America’s prolific Bakken shale formation to market. Their travails signal the ebbing of the oil industry’s sway in the U.S. heartland and underscore the growing heft and savvy of challengers who’ve become emboldened to demand higher compensation and safeguards. “In the past, it was a shotgun approach of challenging pipelines,” said Brandon Barnes, an analyst for Bloomberg Intelligence. “Now, the resources are more plentiful and the challengers are far more nuanced and sophisticated in their approach.” The stakes are high. If the shutdown of both pipelines proceeds, it would force the region’s drillers to turn to more expensive options to ship their oil -- or shut in production altogether, just as the entire oil industry is reeling from depressed prices that have pushed a steady stream of producers into bankruptcy. The outlook for the U.S. pipeline industry has perhaps never been more uncertain. Earlier this month, Dominion Energy Inc. and its partner Duke Energy Corp. announced they were no longer moving forward with their $8 billion Atlantic Coast natural gas pipeline after years of delays and ballooning costs. In the ensuing 24 hours, the Supreme Court left in force a lower court order blocking the start of construction on TC Energy Corp’s Keystone XL pipeline, while a district court ordered the shutdown of Dakota Access (although that project scored temporary relief last week). In the case of High Plains, which delivers oil to Marathon Petroleum Corp.’s 74,000 barrel-a-day Mandan refinery, the U.S. Interior Department’s Bureau of Indian Affairs ordered it shut after determining the pipeline was trespassing on Native American land. The ruling also found the company responsible for $187 million in damages and gave it 30 days to appeal.

Uncertainty, concerns surround potential oil train resurgence - While lawyers fight over a federal judge’s order to temporarily shut down the Dakota Access Pipeline, the oil industry is grappling with uncertainty as it ponders how to keep shipping Bakken crude to market. The questions on everyone’s mind: Will the pipeline actually be forced to halt operations, and when? Many observers anticipate a shutdown could result in a resurgence of trains carrying Bakken crude, a prospect that has rail safety advocates and farmers concerned. Whether more oil trains hit the tracks depends on the outcome of the latest legal maneuvering over the pipeline. At the moment, the order to shut down the line is on an “administrative” hold as the case moves to a panel of judges on a federal appeals court. The shutdown order came July 6 from U.S. District Judge James Boasberg, who for four years has overseen a lawsuit launched by the Standing Rock Sioux Tribe. The tribe’s reservation lies just south of the pipeline’s Missouri River crossing in North Dakota, and tribal members worry a potential oil spill could devastate their water supply. Boasberg ordered pipeline developer Energy Transfer to idle the line for the duration of a lengthy environmental review expected to last at least 13 months, and for the company to drain it of oil by Aug. 5. In the days ahead, the appellate judges will consider arguments on whether the pipeline must halt operations while the U.S. Army Corps of Engineers and Energy Transfer appeal Boasberg’s shutdown order and his earlier ruling requiring the environmental study. The short-term hold buys the oil industry a little more time to prepare for a potential shutdown of Dakota Access, which has been operating for three years and can transport up to 570,000 barrels per day of oil from North Dakota to Illinois. That amount equaled 40% of North Dakota’s daily oil output before the coronavirus pandemic hit, sending oil demand, prices and production plummeting.Several experts anticipate that a shutdown of Dakota Access would eventually prompt oil companies to ship another 200,000 barrels per day of Bakken crude via rail, the equivalent of about three more oil trains leaving the region each day. The shift would not happen overnight but likely would occur gradually over the course of the next year, assuming oil production slowly ticks back up as prices rise,

North Dakota has ample rail capacity for oil -A judge ordered the Dakota Access pipeline (DAPL) to shut down because permitting laws were not followed. The reactionary response from our elected officials and oil barons is that if the pipeline shuts down “the sky will fall.”Wayne Stenehjem, our attorney general, and some guy from Douglas named Real Mercier both plied for farmer support by claiming that shutting down the pipeline could hurt farmers because added oil trains will crowd out grain that needs to be shipped to market.The opposite is true.Shutting down the pipeline would add only eight oil trains a day to our state’s rail system. I was a locomotive engineer for 30 years in North Dakota and there were times when we had 125 trains a day passing through Fargo. Now that city has only about 50 trains a day and hundreds of North Dakota railroad workers have been laid off because of this drop in traffic.In the 1960s and 70s North Dakota’s rail lines were in shambles because of the building of the interstate highway system and the diversion of freight from the rails to the highways. Then along came Powder River Basin coal and container trains from Asia. This pass through freight rebuilt our rail lines to the tremendous benefit of North Dakota farmers. Shipping oil by rail doesn’t just benefit rail workers and our state’s railroads, revenue from shipping oil helps pay for the maintenance of our entire rail system and that benefits other shippers like farmers who depend on good rail lines to get their crops to market. The Dakota Access Pipeline … well it ships oil.In the last dozen years, 21 oil train loading facilities were built in our state with the capacity to load 100 oil trains a day. Those facilities cost almost $1 billion to construct, BNSF alone spent more than $1 billion upgrading track in North Dakota to accommodate the new oil traffic and old unsafe tank cars were replaced with newer safer cars. Building the DAPL created hundreds of millions of dollars in stranded assets and lost opportunities for our state. Shutting down the DAPL will not cause the “sky to fall.” We have ample rail capacity to haul all of North Dakota’s crude oil safely by rail with newer and safer rail cars. It will put a bunch of railroad workers back to work and provide needed revenue to help maintain our rail infrastructure.

Radioactive oil waste study recommends uniform permitting; slurry wells a hot topic - Oil patch counties, state officials and others should work together toward a uniform permitting process for radioactive oilfield waste disposal facilities, concluded the author of a new study commissioned by the Western Dakota Energy Association. No landfills in North Dakota have received the necessary permits to accept radioactive material from the oil fields despite a change in state rules several years ago raising the acceptable radiation level. As a result, the waste is trucked to disposal sites in other states. Many proposals to establish facilities in North Dakota have received pushback from local landowners concerned about their safety and traffic, and county leaders often have numerous questions themselves.The waste is known as Technologically Enhanced Naturally Occurring Radioactive Material or TENORM. Low levels of radiation occur naturally in soil, water and rocks. When those materials are removed from the ground, like in oil and gas production, they become known as TENORM. It’s found in drill cuttings and wastewater, but it can be more concentrated in tank sludge, pipe scale and filter socks used to strain oilfield fluids, according to Bogar.“We are, as far as I was able to find, the only oil-producing state that does not have TENORM disposal within it,” he said.  Bogar envisions consistent zoning rules for the landfills across the Bakken or a single permitting process at the state level that relies heavily on county input, instead of separate permits needed from the county and the North Dakota Department of Environmental Quality.Environmental Quality has an extensive permitting process already, requiring that landfills receive both a solid waste permit and radioactive materials license to dispose of the material. Bogar suggests that a group of legislators, county commissioners, state officials and other stakeholders form to discuss how the permitting process ought to look.

