oil prices rose for the 7th time in the past nine weeks on tight crude supplies and signs that fuel demand was holding up, despite the Covid surge.... after falling 3.7% to $71.81 a barrel last week as rising Covid cases and the prospect of added supplies from OPEC weighed on the market, the contract price of US light sweet crude for August delivery opened lower on Monday after OPEC and its allies agreed to end their oil production cuts and increase supplies by September 2022, and quickly tumbled to finish the day's trading down by $5.39, or by more than 7%, at $66.42 a barrel, the biggest single day drop since last September, as the spread of the delta Covid variant among vaccinated populations threatened global demand just as OPEC was increasing supplies...however, oil prices bounced back on Tuesday, reversing some of the panic selling seen on Monday, as trading in the August WTI oil contract expired $1.00 higher to end at $67.42 a barrel, while the more actively traded US oil contract for September delivery, which had fallen $5.21 to 66.35 a barrel on Monday, recovered 85 cents to settle at $67.20 a barrel....however, oil prices tumbled that evening after the API reported a surprise increase in US crude inventories, and hence opened 75 cents lower on Wednesday, but rallied from that point despite the EIA's confirmation of an unexpectedly large crude supply build, to finish $3.10 higher at $70.30 a barrel, as inventories at the Cushing, Oklahoma storage hub, the delivery point for the US oil contract, fell to their lowest level in 18 months...oil prices then rose for a third straight session on Thursday on expectations of tighter supplies through 2021 as economies recovered from the coronavirus crisis, as the September crude contract price rose $1.61 to $71.91 a barrel, thus erasing Monday's rout and turning higher for the week...oil prices edged up again on Friday on forecasts for tight supplies throughout the year and settled 16 cents higher at $72.07 a barrel, on signs that global fuel demand and road traffic was holding up, despite concerns that the virus could stall the recovery. leaving the front-month U.S. oil benchmark contract up by 0.7% for the week, same as the gain seen on the September contract, which had become the front month on Wednesday...
meanwhile, natural gas prices rose every day this week in surging to a new 31 month high, as yet another continental heat wave loomed...after ending last week unchanged at $3.674 per mmBTU as strong export demand offset cooler weather and a bearish storage report, the contract price of natural gas for August delivery opened the week higher on Monday and surged 10.5 cents, or 2.9% to a 30 month high at $3.779 per mmBTU on soaring global natural gas prices and forecasts for more air conditioning demand next week than had been previously expected...gas prices rose another 9.7 cents on Tuesday, bolstered by forecasts for hotter weather and concerns over winter supplies, and then moved up 8.3 cents more on Wednesday to a 31 month high of $3.959 per mmBTU on forecasts that the hotter weather and higher air conditioning demand would continue through early August...prices then topped $4 for the first time since early December 2018 on Thursday, as traders looked past a bearish storage print from the EIA and focused instead on persistently strong demand and relatively light production, with the August contract gaining 4.4 cents on the day and settling at $4.003 per mmBTU...forecasts for an even hotter coast to coast heat dome in the coming week pushed natural gas prices another 5.7 cents higher to yet another 31 month high of $4.060 per mmBTU on Friday, putting the front-month price up almost 11% for the week, its biggest weekly percentage gain since February...
the natural gas storage report from the EIA for the week ending July 16th indicated that the amount of natural gas held in underground storage in the US rose by 49 billion cubic feet to 2,678 billion cubic feet by the end of the week, which still left our gas supplies 532 billion cubic feet, or 16.6% below the 3,210 billion cubic feet that were in storage on July 16th of last year, and 176 billion cubic feet, or 6.2% below the five-year average of 2,854 billion cubic feet of natural gas that have been in storage as of the 16th of July in recent years...the 49 billion cubic feet increase in US natural gas in storage this week was more than the median forecast for a 43 billion cubic foot addition from a S&P Global Platts survey of analysts, and well above the average addition of 36 billion cubic feet of natural gas that have typically been injected into natural gas storage during the same week over the past 5 years, and also above the 38 billion cubic feet that were added to natural gas storage during the corresponding week of 2020…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending July 16th showed that after a big increase in our oil imports and a near record decrease in our oil exports, we had surplus oil to add to our stored commercial crude supplies for the first time in nine weeks, and for the 12th time in the past thirty-six weeks….our imports of crude oil rose by an average of 875,000 barrels per day to an average of 7,097,000 barrels per day, after rising by an average of 347,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 1,562,000 barrels per day to an average of 2,463,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 4,634,000 barrels of per day during the week ending July 16th, 2,437,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was reportedly unchanged at 11,400,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to total an average of 16,034,000 barrels per day during this reporting week…
meanwhile, US oil refineries reported they were processing 16,007,000 barrels of crude per day during the week ending July 16th, 87,000 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 301,000 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 274,000 barrels per day less than what was added to storage plus our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a (+274,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or errors of that magnitude in this week’s oil supply & demand figures that we have just transcribed….since last week’s EIA fudge factor was at (+1,369,000) barrels per day, that means there was a 1,095,000 barrel per day balance sheet difference in the crude oil fudge figure from a week ago, thus rendering the week over week supply and demand changes indicated by this report useless…. however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as they’re published, just as they’re watched & believed to be reasonably accurate by most everyone in the industry….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,400,000 barrels per day last week, which was 2.9% more than the 6,218,000 barrel per day average that we were importing over the same four-week period last year… the 301,000 barrel per day net increase in our crude inventories was all added to our commercially available stocks of crude oil, while the quantity of oil stored in our Strategic Petroleum Reserve remained unchanged…..this week’s crude oil production was reported to be unchanged at 11,400,000 barrels per day because the EIA"s rounded estimate of the output from wells in the lower 48 states was unchanged at 11,000,000 barrels per day, while a 56,000 barrel per day decrease in Alaska’s oil production to 378,000 barrels per day had no impact on the rounded national total….US crude oil production had hit a pre-pandemic record high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 13.0% below that of our production peak, but 35.3% above the interim low of 8,428,000 barrels per day that US oil production had fallen to during the last week of June of 2016…
meanwhile, US oil refineries were operating at 91.4% of their capacity while using those 16,007,000 barrels of crude per day during the week ending July 16th, down from 91.8% of capacity the prior week, and somewhat below normal for summertime operations…while the 16,007,000 barrels per day of oil that were refined this week were 11.9% higher than the 14,309,000 barrels of crude that were being processed daily during the pandemic impacted week ending July 17th of last year, they were still 6.0% below 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 what was a seasonally low 93.1% of capacity…
with this week’s decrease in the amount of oil being refined, the gasoline output from our refineries was also lower, decreasing by 728,000 barrels per day to 9,130,000 barrels per day during the week ending July 16th, after our gasoline output had decreased by 696,000 barrels per day over the prior week…while this week’s gasoline production was still fractionally higher than the 9,079,000 barrels of gasoline that were being produced daily over the same week of last year, it was j9.5% lower than the gasoline production of 10,089,000 barrels per day during the week ending July 19th, 2019….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 24,000 barrels per day to 4,902,000 barrels per day, after our distillates output had decreased by 41,000 barrels per day over the prior week…while this week’s distillates output was 2.9% more than the 4,763,000 barrels of distillates that were being produced daily during the week ending July 17th, 2020, it was 6.1% below the 5,219,000 barrels of distillates that were being produced daily 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 fifth time in sixteen weeks, and for the 15th time in thirty-six weeks, falling by 121,000 barrels to 236,414,000 barrels during the week ending July 16th, after our gasoline inventories had increased by 1,038,000 barrels over the prior week...our gasoline supplies decreased this week even though our imports of gasoline rose by 330,000 barrels per day to a ten year high of 1,374,000 barrels per day while our exports of gasoline rose by 119,000 barrels per day to 866,000 barrels per day, and as the amount of gasoline supplied to US users increased by 12,000 barrels per day to 9,295,000 barrels per day…after this week’s inventory decrease, our gasoline supplies were 4.2% lower than last July 17th's gasoline inventories of 246,733,000 barrels, and near the five year average of our gasoline supplies for this time of the year…
meanwhile, with the decrease in our distillates production, our supplies of distillate fuels decreased for the tenth time in fifteen weeks and for the 16th time in 31 weeks, falling by 1,349,000 barrels to 141,000,000 barrels during the week ending July 16th, after our distillates supplies had increased by 3,657,000 barrels during the prior week….our distillates supplies fell this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 761,000 barrels per day to 3,925,000 barrels per day, while our exports of distillates fell by 59,000 barrels per day to 1,257,000 barrels per day, and while our imports of distillates rose by 10,000 barrels per day to 66,000 barrels per day… after ten inventory decreases over the past fifteen weeks, our distillate supplies at the end of the week were 20.8% below the 177,883,000 barrels of distillates that we had in storage on July 17th, 2020, and about 4% below the five year average of distillates stocks for this time of the year…
finally, with the drop in our oil exports and the increase in our oil imports, our commercial supplies of crude oil in storage rose for the fourth time in the past seventeen weeks and for the 24th time in the past year, increasing by 2,107,000 barrels over the week, from 437,580,000 barrels on July 9th to 439,687,000 barrels on July 16th, after our commercial crude supplies had decreased by 7,896,000 barrels the prior week….with this week’s decrease, our commercial crude oil inventories rose to about 7% below the most recent five-year average of crude oil supplies for this time of year, and were about 29% above the average of our crude oil stocks as of the the 3rd weekend of July over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories had jumped to record highs during the Covid lockdowns of last spring and remained elevated thereafter, our commercial crude oil supplies as of this July 16th were 18.1% less than the 536,580,000 barrels of oil we had in commercial storage on July 17th of 2020, and 1.2% less than the 445,041,000 barrels of oil that we had in storage on July 19th of 2019, but are still 8.6% more than the 404,937,000 barrels of oil we had in commercial storage on July 20th of 2018…
This Week's Rig Count
The number of drilling rigs active in the US increased for the 38th time out of the past 44 weeks during the week ending July 23rd, but was still down by 38.1% from the pre-pandemic rig count….Baker Hughes reported that the total count of rotary rigs running in the US increased by seven to 491 rigs this past week, which was also up by 240 rigs from the pandemic hit 251 rigs that were in use as of the July 24th report of 2020, but was still 1,438 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, a week before OPEC began to flood the global oil market in an attempt to put US shale out of business….