$1.6 million settlement reached in 2016 Ventura oil spill - An oil pipeline company and associated contractor will pay a $1.6 million settlement regarding a 2016 crude oil spill in Ventura, the Ventura County District Attorney's Office said Tuesday.The owner of the pipeline, Crimson Pipeline L.P., agreed to pay $1.3 million in civil penalties, costs and natural resources damages as part of the settlement. The contractor working on the pipeline, identified as CD Lyon Construction Inc., has agreed to pay $300,000 in civil penalties and outstanding costs.The spill was reported on June 23, 2016, in the Hall Canyon area of Ventura. It was caused by a pipeline owned by Crimson after a faulty valve-replacement operation. When the pipeline began to operate after the replacement, it began to leak because new valve flanges had not been properly tightened by CD Lyon workers. In total, more than 44,000 gallons of crude oil were released into the Hall Canyon area, officials said. The spill was stopped by first responders and pipeline personnel before reaching the Pacific Ocean, but the spill area required months of cleanup. Some nearby residents left their homes because of the overwhelming odor of petroleum after the spill. Thomas Cullen, administrator of the California Department of Fish and Wildlife's Office of Spill Prevention and Response, noted the significance of the settlement in a statement.“With this settlement, Crimson and their contractor will pay a significant penalty, improve its oil spill preparedness and response operations, and compensate the public for natural resource damages,” Cullen said. “The public should know that when an oil spill happens in California, we will hold those responsible accountable and require a thorough and rapid cleanup and restoration."The disbursement of the settlement includes $900,000 in civil penalties from Crimson, with $600,000 being paid to the District Attorney's Office and the California Department of Fish and Wildlife. The penalties also include $387,700 for reimbursement of investigation and attorney costs; $20,000 to pay for damages to natural resources; and required compliance with the Lempert-Keene-Seastrand Oil Spill Prevention and Response Act, as well as improved oil spill prevention and response measures. CD Lyon's settlement will require reimbursing the District Attorney's Office with $115,000 in investigation and attorney costs, in addition to $185,000 to the California Department of Fish and Wildlife.

EIA forecasts U.S. petroleum demand will remain below 2019 levels for several more months -- Consumption of U.S. liquid fuels fell in March and April 2020 as a result of reduced travel related to COVID-19 and its mitigation measures. The U.S. Energy Information Administration’s (EIA) July Short-Term Energy Outlook (STEO) forecasts that U.S. consumption of total petroleum and other liquid fuels will continue increasing in the second half of 2020 as economic activity increases, but levels will remain lower than the 2019 average until August 2021.In April, consumption of liquid fuels in the United States (as measured by product supplied) reached its all-time monthly low since the early 1980s at an average of 14.7 million barrels per day (b/d). Weekly data show consumption of petroleum products has increased as states have relaxed restrictions. Volumetrically, almost half of the decrease in U.S. consumption of liquid fuels in 2020 has come from reduced motor gasoline use. EIA expects motor gasoline consumption will average 8.3 million b/d in 2020, down 1.0 million b/d (10%) from 2019. In the second half of 2020, a forecast increase in employment leads to an increase in gasoline consumption. EIA assumes employment levels will continue to grow in 2021, and gasoline consumption will increase to 9.1 million b/d, or to about 2% less than its 2019 average. EIA expects U.S. jet fuel consumption in 2020 to be 31% lower than its 2019 average, a much larger percentage change than gasoline (down 10%) and distillate (also down 10%). U.S. jet fuel consumption fell to an estimated 660,000 b/d in the second quarter of 2020, and EIA expects it to rise to 1.4 million b/d in the fourth quarter of this year. EIA expects jet fuel consumption to continue rising in 2021 and average 1.5 million b/d, or about 12% lower than its 2019 average.  During peak stay-at-home orders, distillate consumption was relatively less affected by COVID-19 mitigation efforts than gasoline or jet fuel consumption. Distillate consumption in the United States is driven by economic activity and is more likely affected by slowing economic growth than by travel restrictions. Distillate fuel is also used in activities that are not as directly affected by restrictions, such as by diesel engines in heavy construction equipment and as heating oil both for space heating in buildings and industrial heating.

INSIGHT-Bounceback in U.S. shale oil output is unlikely to last the summer – (Reuters) - A reopening of some majoreconomies locked down due to the coronavirus has lifted global oil prices and encouraged U.S. shale producers to return at least a third of the 2 million barrels per day (bpd) curtailed since April.  But that bump in output is unlikely to be sustained as shale wells lose up to half their initial output after the first year, and require constant drilling to maintain and increase production.With most new drilling halted and OPEC relaxing curbs that have underpinned the oil-price recovery, shale output will slide again in autumn, said oil executives and analysts.Shale output falls off faster than at conventional oil wells, a factor that will lead to output declining by September.Average U.S. daily oil output will fall below 2019's record 12.2 million barrels per day (bpd) for the next two to three years, analysts said.The decline means further economic damage from an industry that contributed nearly 1 percentage point to U.S. GDP early last decade. U.S. pipeline and oil export-terminal projects have been delayed or canceled as shale production forecasts have been cut."You shut down like this, reduce activity like this, and it is going to be felt for a while," David Dell'Osso, chief operating officer of shale producer Parsley Energy PE.N said in an interview.  Parsley Energy's plans mirror that of many shale rivals that have begun reopening existing wells but tightly restricting new activity. It had planned to operate 15 drilling rigs this year, but halted work in the spring as oil demand shrank on pandemic-related business closings.This month, the company restarted drilling with two rigs, not enough to maintain existing production levels. Diamondback Energy FANG.O, one of the top U.S. shale producers, reopened most of its curtailed wells this month. It expects to pump about 180,000 bpd this year, down from 188,000 bpd last year. The reason: its rig count fell from 20 at the end of March to just seven by mid July, and is expected to be six by the end of the month.Much of the shale production curtailments came from shale wells that were choked back but not shut-in completely, several shale company executives said.