The number of rigs drilling for oil was up by 7 to 387 oil rigs this week, after rising by 2 oil rigs the prior week, and it’s also 206 more oil rigs than were running a year ago, while it’s still just 24.1% of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations was unchanged at 104 natural gas rigs, which was still up by 36 natural gas rigs from the 68 natural gas rigs that were drilling during the same week a year ago, but still just 6.5% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….
The Gulf of Mexico rig count was unchanged at 17 rigs this week, with 16 of those rigs drilling for oil in Louisiana’s offshore waters and one drilling for oil offshore from Texas….that was five more rigs than the 12 rigs that were drilling in the Gulf a year ago, when 10 Gulf rigs were drilling for oil offshore from Louisiana and two were deployed for oil in Texas waters….since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week’s national offshore rig totals are equal to the Gulf rig count… in addition to those rigs offshore, we continue to have a rig drilling through an inland body of water in Terrebonne Parish of southern Louisiana, whereas there were no such “inland waters” rigs running a year ago…
The count of active horizontal drilling rigs was up by 5 to 439 horizontal rigs this week, which was also up by 224 rigs from the 216 horizontal rigs that were in use in the US on July 24th of last year, but less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….at the same time, the directional rig count was up by one to 33 directional rigs this week, and those were up by 11 from the 22 directional rigs that were operating during the same week a year ago….in addition, the vertical rig count was up by 1 to 19 vertical rigs this week, and those were also up by 5 from the 14 vertical rigs that were in use on July 24th of 2020….
The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of July 23rd, the second column shows the change in the number of working rigs between last week’s count (July 16th) and this week’s (July 23rd) count, the third column shows last week’s July 16th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 24th of July, 2020..
checking first for the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes, we find that one oil rig was added in Texas Oil District 8, which is the core Permian Delaware in the westernmost part of the state, and that two oil rigs were added in Texas Oil District 8A, which encompasses the northern counties of the Permian Midland, and that another oil rig was added in Texas Oil District 7C, which encompasses the southern counties of the Permian Midland, thus accounting for this week's Permian basin increase...however, the Permian basin gas drilling rig that had been started last week was either pulled out or converted to oil this week, so hence there was a net addition of 5 oil rigs in the basin...elsewhere in Texas, two rigs were added in Texas Oil District 10, at least one of which was an oil rig in the Granite Wash basin, while the rig counts in other Texas districts remained unchanged... meanwhile, in Louisiana, two rigs were pulled out from the northern part of the state, one of which was a natural gas rig in the Haynesville shale...elsewhere, the Ardmore Woodford rig addition was in Oklahoma, while the two Utah rig additions were in the Unitah basin, one of which was targetting natural gas...that gas rig, and another addition, are aggregated by Baker Hughes as "other natural gas rigs", offseting the natural gas losses in the Permain and Haynesville that we've previously noted...
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Where is the watchdog over Ohio's oil and gas industry? - Well. Well. Well. If it ain’t one thing, it’s another, right? Did you know Ohio’s taxpayer dollars are being used to buy up the oil and gas industry’s drilling and fracking radioactive waste? To use as highway “de-icer”? And for dirt road “dust control”? And that a new “twist” might be coming from Columbus? At least this time our state representatives and senators aren’t being bought and sold by Ohio’s nuclear and coal industry campaign contributors. Nope. This time it’s Ohio’s oil and gas industry campaign contributors. Well-heeled oil and gas lobbyists have “made it attractive” for certain state representatives and senators to create, and then try to push, two current bills [HB 282 and SB 171] through the legislative process. These bills attempt to “re-classify” the drilling and fracking industry’s radioactive waste brine “de-icer” as a “commodity.” Why? Because, if they can re-classify it as a “commodity,” state health agencies and the Ohio Department of Natural Resources will no longer be able to measure or regulate the amount of radioactivity in the brine. Why? Because, if it’s an “unregulated commodity,” it can more easily, and more profitably, be sold right off the shelf in retail stores. Where it is temptingly and misleadingly labeled “ancient sea water,” or “nature’s source agua salina.” For people to use to “de-ice” their patios, sidewalks and driveways. Where it will all eventually be washed away to “someplace” (spread over the soil, onto farmland, into streams, into water wells and underground aquifers; or maybe dried, airborne and inhaled). Not nice. It’s carcinogenic, people. Don’t buy it, people. Don’t allow it, people. Email your state reps. Fast.