Top Shale Boss Warns US Production Won't Revisit 2019 Levels "In My Lifetime" - America's energy dominance could be coming to an end as the country's shale industry is experiencing steep production declines. Rarely do we hear President Trump these days touting shale jobs and production output, mostly because the industry has entered a bust cycle. Matt Gallagher, CEO of Parsley Energy, a top 20 producer in Texas, spoke recently with the Financial Times and said crude output of 12 or 13 million barrels per day is over:  "I don't think I'll see 13m [barrels a day] again in my lifetime.   "It is really dejecting, because drilling our first well in 2009 we saw the wave of energy independence at our fingertips for the US, and it was very rewarding . . . to be a part of it," Gallagher,37, said.    The shale bust of 2020 is an ominous sign of America's energy dominance is over. Crude output will continue to wane this year and likely into next. The lack of shale profitability, mainly due to West Texas Intermediate (WTI) prices sub-$40 per barrel won't be enough for highly indebted shale companies to survive.  We've pointed out the shale industry could be on the verge of destruction due to the sharp decline in demand and plummeting energy prices brought on by coronavirus pandemic. So far, bankruptcies in the shale patch are accelerating to levels not seen since the first half of 2016. Another significant driver of lower production levels is a halving of rig counts due to collapsing price and demand; rigs dropped from 539 in mid-March to 258 last week."Tight oil production will decline by 50% by this time next year. As a result, US oil production will fall from to less than eight mmb/d by mid-2021," we noted via Arthur Berman via OilPrice.com.The combination of the Saudi-Russia oil price war and the virus pandemic has been nothing but disastrous for shale companies. These two factors forced Gallagher earlier this year to shut down wells and slash spending. He said the recent oil-price crash was "hands down" the worst ever. In April, WTI prices dove below the zero mark for the first time in history due to oversupplied conditions triggered by virus-related lockdowns.

Halliburton's $1.7B loss paves way for more bruising results - With a massive second-quarter loss, Halliburton, one of the world’s largest oil-field services companies, on Monday set the stage for a string of brutal energy company earnings reports. The company lost $1.7 billion in the second quarter compared with a $75 million profit during the second quarter of 2019. Revenue for the quarter declined 46 percent to $3.2 billion from $5.9 billion in the same period a year ago. The bulk of Halliburton’s loss was attributed to a $2.1 billion write down on the value of its assets as the price of oil collapsed during the quarter, including a dive to negative territory in April. Halliburton took a $1.1 billion write-down in the first quarter. The second quarter was the first full three-month period affected by shutdown orders across the country that wiped out demand, forced industrywide production cuts, and reduced drilling and well-completion activity. Halliburton’s rivals also post second-quarter results this week. Baker Hughes, which lost $10.2 billion in the first quarter, reports Wednesday, and Schlumberger, which lost $7.4 billion in the first quarter, is to report results Friday. Minus the write-downs and other charges, Halliburton reported $456 million of free cash flow compared with $12 million during the first quarter. “Halliburton’s second-quarter performance in a tough market shows we can execute quickly and aggressively to deliver solid financial results and free cash flow despite a severe drop in global activity,” Halliburton CEO Jeff Miller said. “Our results demonstrate a significant and sustainable reset to the power of our business to generate positive earnings and free cash flow.”

Frackers Are in Crisis, Endangering America’s Energy Renaissance - Twenty years ago brothers Dan and Farris Wilks started Frac Tech Services LLC in tiny Cisco, Texas. The company provided equipment for hydraulic fracturing, aka fracking, the breaking up of tight sedimentary rock by blasting water, sand, and assorted chemicals through horizontal bores at fantastically high pressure. Frac Tech grew into one of the most successful pressure pumpers as the U.S. experienced a boom first in shale gas, then in shale oil. The Wilks brothers became billionaires when they sold Frac Tech in 2011, just as shale oil was transforming the U.S. into one of the world’s biggest producers of crude.  The big oil explorers and producers are household names: Chevron and BP, Exxon Mobil and Royal Dutch Shell. But the U.S. oil renaissance has ridden heavily on the backs of little-known pressure pumpers that figured out how to extract oil from the stubborn shale of Colorado, New Mexico, North Dakota, Texas, and Wyoming. Today the Wilks brothers’ former company, now publicly traded and named FTS International Inc., is fighting to stay alive. Since early March, FTS has slashed executive pay, idled almost its entire fleet of pumping gear, and laid off two-thirds of its employees. It has more debt than cash. Its stock fell to about 30¢ a share before a 20-for-1 reverse stock split in May. Other pressure pumpers are suffering, too, with thousands of workers laid off.  With pressure to move away from fossil fuels rising, the bigger question may be whether the shale phenomenon itself can endure. Already this year, more than three dozen North American explorers, fracking service companies, and pipeline operators—including shale pioneer Chesapeake Energy Corp.—have sought bankruptcy protection. Production is down about 2 million barrels a day from a peak of almost 13 million early this year, and Morgan Stanley says prices must go higher than the current $40 a barrel to prevent further production declines in 2021. Shale’s woes are connected to pandemic shutdowns eviscerating demand and the Saudi-Russia price war that briefly pushed oil prices below zero. But the shale industry’s own shortcomings had gotten it into trouble before Covid-19, as a look at FTS’s winding journey through twin booms and busts makes clear. Now a crucial link in the U.S. oil supply chain is facing mass extinction.

Marathon Petroleum Takes Bailout Tax Breaks During Pandemic -- Fossil fuel companies have reaped millions of dollars in benefits from a stimulus package intended to help struggling Americans and the economy. Among these is Marathon Petroleum, the largest oil refiner in the country, which has a history of air pollution violations impacting low-income and Black and Brown communities. The CARES Act included several provisions to support businesses, one of which allowed companies to claim an immediate tax refund by deducting current operating losses from income taxes paid in the past five years. As a result of changes to allow the "carryback" of net operating losses, Marathon received $411 million in tax benefits, a sum even greater than their recent $334 million penalty for environmental violations. The Federal Reserve also included Marathon Petroleum in its recent purchase of energy bonds.Oil and gas companies, like Marathon, are not violating any rules by claiming this tax benefit, but there are significant downsides to using public resources to prop up dirty companies with a history of air pollution violations in the midst of a pandemic that targets the respiratory system. As part of the paycheck protection program, a separate program under the CARES Act, at least $3 billion in taxpayer dollars intended for small businesses have gone to over 5,600 U.S. fossil fuel companies and are being used to save an antiquated industry, rather than investing in a sustainable future that will benefit all Americans. Democratic lawmakers have warned that this oil bailout is not only taking the funds meant for smaller businesses, but is also forcing taxpayers to pay for the industry's past mistakes. Senators Brian Schatz and Sheldon Whitehouse wrote that the pandemic "was not the source of the oil and gas industry's dire financial condition," and that this bailout "poses both a credit risk and a more profound climate transition risk to taxpayers." Marathon Petroleum is just one example of an oil company that was already struggling prior to the COVID-19 outbreak, partly due to their expensive 2018 acquisition of rival refiner Andeavor. Oil companies have been pursuing suchmergers in an attempt to generate investor excitement and make up for the structural weaknesses of the oil sector. More specifically, upstream companies have spent billions more on drilling than they receive from selling the produced oil and gas, which creates a condition known as negative free cash flow. Investing in oil stock has had a similarly negative trajectory, as the average U.S. oil producer over the past three years has produced a total return of negative 17%.