Liens remain in place as mediation fails in Erie County pipeline case - A federal lawsuit is keeping uncertainty in place for hundreds of property owners who sold rights-of-way for a natural gas pipeline in western Erie County. The suit over the 28.3-mile Risberg Pipeline has failed to settle in U.S. District Court in Erie, and both sides in the case are asking for more time to gather evidence as they prepare for trial.As the case advances slowly in court, a far-reaching aspect of the dispute is staying intact: mechanic's liens of $18,946,185 each are still attached to pipeline work on hundreds of swaths of land near Albion in Erie County.The liens are an outgrowth of the federal suit that the builder of the pipeline, the Wood Group USA Inc., of Houston, Texas, filed in August against the Erie-based RH Energytrans, which owns the $86 million project. The pipeline, which opened in 2019, is made up of 15 miles of 12-inch steel pipe in Elk Creek Township in Erie County and about 13 miles of pipe in Ashtabula County, Ohio, where the project ends in North Kinsgsville.The Wood Group claims that RH Energytrans owes it more than $35 million, with $18,946,185 of that due on the work the Wood Group said it completed in Erie County. RH Energytrans is claiming it has paid the Wood Group everything due under the terms of the contract. The case is in federal court because the Wood Group and RH Energytrans are located in different states.In a companion action to the federal suit, the Wood Group in December filed the mechanic's liens at the Erie County Courthouse in an attempt to recoup the money that it claims RH Energytrans owes it. The Wood Group in December also filed similar mechanic's liens against hundreds of other property owners in Ashtabula County.
Wood Continues to Threaten OH/PA Landowners with Liens re Risberg Pipe - In March 2019 MDN brought you the news that Wood Group had been awarded a $34 million contract to build 28 miles of the 60-mile Risberg Pipeline from Crawford County, PA to Ashtabula County, OH (see Wood Wins $34M Contract to Build PA to OH Risberg Pipeline). The portion Wood built was new “greenfield” pipeline. The rest of the pipeline (32 miles) already existed and was repurposed. There is an ongoing controversy between Wood and RH energytrans (the owner) concerning payment for services rendered. Wood says they’re owed more and is using the “nuclear option” of going after the landowners whose property the pipeline traverses as a way to pressure RH into paying more.We told you back in January that Wood had filed “mechanic’s liens” against landowners in both Erie County, PA and Ashtabula County, OH (see Liens Served on PA/OH Landowner Property re Risberg Pipeline). Landowners get served papers by local sheriff’s deputies and don’t understand what’s happening. It’s a very scary (very sleazy) tactic to force a settlement.Wood filed a lawsuit in federal court in August 2020 claiming RH is refusing to pay Wood for extra work it did (see Contractor Sues Risberg PA-to-OH Pipeline for Nonpayment $35M). There is a dispute over a number of change orders submitted by Wood. We get it–sometimes there are disputes over contracts. However, Wood’s dispute with RH is no reason to send scare letters to landowners, some of whom have hired lawyers to defend themselves.The two sides tried arbitration in April. That effort failed, so the case will go to trial later this year. Meanwhile, Wood continues to keep the pressure on landowners with the mechanic’s liens. The suit over the 28.3-mile Risberg Pipeline has failed to settle in U.S. District Court in Erie, and both sides in the case are asking for more time to gather evidence as they prepare for trial. As the case advances slowly in court, a far-reaching aspect of the dispute is staying intact: mechanic’s liens of $18,946,185 each are still attached to pipeline work on hundreds of swaths of land near Albion in Erie County. The liens are an outgrowth of the federal suit that the builder of the pipeline, the Wood Group USA Inc., of Houston, Texas, filed in August against the Erie-based RH Energytrans, which owns the $86 million project. The pipeline, which opened in 2019, is made up of 15 miles of 12-inch steel pipe in Elk Creek Township in Erie County and about 13 miles of pipe in Ashtabula County, Ohio, where the project ends in North Kinsgsville. Back in January when this issue first hit the news we spoke to Dennis Holbrook, spokesman for RH energytrans. The position of RH is that they properly compensated Wood for the work done, including many of the extras Wood requested. From the start, there was a delay in beginning construction (no fault of either RH or Wood), pushing a lot of the construction into the winter and then into the rainy and wet spring. RH agreed to compensate Wood $1.3 million per month for the delayed start of construction, which went on for three months.RH also gave Wood an extra 40 days to complete the work, over and above the original time allotted. Even so, Wood took an extra six months to complete the project. Wood walked off the job in June and RH had to hire other contractors to finish up–not with building the pipeline itself, but with the work to re-seed and fix up construction areas, clean everything back to pristine condition.Holbrook pointed out there are often disputes in contracts for major projects, but it was unnecessary for Wood to serve landowners with mechanic’s liens. RH had already agreed to mediation! COVID delayed the start of the mediation. However, mediation ultimately failed.Here’s the thing. If this kind of situation keeps happening with companies like Wood serving landowners with court papers when there’s a tiff over the contract and payment, landowners will think twice about allowing a pipeline across their property. We sure would. In that case, everybody loses–including companies like Wood that build pipelines.