Chevron Deal for Oil and Gas Fields May Set Off New Wave of Mergers - The New York Times— In the first big deal since oil prices crashed four months ago, Chevron agreed on Monday to buy Noble Energy for roughly $5 billion in what many experts consider the beginning of a sweeping consolidation in the U.S. oil industry.The coronavirus pandemic has caused a sharp decline in oil demand, putting intense pressure on oil companies with large debts. This includes Noble, which is based in Houston and has operations in Colorado, Texas, the eastern Mediterranean and West Africa.But it has also created an opportunity for oil giants to gobble up smaller fish and extend their acreage in places like the Permian Basin, which straddles Texas and New Mexico. Chevron, for one, already has a large presence in the basin and easy access to large pipeline networks, which should help the company put Noble’s assets to good use. “In a downturn like this, the strong get stronger and the weaker players try to survive as best they can, and some will be bought,”  . “There will be some bankruptcies and mergers and acquisitions like you saw today and I would expect that will continue and potentially pick up speed.” Like all oil companies, Noble has struggled to make a profit with oil prices at around $40 a barrel. The price has recovered somewhat in recent months, but the pandemic’s persistence and the recent surge of infections and hospitalizations in Texas and other states have led some executives to conclude that the price of oil may not climb much more anytime soon.  Even before the pandemic, the shale drilling boom helped produce so much oil that a growing number of wells were unprofitable. More than 20 North American producers have filed for bankruptcy this year, including Chesapeake Energy. The oil service giant Halliburton on Monday reported a $1.7 billion loss for the second quarter and said it had written down its assets by $2.1 billion.  This is the first major acquisition by Chevron since the company was outbid by Occidental Petroleum for Anadarko Petroleum last year. That $38 billion deal has left Occidental heavily in debt, while Chevron walked away with a $1 billion termination fee.  If the deal goes through, Chevron would pick up 92,000 acres of shale oil near or adjacent to its own fields. While that is far less than it would have picked up from Anadarko, Chevron is getting these fields at a far better price per acre. It will also acquire assets in the Eagle Ford field of South Texas, the DJ Basin in Colorado, and Equatorial Guinea. The deal will also give Chevron a presence in Israeli waters where Noble has discovered large natural gas deposits in recent years.

Trans Mountain Pipeline’s Lead Insurer Zurich Drops Coverage -A spokesperson for the Trans Mountain pipeline, which is planning a controversial expansion opposed by environmental groups and some Indigenous communities, said that Zurich would not renew its insurance coverage, Reuters reported Wednesday. Zurich's decision comes as environmental groups have put pressure on insurers to abandon the pipeline and other fossil fuel projects over their contribution to the climate crisis."This project is never getting built," advocacy group Stand.earth tweeted in response to the news. Stand.earth is one of 32 environmental groups behind a petition urging Trans Mountain's 26 insurers to cease covering the project by Aug. 31, according to Burnaby Now. Zurich is the third insurer to do so in the last two months, Stand.earth said.  The Trans Mountain pipeline expansion would nearly triple the oil flowing along its 715-mile route from Alberta's tar sands to the coast of British Columbia from 300,000 barrels a day to 890,000. Its opponents have faced legal setbacks in recent months. In February, the Canadian Federal Court of Appeals ruled that the government had adequately consulted with First Nations groups when approving the project. Then, in July, the Supreme Court of Canada opted not to hear an appeal of that decision from the Tsleil-Waututh Nation, the Squamish Nation and the Coldwater Indian Band, according to Burnaby Now.Indigenous groups oppose the pipeline expansion over concerns it will spill oil in their communities and erode their sovereignty."What is happening is about more than just a risky pipeline and tanker project. We see this as a major setback for reconciliation," Chief Leah George-Wilson of the Tsleil-Waututh Nation told CBC News following the Supreme Court's decision not to hear the appeal.  Pressuring the project's financial backers is another means of blocking it.Trans Mountain's current insurance contract runs out in August of this year, according to Reuters. For now, the company says it still has enough insurers to cover its regular operations and the expansion."There remains adequate capacity in the market to meet Trans Mountain's insurance needs and our renewal," a pipeline spokesperson told Reuters in an email.Zurich did not comment on its reasons for abandoning the project.Other insurers who covered the project this year include Munich Re, Lloyd's of London, Liberty Mutual and Chubb. Munich Re said it would review the contract based on its new policies on covering oil sands. The others declined to comment.  One insurer who dropped out in July, Talanx, based its decision on climate concerns.

Shell’s big bet on floating LNG may not pan out - It was the last of the large LNG projects that put Australia in the lead for global LNG exports. It was the biggest jewel in Shell’s LNG crown. But this jewel hasn’t produced any LNG since February, and its future is unclear. The Prelude floating liquefied natural gas project, with an annual capacity of 3.6 million tons, began shipping LNG last June. The first cargo shipped more than eight years after the final investment decision was made, and two years after the FLNG vessel arrived at the site, one Wood Mac analyst pointed out at the time. In February this year, production was stopped following a technical problem. Production at the world’s largest FLNG installation still hasn’t been restored, and it remains unclear when this will happen. Building it and putting it into operation cost between $12 and $17 billion, according to external estimates. Now, there are concerns that it may flop. The gas market situation is difficult enough. Just like in oil, there is a substantial glut in natural gas, and demand is lagging far behind. According to Rystad Energy, global natural gas output is set for a 2.6-percent decline this year because of the coronavirus pandemic. Next year, demand should begin to improve, driven by the low prices currently plaguing the sector. But that’s only if the pandemic goes away for good and without a fight, which at the moment is not happening. In this situation, it may not be that bad that Prelude is not operating at the moment. There is an oversupply of LNG, prices are low, and Shell said in a recent update that it will take a hit because its 2019 term sales contracts for LNG were tied to oil prices. That hit may be nothing compared to what Prelude may need to break even, at least according to analysts from Goldman Sachs quoted by Tim Treadgold in an article for Forbes. According to them, the commercial breakeven price for gas produced at Prelude is as much as $20 per thousand cubic feet. This compares with prices between $2 and $3 per thousand cubic feet in April in the United States. The difference is impressive, and it certainly would explain why, as Treadgold notes, Shell is in no hurry to restart operations at Prelude. Prelude is an impressive achievement, regardless of its problems. As the largest floating LNG facility in the world, it has a total capacity of 5.3 million tons of hydrocarbon liquids annually, including, besides the LNG, 1.3 million tons of gas condensate and 400,000 tons of liquefied petroleum gas. Floating LNG was to be a game-changer: boosting the efficiency of gas production by adding the processing to the place of extraction. But now it has to prove it is cost-competitive with other, more traditional approaches to LNG production.

Brazil boosts oil exports to Asia as global rivals make record cuts - (Reuters) - Brazil increased crude exports to Asia in the first half of the year, stealing a slice of a coveted developing market from global rivals who made record cuts to shipments to match the unprecedented fall in demand caused by the coronavirus pandemic. The rise reflects Brazil’s growing clout among global oil producers as its massive offshore projects come online. Brazil is expected to deliver one of the biggest increases to global supply in the next five years from nations outside of the Organization of the Petroleum Exporting Countries, according to the International Energy Agency. State oil firm Petrobras (PETR4.SA) offered Asian refiners competitive deals on relatively high-quality oil just as China and other countries in the region reopened their economies and as Western nations went into lockdowns to curb the spread of coronavirus, traders said. China also took advantage of the lowest oil prices in decades to fill up strategic storage.”If we had more oil available, China would buy it,” Petrobras Chief Executive Roberto Castello Branco told Reuters in a written response to questions. Castello Branco said there was no more to sell to further boost exports, because demand in Brazil has been recovering. China is now the destination for 70% of the country’s exports, Petrobras said in a statement to Reuters. Asia imported an average of 1.07 million barrels per day of oil from Brazil in the first half of the year, 30% year-on-year hike, according to Refinitiv Eikon’s trade flows data. A record 1.62 million bpd of Brazilian crude arrived in Asian ports in June, almost triple the volume in June 2019, according to the data. (Graphic showing Asia's oil imports from Latin America: here) Asian refiners were keen for the low-sulfur oil that Brazil sells, as they sought to comply with new maritime regulations to supply ships with cleaner fuel. The oil is from Brazil’s prolific offshore deposits known as pre-salt fields, which Petrobras and oil majors are spending hundreds of billions of dollars to develop.

PetroChina to sell major pipeline assets to PipeChina for $38 bln (Reuters) - PetroChina, China's state-owned oil and gas firm, said on Thursday it would sell its major oil and gas pipelines and storage facilities to the newly launched China Oil and Gas Pipeline Network (PipeChina) for 268.7 billion yuan ($38.36 billion). The sale excludes the assets of Kunlun Energy 0135.HK, in which PetroChina 601857.SS, 0857.HK has a 54.4% stake, it said in a statement. Separately, China Petroleum & Chemical Corp 600028.SS, 0386.HK (Sinopec) on Thursday announced plans to sell some of its oil and gas pipeline assets for 47.11 billion yuan to PipeChina, of which 22.89 billion yuan will be injected into PipeChina for an equity interest. Launched in December last year as part of a sector-wide reform, PipeChina had not been allocated any asset until this week, despite signing agreements with the national oil majors. The deals come as a part of Beijing's plans to boost investment in oil and gas production and provide a fair market access to small, non-state owned oil and gas producers and distributors. The deal will give PetroChina a stake of about 30% in PipeChina. The stake is worth 149.5 billion yuan, PetroChina said. The remainder will be paid in cash. Upon completion of the transactions, PipeChina will become an associate company of PetroChina, a listed arm of CNPC. PetroChina expects to book a gain of 45.82 billion yuan from the disposal of its assets, which it will use to pay dividend and for capital expenditure, it said in a statement.

Aging oil tanker in Yemen raises concern about catastrophe in the Red Sea - The FSO Safer, an oil tanker moored in the Red Sea near Yemen’s port city of Hodeida, holds more than 1 million barrels of oil. The ship was operated by Yemen’s government-run oil company until 2015, when Houthi rebels seized control of Hodeida and limited access to the FSO Safer. The ship’s condition is deteriorating, and volatile gases are building up inside. Experts say it could soon spring a leak or explode. An oil spill would worsen war-racked Yemen’s humanitarian disaster by poisoning fisheries and possibly releasing toxic gas. Drinking water is also a concern. Neighboring countries would have to shutter desalination plants if there was a spill. Yemen’s government has asked the United Nations to remove the ship’s oil. The Houthis say they would allow access to the ship only as part of a broader agreement, which appears unlikely to happen soon.

Iran Could Flood Oil Markets If Biden Becomes US President -  If presumptive Democratic candidate Joe Biden wins the presidential election in November, Iran could suddenly turn from a bullish driver for oil prices into a bearish factor if it resumes up to 2 million barrels per day (bpd) of oil exports.   Currently, there is a consensus among analysts and international agencies that the oil market is tightening and will continue to tighten, lifting oil prices through next year.    Oil demand is expected to rise next year by between 5 million bpd and 7 million bpd compared to this year’s lows, according to OPEC and the International Energy Agency (IEA)—in the absence of a mass return to lockdowns. The OPEC+ group is set to further ease its collective production cuts. In theory, the current expectations of supply and demand in 2021 are bullish for oil prices.  Yet, the market shouldn’t discount one political and geopolitical factor that could upend current oil price forecasts for next year. The U.S. presidential election in November could install a new administration in the White House – of a President Biden – that would be inclined to renegotiate the Iran nuclear deal and potentially ease the current sanctions on Tehran’s oil exports. The return of 1-2 million bpd of Iranian oil on the global market would cap oil price gains next year, a leading oil analyst said last week.“If you have Joe Biden as president he could basically take the US back into the [Iranian] Nuclear deal and you could see a million plus Iranian barrels hit the market. These are the kind of things I think will be very important into the trajectory of oil into 2021,” Helima Croft, head of commodity strategy at RBC Capital Markets, told Business Insider in an interview last week.  If Biden wins the November election, he could be inclined to revisit and renegotiate the Iran nuclear deal, potentially easing some sanctions in exchange for Tehran returning to compliance under some revised form of the Joint Comprehensive Plan of Action (JCPOA).  Iran’s oil will not return overnight to the market if Biden becomes president. But the prospect of renegotiation of the nuclear deal will likely keep oil prices depressed, making Iran a bearish factor for the market. This would be in contrast with the bullish factor that Iran has been for oil prices during the Trump Administration so far, with the renewed sanctions on its oil and the occasional flare-up of Iran-U.S. and Iran-Saudi tensions in the most important oil shipping lane in the world, the Strait of Hormuz.