Concerned residents seek answers on radioactive waste concerns - — A service committee meeting was held Monday night, and one thing that was brought up by residents was radioactive waste concerns. Martins Ferry council members heard from other board members in the city and listened to residents, many there to voice concerns on the Austin Masters Services facility and the processing of hazardous material."Is the contamination from the oil and gas waste getting into the water system?" Bridgeport resident Bev Reed said. "The other concern we're looking at is PFAS chemicals, they call them forever chemicals, they found them in fracking fluid."Council members spoke and say they are doing what they can right now to help with those who believe it's contaminating the water and ensure its safe."I checked with the water superintendent and our water and our wells where we get our water from, they're checked daily, and we probably have the best drinking water in all of the state," said Bruce Shrodes, 2nd Ward Councilman.Council members like Bruce Shrodes have reached out to EPA and the Ohio Department of Natural Resources and say all they can do right now is wait to hear back for assistance. "So until we hear from them and let us know they're a hazard, we definitely want to know, we'd be the first that want to know."Reed is a part of the Concerned Ohio River Residents group and although there wasn't answer from the meeting on Monday, the group hopes for the city to find a resolution soon because of concern over Austin Masters' location and safety of all residents."Where this facility is located is really not safe. I mean, it's a half mile from the football field, it's a half mile from the hospital, and these are real issues and we need to take a real close look at them." Reed said.
Repairs to supply line at D-2 injection well in Cambridge completed - Repairs to a supply line that leaked at the SOS D-2 injection well off Southgate Parkway in June have been completed, according to the agency tasked to oversee the repairs and soil remediation at the site. "The leak was repaired and the line was pressure tested to ensure that there were no leaks in the repaired line," said Stephanie O'Grady of the Ohio Department of Natural Resources' Division of Oil and Gas Resources Management.The well was placed back in service on July 7."The division continues to oversee any identified soil impact remediation caused by the brine leak," added O'Grady.Cambridge officials were not advised of the leak for more than a week after city water department employees discovered what they believed to be an illegal dump site behind a business near the location of the injection well. Cambridge Mayor Tom Orr and Environmental Compliance and Safety Manager Louis Thornton both said they received no notification regarding the brine leak.Orr described the lack of notification as "disheartening.""Everything within the city has checked okay, but we are watching it. We have rallied up since we learned what happened," said Orr at the time the city learned of the leak during it's own investigation into the incident.It was not until local officials contacted the EPA and ODNR that they learned of the leak.Orr said city officials checked the reservoir and water systems, and found no evidence of contamination. The leak was reportedly the result of a weak spot in a weld in the line.
FERC Tells DC Circ. Gas Exports Can Justify Eminent Domain – Law360 (paywalled, re Nexus)
Ohio Oil and Gas Production Saw Steep Declines During Pandemic - Ohio’s oil and natural gas production dropped last year as operators shut in volumes and curbed activity amid the Covid-19 pandemic, according to the Ohio Oil and Gas Association’s (OOGA) annual Debrosse Memorial Report. Natural gas production fell by 10% year/year to 2.4 Tcf in 2020, according to estimates included in the report. Oil production fell 16% over the same time to 23.2 million bbl after setting a record in 2019. The pandemic curbed energy demand across the country and the world, which sent prices lower and forced oil and gas operators to slash activity and make price-related curtailments across Appalachia and the nation’s other leading fields. Permits issued by the state fell 25% last year to 353. The Utica Shale continued to dominate drilling programs in Ohio, accounting for 313 of the permits issued, while shallower legacy targets like the Clinton Sandstone accounted for the remainder. Completion activity also fell as operators deferred activity during the virus-induced slump. OOGA’s report said there were 267 completions in 2020, down 34% from 2019. Roughly 80% of all completions were for horizontal wells. Jefferson, Belmont, Monroe, Harrison and Guernsey counties accounted for 80% of all completions and wells drilled in the state last year. Meanwhile, Ascent Resources Corp., Encino Energy LLC and an affiliate of Southwestern Energy Co. were the top three most active operators. They accounted for nearly 70% of all wells drilled in the state during 2020. The number of producers operating in Ohio has continued to decline, going from 41 in 2019 to 31 in 2020, according to the report. Before the Utica land rush got underway in 2008, there were more than 180 exploration and production companies working in the state, but that number has declined every year since as assets in the basin have been consolidated by dominant operators.