Oil falls as worsening pandemic threatens recovery - Oil prices dipped on Monday, weighed down by the prospect that a rise in the pace of coronavirus infections could derail a recovery in fuel demand. Brent crude was down 10 cents, or 0.2%, at $43.04 a barrel by 0047 GMT, after dropping slightly last week. U.S. oil was off by 6 cents, or 0.2%, at $40.53 a barrel, after gaining 4 cents last week. "With global daily COVID-19 case counts still rising and the U.S. Sunbelt most populous states showing little success in bending and containing the (epidemic's) curve, concerns about the post-COVID recovery pace are limiting the upside for oil," said Stephen Innes, chief global markets strategist at Axicorp. More than 14 million people have been infected by the novel coronavirus globally and nearly 602,000 have died, according to a Reuters tally. While fuel demand has recovered from a 30% drop in April after countries around the world imposed strict lockdowns, usage is still below pre-pandemic levels. U.S. retail gasoline demand is falling again as infections rise. Japan's oil imports fell 14.7 percent in June from the same month a year earlier, official figures showed on Monday. The drop was not as pronounced as in May when they fell 25%, year on year. Still, exports from the world's third-largest economy slumped by a double-digit decline for the fourth month in a row as the coronavirus pandemic took a heavy toll on global demand. In the U.S., energy drillers cut the number of oil and natural gas rigs operating to a record for an 11th week in a row, data showed on Friday.

Oil Rebounds on Covid Vaccine Hopes, But Anchored at $40 --Oil prices recouped Monday’s early losses to trade a notch higher, after talk of safe human clinical trials for a Covid-19 vaccine licensed to AstraZeneca (NYSE:AZN). But fear of coronavirus cases raging anew in the United States kept the crude market anchored at just above $40 per barrel. The AZD1222, a vaccine developed by Oxford university and licensed to AstraZeneca, was put into large-scale, late-stage trials that included 1,077 healthy adults aged 18 to 55 years with no history of Covid-19. The vaccine’s marketers have already signed deals to produce and supply over 2 billion doses, once the shot proves successful. News on the AZD1222’s progress came as 31 of the 50 U.S. states saw more new cases of the virus this past week, with some cities overwhelmed by new hospitalizations or deaths. Los Angeles Mayor Eric Garcetti said he was on the "brink" of making another stay-at-home order, saying things "reopened too quickly" in the most economically-vibrant city in California, which had a record daily hospitalization of 2,216 people as of Sunday. In Florida, at least 49 hospitals had no more ICU space available while Arizona reported its highest number of Covid-19 deaths in one day -- 147. Crude prices, which fell more than 1% earlier on Monday during the Asian and European sessions, returned to positive territory by the lunch hour in New York. The rebound came as traders went with the progress on the vaccine development despite indications that it could take at least until the year-end or longer for a successful shot to reach the market. Meanwhile, immediate risk from the virus to both people and the economy is real and needs to be contained. New York-traded West Texas Intermediate, the benchmark for U.S. crude futures, was up 2 cents at $40.77 per barrel by 12:40 PM ET (1640 GMT). It dipped to a session low of $39.98 earlier. 

Oil jumps nearly 3% to highest level since March on vaccine hopes, EU deal - Oil rose on Tuesday, helped by positive news about vaccine trials and an EU stimulus deal, taking prices to levels last seen when an oil price war erupted in early March between Russia and Saudi Arabia. Benchmark Brent crude was up $1.37, or 3.17%, at $44.65, on track for its biggest daily rise since mid-June. West Texas Intermediate crude gained 2.82%, or $1.15, to settle at $41.96 per barrel, the highest level since March. Prices were buoyed by an agreement among European Union leaders on a 750 billion euro ($859 billion) fund to prop up their coronavirus-hit economies, lifting prospects for fuel demand. In other financial markets, world shares and the euro also hit their highest in several months on Tuesday. The dollar, in which most oil contracts are priced, fell to its lowest since March against a basket of currencies. The EU deal allows the European Commission to raise billions of euros on capital markets on behalf of all 27 states, an unprecedented act of solidarity in almost seven decades of European integration. Oil prices were also supported by promising coronavirus vaccine data released on Monday, raising confidence that a vaccine may be created even if a global rollout will take time. In China, some cinemas reopened on Monday after a six-month closure, another sign of recovery in the world's second-largest economy. Countries from the United States to India are reporting record numbers of coronavirus infections, while others such as Spain and Australia are battling new outbreaks. In the first big energy deal since the coronavirus crushed fuel demand, Chevron Corp said it would buy Noble Energy Inc for about $5 billion in stock. U.S. crude oil stockpiles were seen falling last week, while inventories of refined products are also likely to have dropped, a preliminary Reuters poll showed on Monday.

WTI Holds Losses As US Distillates Stocks Reach 38-Year Highs  -Oil prices are lower overnight after a surprisingly large crude inventory build reported by API. The energy complex was not helped by comments by President Trump that the COVID-19 outbreak in the U.S. will probably worsen before improving.“Everything seemed to rise in the commodity world yesterday as part of the reflation trade,” said Giovanni Staunovo, an analyst at UBS Group AG in Zurich.“But today oil fundamentals are taking control again, and a likely crude inventory build in the U.S. doesn’t fit in the story of an undersupplied market.”And so all eyes are on the official data for signs of this reversal in recovery...API

• Crude +7.54mm (-2.1mm exp)
• Cushing +716k (+800k exp)
• Gasoline -2.019mm (-1.4mm exp)
• Distillates -1.357mm (-600k exp)

After API reported a 7.54mm build in US crude stocks, oil bulls are focused intently on the official data expecting a 2.1mm draw still. However, while not as large as the API build, DOE reports a 4.892mm build in crude, another build at Cushing, a surprise build in distillates, and a slowing drawin gasoline...  Additionally, as Bloomberg's Sheela Tobben reports, U.S. crude oil exports may be under downward pressure as China is now facing new troubles that might curb its interest for American. The Asian nation was struggling with bulging inventories and port jams after a recent crude binge, while battling a new wave of the Covid-19 pandemic. This month, heavy rains have resulted in severe floods, threatening run cuts at the country’s top refiner. Total US distillates inventory has soared to its highest since 1982...