Owens art exhibit considers effects of fracking in Ohio - WTOL— An art exhibit on display in the Walter E. Terhune Art Gallery at Owens Community College is bringing focus to the effects of fracking on the environment. The temporary exhibit is called, The Heavens and Earth."Chemicals and things from that process are getting to everyone. Whether it be in the atmosphere or in the brine that comes up from under the earth, with up to 600 chemicals in it," said Beth Genson, Owens Community College artist in residence.Fracking is a process of using hydraulics to break up the ground below the Earth's surface in order to gain access to natural gas and oil.Although it's not a typical sight in Northwest Ohio, Genson says some of what's produced is transported around the state.Genson says she takes inspiration from her firsthand experience visiting an area in Southeast Ohio where fracking is common."It just had such an impact on me, that I wanted to create some work that would speak to it, and also raise some money toward the project to further get regulation in Ohio," said Genson.Genson says she wants visitors to come away from the exhibit with an understanding of the effects of fracking in our state.By experiencing the gallery, she says you can help make change for the future."25 percent of the sale of any of the work goes to the freshwater accountability group. They are working hard to put regulation and legislation in Ohio to regulate the fracking industry here in Ohio," said Genson.The exhibit will be on display until August 13th. You can find information about the exhibit and reception here.
Series Of Sinkholes Spurs Action In Chesco To Halt Pipeline Work — Sinkholes — one after another along Mariner East 2 construction sites in Chester County — prompted a letter from the Chester County Commissioners today calling for the work to stop. In a letter to the Pennsylvania Public Utility Commission (PUC), the Chester County Commissioners on Monday requested that two Mariner East pipelines be ordered to cease operations while further investigations examine the impact on public safety from a recent outbreak of construction-induced sinkholes near the lines. With at least seven sinkhole formations documented this year, the Commissioners urged PUC to take swift action to protect residents' safety. The lines in question are Energy Transfer's Mariner East 1 (ME1) 8-inch and 12-inch natural gas liquid (NGL) pipelines. Both pipelines have been in the ground for about 80 years but only began carrying NGLs under high pressure much more recently. A PUC document explained ME1 is used to transport liquid propane, butane, and ethane. According to the letter from Commissioners' Chair Marian Moskowitz, and Commissioners Josh Maxwell and Michelle Kichline, at least seven sinkholes have been caused by construction near the lines in 2021 in the fragile, hollow karst geology in West Whiteland Township. The Commissioners asked that work be halted and the cause of the sinkholes be determined. Find out what's happening in West Chester with free, real-time updates from Patch. The Commissioners' letter reported that one recent sinkhole near the lines swallowed a tree, a phenomenon caught on video and provided with the letter to the PUC. "It seems to us that the significant risk of exposing these pipelines makes the potential for a catastrophic leak that much easier to occur and renders the ME1 and 12-inch pipelines 'unreasonable, unsafe and inadequate,'" wrote the County Commissioners. "This is why we are asking that you order operations of the ME1 and 12-inch pipelines be ceased until the Commission can better understand the cause of these sinkholes and the risks that they present to the operation of the operating NGL pipelines," the letter said.
SEPTA Nicetown plant: EPA takes up environmental justice complaint - The Environmental Protection Agency has a long history of failing to adequately enforce Title VI of the 1964 Civil Rights Act, which requires federal aid recipients not to discriminate on the basis of race, color, or national origin. Since October 2019, the agency has pursued just seven out of 31 complaints.In March, the EPA’s External Civil Rights Compliance Office began an investigation of the Philadelphia Department of Public Health’s Air Management Services permitting of SEPTA’s natural gas-powered combined heat and power plant at the Midvale bus depot in Nicetown. The plant is built and operating, providing electricity to SEPTA’s Regional Rail lines. The heat typically lost at traditional power plants is used to heat and cool the buildings at the Midvale bus depot.Opposition to the project was twofold: Neighbors and environmentalists said that it would increase air pollution, and that it would lock in reliance on a new fossil fuel plant at a time when climate change is creating record-breaking heat waves, forest fires, and flooding. Frances Upshaw pointed to the 40-acre Midvale depot — where more than 300 buses come each day to be cleaned and fixed.“These people would not have put this in Chestnut Hill or any other place where there were mostly white people, because that’s just not the way it’s done,” said Upshaw. “Everything in this system, unfortunately, and I hate to say it, is all institutional racism, period.”Her friend Paula Paul, who lives in East Germantown, said nobody should be building new fossil fuel plants.“If we’re moving toward an environment where we’re trying to get rid of fossil fuels because we know it’s bad, why would you do that?”
Mariner East pipeline cases slammed as 'gamesmanship' — An attorney for the two state constables who were cleared by a Chester County Common Pleas Court judge last week of felony charges in what Chester County’s former chief prosecutor called a “buy-a-badge scheme” criticized the prosecution for pursuing cases involving the Mariner East Pipeline project against “innocent people. “This District Attorney’s office continues to spend enormous amounts of time, effort and taxpayer money prosecuting innocent people that are even tangentially associated with the pipeline for causes and political reasons that have absolutely nothing to do with whether the individual did anything wrong. Saying that the prosecution had failed to meet its burden in showing that the two men had abused their authority as public servants in their work along the pipeline, Judge Jeffrey Sommer granted the defense’s motions for acquittal on the most serious of the charges.Dismissed were counts of bribery of a public official, a felony; official oppression; and separate counts of conflict of interest, with Sommer saying that there was no evidence presented to show that the men could be considered guilty of those charges by the jury hearing the case, even under the most favorable version of the prosecution’s case.“I don’t think there is any evidence that would allow you to remotely conclude that they took any benefit,” as public officials to work on the pipeline project, Sommer said in granting the motion to dismiss. He said it was clear from the evidence that Johnson and Robel were working as security guards for the pipeline constriction company, a fact for which there is no prohibition in state law for constables.The men were later found guilty by the jury hearing the case of misdemeanor counts of failing to file statements of financial interest with the state Ethics Commission. They will be sentenced for those offenses at a later date.
Energy Transfer to finish Pa. NGL line expansion in Q3 despite opposition (Reuters) - U.S. energy company Energy Transfer LP said on Wednesday it plans to finish the final phase of its long-delayed Mariner East 2 natural gas liquids (NGL) pipeline expansion in Pennsylvania in the third quarter despite calls by county commissioners to shut some operating parts of the system. Earlier this week, Chester County Commissioners asked the Pennsylvania Public Utility Commission (PUC) to shut the operating Mariner East 1 and a 12-inch (30-cm) "workaround" pipe being used by the Mariner East 2 expansion, according to local media. The county commissioners said several sinkholes have developed this year near the Mariner East 2 construction site in West Whiteland Township in southeastern Pennsylvania about 30 miles (48 kilometers) west of Philadelphia. Energy Transfer's Sunoco Pipeline unit used an existing 12-inch pipe - the so-called "workaround" pipe - to allow the 20-inch Mariner East 2 to enter service in December 2018 after numerous delays related to sinkholes and drilling fluid spills slowed the project's construction. In regards to the Chester County request, a spokesperson at Energy Transfer said "there are no safety concerns regarding the ongoing operations of our active pipelines in this area, which have safely operated for years." Mariner East transports liquids from the Marcellus/Utica shale in western Pennsylvania to customers in the state and elsewhere, including international exports from Energy Transfer's Marcus Hook complex near Philadelphia. Sunoco started work on the $2.5 billion Mariner East expansion in February 2017 and planned to finish the 350-mile (563-km) pipeline in the third quarter of 2017. Mariner East 2 did not enter service until December 2018 due primarily to several work stoppages by state agencies. Since May 2017, Pennsylvania has issued 122 notices of violation to Mariner East, mostly for drilling fluid spills, including two in June.
Regulation Is Too Weak for Radioactive Oil and Gas Waste | NRDC - The U.S. oil and gas industry produced an estimated one trillion gallons of produced water in 2017. And this waste—along with drilling and fracking waste--can contain radioactive elements known as “technologically enhanced naturally occurring radioactive material,” or TENORM. A new NRDC report describes these risks and how weak regulations fail to appropriately protect workers and communities.The U.S. oil and gas industry produced an estimated one trillion gallons of produced water in 2017. And this waste—along with drilling and fracking waste--can contain radioactive elements known as “technologically enhanced naturally occurring radioactive material,” or TENORM. A new NRDC report describes these risks and how weak regulations fail to appropriately protect workers and communities. TENORM that is not adequately managed poses significant health threats to oil and gas workers and their families and people who live near oil and gas operations. Nearby residents may face an increased risk of cancer. Making the situation even more dangerous, many oil and gas activities take place in residential neighborhoods, in close proximity to homes, schools, and playgrounds. My colleague Bemnet Alemayehu details the health threats from oil and gas TENORM here. Despite the clear health risks, there are no dedicated federal regulations to ensure comprehensive and safer management of radioactive oil and gas materials. Bedrock federal environmental, health, and safety laws have gaping loopholes and exemptions that allow radioactive oil and gas materials to go virtually unregulated, including the Resource Conservation and Recovery Act that governs waste management, the Atomic Energy Act, the Clean Water Act, the Safe Drinking Water Act, and the Clean Air Act. Rules to protect workers, including truck drivers, also have significant gaps. The Conference of Radiation Control Program Directors, an association of state and local professionals, has concluded that “no federal regulations explicitly govern the management and disposal of TENORM associated with the oil and gas industry.” State regulations are also filled with gaps that allow unsafe practices for radioactive oil and gas waste. NRDC worked with Fair Shake Environmental Legal Services to review state regulations in the 12 states with the most oil and gas production. We looked at regulations for landfills that accept oil and gas waste, road-spreading, discharging into surface waters, and burying waste on a wellpad. Our review found that 4 of the 12 states have no standards at all for the level of radioactive material in oil and gas waste that can be accepted at landfills, only 3 require monitoring of radioactive material in the wastewater that leaches out of landfills, and 10 allow oil and gas waste to be spread on roads for uses such as dust suppression, deicing, or road maintenance. Compounding the problem, radioactive oil and gas wastes are frequently transported across state lines as waste haulers take advantage of the lack of consistent state regulations to search for the cheapest or easiest way to dispose of radioactive material. Our report details case studies where scientific research has found radioactive materials at high levels being released into the environment in Kentucky, North Dakota, Ohio, Pennsylvania, and Wyoming.