Oil declines slightly after surprise build in U.S. inventories - Oil prices moved lower on Wednesday as U.S. government data showed a surprise rise in U.S. crude inventories, and as tensions escalated between the United States and China. Brent crude fell 3 cents to settle at $44.29 per barrel. West Texas Intermediate crude settled 2 cents lower at $41.90 per barrel. U.S. crude and distillate inventories rose unexpectedly and fuel demand slipped in the most recent week, the Energy Information Administration said on Wednesday, as the sharp outbreak in coronavirus cases has started to hit U.S. consumption. Crude inventories rose by 4.9 million barrels in the week to July 17 to 536.6 million barrels, compared with expectations in a Reuters poll for a 2.1 million-barrel drop. Production rose to 11.1 million bpd, up 100,000 bpd. "Overall this would suggest that the demand recovery we've seen from the bottom seems to be stalling," said Phil Flynn, senior analyst at Price Futures group in Chicago. U.S. President Donald Trump said on Tuesday that the outbreak would probably worsen before it got better, a shift from his previously robust emphasis on reopening the economy. Bjornar Tonhaugen, Rystad Energy's head of oil markets, said Trump's comments might be welcomed by investors because they are among the most measured by him or his administration so far. "This could be a positive for oil demand prospects. Instead of an uncontrolled, disruptive second wave of lockdowns, maybe chances have now increased that the United States will eventually get the spread under control," Tonhaugen said. However, a fresh dispute between Washington and Beijing put pressure on prices after the United States told the Chinese consulate in Houston to shut and a source said China was considering closing the U.S. consulate in Wuhan. Adding to pressure were signs that Iraq, the second-largest producer in the Organization of the Petroleum Exporting Countries, was still not meeting its target under an OPEC-led pact to cut supplies.

Oil settles lower as worries remain over rising U.S. inventories and coronavirus cases -  Oil futures settled lower Thursday, extending a decline seen the previous session after data showed an unexpected rise in U.S. crude inventories, as alarming growth in the number of U.S. cases of coronavirus point to the potential for further business shutdowns, dulling the prospects for energy demand. “Virtually all demand categories” showed a week-on-week decline in the report from the Energy Information Administration Wednesday, said Robbie Fraser, senior commodity analyst at Schneider Electric. The report showed a weekly fall of 98,000 barrels per day in implied demand for finished motor gasoline to 8.55 million barrels a day. Implied demand for distillate fuel oil fell 470,000 barrels per day to 3.22 million barrels a day. “That fall will tie into broader concerns around a rise in COVID cases in the U.S. and the potential economic headwinds that could bring moving forward,” Fraser said in a daily note. West Texas Intermediate crude for September delivery on the New York Mercantile Exchange fell 83 cents, or 2%, to settle at $41.07 a barrel, while September Brent crude BRN.1, +0.18% lost 98 cents, or 2.2%, at $43.31 a barrel on ICE Futures Europe. Crude prices finished slightly lower Wednesday, pulling back a day after settling at their highest since March, pressured by an unexpected weekly climb in U.S. crude stockpiles. The EIA reported Wednesday that U.S. crude inventories rose by 4.9 million barrels for the week ended July 17. That compared with an average forecast by analysts polled by S&P Global Platts for a decline of 1.9 million barrels.Natural-gas futures, meanwhile, rallied as traders eyed storm activity in the Gulf of Mexico. “Aa tropical depression is building off the coast of Texas and may develop into Tropical Storm Hanna before reaching land” said Christin Redmond, commodity analyst at Schneider Electric, in a note. “The storm is likely to hit an area with offshore oil and gas production assets, which may temporarily reduce gas production in the near-term.”

Oil falls on coronavirus demand concerns, weak U.S. jobs numbers (Reuters) – Oil prices fell 2% on Thursday as investors worried the U.S. Congress may not agree on a stimulus package and as jobless numbers rose, while analysts prepared to cut energy demand forecasts as the number of coronavirus cases surges higher. That price decline came despite the benefit of a drop in the dollar to a near 22-month low. Brent LCOc1 futures fell 98 cents, or 2.2%, to settle at $43.31 a barrel, while U.S. West Texas Intermediate (WTI) crude CLc1 fell 83 cents, or 2.0%, to settle at $41.07. The U.S. dollar was trading at its lowest against a basket of currencies .DXY since September 2018. A weaker dollar usually spurs buying of dollar-priced commodities, like oil, because they become cheaper for holders of other currencies. But weak U.S. jobless numbers and a surge in coronavirus cases weighed on oil prices and stock markets. The number of Americans filing for unemployment benefits unexpectedly rose last week for the first time in nearly four months. U.S. Senate Republican leaders and White House officials tried to hammer out a proposal for a fresh round of coronavirus aid on Thursday. Democratic leaders, meanwhile, rejected the idea of passing a piecemeal bill. U.S. coronavirus cases approached 4 million on Thursday, with more than 2,600 new cases every hour on average – the highest rate in the world, a Reuters tally showed. “The trend for COVID-19 cases will likely result in downwards revisions in demand growth forecast from key market observers soon, including ourselves and the agencies, especially for the fourth quarter,” Adding to the market uncertainty, U.S.-China relations deteriorated as Washington gave Beijing 72 hours to close its consulate in Houston after spying allegations. The Chinese foreign ministry said the U.S. move had “severely harmed” relations and that China would be forced to respond.

Oil up on strong economic data, U.S.-China tensions cap gains - (Reuters) - Oil prices rose on Friday, lifted by some supportive economic data, but tensions between the United States and China limited gains. Brent crude futures LCOc1 rose 3 cents to settle at $43.34 a barrel. U.S. West Texas Intermediate (WTI) crude CLc1 futures rose 22 cents to settle at $41.29 a barrel. For the week, Brent rose 0.5%, while U.S. crude rose 1.7%. Ahead of the weekend, market participants had their eye on Tropical Storm Hanna, forecast to cross to Baffin Bay, 46 miles (74 km) south of Corpus Christi, Texas, on Saturday afternoon or evening. So far, energy companies said there have been no evacuations of workers or shutdowns of production from offshore platforms in the northern Gulf of Mexico. Lifting market sentiment, Euro zone business activity grew in July for the first time since the coronavirus pandemic hit, according to IHS Markit’s flash Composite Purchasing Managers’ Index (PMI). The index is seen as a good indicator of the bloc’s economic health. “The economic data in Europe was much better than anticipated, which would suggest that demand destruction in recent months because of COVID-19 may not have been as bad as people thought,” said Phil Flynn, senior analyst at Price Futures group in Chicago. Meanwhile, U.S. business activity increased to a six-month high in July. U.S. companies, however, reported a drop in new orders as new COVID-19 cases spiked. The resurgent pandemic has darkened the U.S. economic outlook. Some states have reinstated restrictions, which should reduce fuel consumption. The U.S. oil and gas rig count, a indicator of future output, fell by two to an all-time low of 251 in the week to July 24, according to data from energy services firm Baker Hughes Co (BKR.N). However, energy firms added one oil rig in the first weekly increase since March. Meanwhile, money managers raised their net long U.S. crude futures and options positions in the week to July 21 by 5,430 contracts to 375,193, the U.S. Commodity Futures Trading Commission (CFTC) said on Friday..

Oil posts third positive week in four on demand recovery hopes - Oil prices moved slightly higher on Friday supported by economic data from Europe, but gains were limited as tensions between the United States and China flared. Brent crude futures settled 3 cents higher at $43.34 per barrel. West Texas Intermediate crude futures gained 22 cents to settle at $41.29 a barrel. China ordered the United States to close its consulate in the city of Chengdu on Friday, responding to a U.S. demand this week that China close its Houston consulate. The renewed tensions between the world's top two oil consumers stoked worries about oil demand, which already faces headwinds including rising coronavirus cases in the United States. The resurgent pandemic has darkened the U.S. economic outlook. Some states have reinstated restrictions to curb the latest outbreak, which is expected to decrease fuel consumption. The number of Americans filing for unemployment benefits hit 1.416 million last week, unexpectedly rising for the first time in nearly four months. Oil prices could see a near-term correction if a recovery in fuel demand slows further, especially in the United States, Barclays Commodities Research said. Still, the bank lowered its oil market surplus forecast for 2020 to an average of 2.5 million barrels per day (bpd) from 3.5 million bpd previously. In the United States, the oil and gas rig count, an early indicator of future output, fell by two to an all-time low of 251 in the week to July 24, according to data on Friday from energy services firm Baker Hughes Co. However, energy firms added one oil rig in the first weekly increase since March. Softening Friday's market losses, Euro zone business activity grew in July for the first time since the coronavirus pandemic hit, according to IHS Markit's flash Composite Purchasing Managers' Index (PMI). The index is seen as a good indicator of the bloc's economic health. "The economic data in Europe was much better than anticipated, which would suggest that demand destruction in recent months because of COVID-19 may not have been as bad as people thought," 

Saudis Stuck Home for Summer Burn More Oil for Air Conditioners -- As the Middle East enters the hottest days of summer, Saudi Arabia is set to burn potentially record amounts of crude oil to run its power plants and keep its citizens comfortably air-conditioned. Electricity consumption always soars around July and August, when temperatures in the kingdom can rise above 122 degrees Fahrenheit (50 degrees celsius). That compels the government to use crude or fuel oil in addition to the much cleaner natural gas that normally fires the plants. But this year the urge to drain oil is even stronger because of higher demand, with the coronavirus pandemic forcing many Saudis to cancel their summer holidays abroad. Another difference is that record cuts to Saudi Arabia’s oil production since April -- part of a push by OPEC members to prop up prices in the face of the virus -- have reduced its supplies of gas, most of which come from the same wells as crude. The extra oil going toward power may limit the price impact of OPEC’s plan to taper output restrictions from next month. The kingdom pumped 7.5 million barrels a day in June, the fewest since 2002, according to data compiled by Bloomberg. Of those, it exported 5.7 million barrels daily, while keeping most of the rest for domestic refineries. “They can simply import more gas or burn more crude in power generation,” said Carole Nakhle, chief executive officer of London-based consulting firm Crystol Energy. “The second option is more likely and easier since the region has been doing this for years and decades and there is plenty of oil around today.” Each August, Saudi Arabia uses 726,000 barrels of crude daily for power generation, according to average numbers over the past decade from the Riyadh-based Joint Organisations Data Initiative, which collates statistics among energy producers. That’s more than double the amount for the cooler months of January and February. The record came in July 2014, when the Saudis burned 899,000 barrels a day. Saudi Arabia has already unwound some crude-production curbs. At the end of June, it ended voluntary cuts of 1 million barrels a day below its OPEC quota, saying it would need most of the additional oil for domestic use. “Our consumption is going to increase,” Saudi Energy Minister Prince Abdulaziz bin Salman said in early June. “A good chunk of what we will produce in July will go to domestic consumption -- crude burning or fuel oil, not refining.” Nearing 1 million barrels a day for power generation would be a setback for Saudi Arabia’s plans to reduce its own use of the dirtiest fossil fuels. Before the virus stuck, the government looked on track to achieve that, especially after increasing capacity at local gas-processing plants,

Egypt's Parliament Approves Ground Troop Deployment To Back Haftar In Libya  --Libya's proxy war just grew hotter, with outside powers supporting opposite sides of the conflict finding themselves more directly intervening on Libyan soil.Though Turkey, which supports Tripoli's UN-backed Government of National Accord (GNA) has sent troops and weapons since last year to help fend off Haftar's (now failed) advance on the capital, Egypt just made a huge and unprecedented move.On Monday Egypt's parliament voted to approve sending its armed forces to fight “criminal militias” and “foreign terrorist groups” on a “Western front”. Previously Egypt has only flown sorties over neighboring Libya, however, this would mark the first ever direct ground intervention.Though the parliamentary vote didn't name Libya directly, it's widely known that "Western front" is a clear reference to the growing chaos along Egypt's border with Libya. Cairo continues to see Haftar as a necessary 'stabilizer' for the country which has remained in a state of chaos and bloodshet since the US-NATO toppling of Gaddafi in 2011.The parliament unanimously voted for "the deployment of members of the Egyptian armed forces on combat missions outside Egypt's borders to defend Egyptian national security... against criminal armed militias and foreign terrorist elements," according to a statement.Reuters underscores that the vote is a big deal and somewhat unprecedented:Egyptian state TV later ran banners on the screen saying: “Egypt and Libya, one people, one fate.”The last time Egypt sent ground troops abroad  for combat was in 1991 in Kuwait as part of a U.S.-led coalition to drive out Iraqi troops.