The Oil and Gas Industry Produces Radioactive Waste. Lots of It - Massive amounts of radioactive waste brought to the surface by oil and gas wells have overwhelmed the industry and the state and federal agencies that regulate it, according to a report released today by the prominent environmental group Natural Resources Defense Council. The waste poses “significant health threats,” including the increased risk of cancer to oil and gas workers and their families and also nearby communities.“We know that the waste has radioactive elements, we know that it can have very high and dangerous levels, we know that some of the waste gets into the environment, and we know that people who live or work near various oil and gas sites are exposed to the waste. What we don’t know are the full extent of the health impacts,” says Amy Mall, an analyst with NRDC who has been researching oilfield waste for 15 years and is a co-author on the report.The report conveys that radioactive oilfield waste is piling up at landfills across America — and in at least some documented cases leaching radioactivity through treatment plants and into waterways. It is also being spread on farm fields in states like Oklahoma and Texas and on roads across the Midwest and Northeast under the belief that it melts ice and suppresses dust.Many of the issues mentioned in the NRDC report were reported by Rolling Stone in a 20-month investigation published in January 2020 that found a sweeping arc of contamination. “There is little public awareness of this enormous waste stream, the disposal of which could present dangers at every step,” the story stated, “from being transported along America’s highways in unmarked trucks; handled by workers who are often misinformed and under-protected; leaked into waterways; and stored in dumps that are not equipped to contain the toxicity. Brine has even been used in commercial products sold at hardwares stores and is spread on local roads as a de-icer.” “Radioactive elements are naturally present in many soil and rock formations, as well as the water that flows through them,” the NRDC report explains. Oil and gas production brings those elements to the surface. Wells generate a highly salty toxic liquid called brine at the rate of about a trillion gallons a year in the U.S. It contains heavy metals and can contain significant amounts of the carcinogenic radioactive element radium. The U.S. EPA’s webpage on oilfield waste indicates that radium and lead-210, a radioactive isotope of lead, can also accumulate and concentrate in a sludge at the bottom of storage containers and in the hardened mineral deposits that form on the inside of oilfield piping. Crushed dirt and rock called drilled cuttings, which are produced through fracking, can contain elevated levels of uranium and thorium. The NRDC report, entitled “A Hot Fracking Mess: How Weak Regulation of Oil and Gas Production Leads to Radioactive Waste in Our Water, Air, and Communities,” shows that despite the industry and regulators knowing about the radioactivity issue, the risks have been patently ignored. A 1982 American Petroleum Institute paper obtained by Rolling Stone laid out hazards but warned the industry that regulation “could impose a severe burden.” A 1987 EPA report to Congress detailed numerous harms, but according to one EPA employee cited in the NRDC report, was ignored for “solely political reasons.” To this day there remains no single federal rule governing the radioactivity brought to the surface in oil and gas development, says the NRDC, and state regulators have failed to pick up the pieces and fill in the gaps.
Wolf administration approves over $42,000 for new pipeline investment program in Crawford County- — On Tuesday, Department of Community and Economic Development (DCED) Secretary Dennis Davin announced more than $42,000 had been approved for a new Pipeline Investment Program (PIPE) project through the Commonwealth Financing Authority (CFA). The project looks to improve infrastructure, save energy, and create and retain jobs in Crawford County. “The PIPE project approved today will help connect a business park to natural gas, which will create jobs, save money, and grow business within the area,” Secretary Davin said. “This program is so critical because it helps Pennsylvanians access the abundant natural gas resources available throughout the commonwealth, while doing their part to decrease their carbon footprint.” Watch: Storms cause more flooding in Titusville overnight The approved project in Crawford County consists of a cooperation between National Fuel and the Titusville Redevelopment Authority. A total of $42,544 in grant funding was approved to install 1,547 linear feet of natural gas pipeline to bring Titusville Opportunity Park in compliance with the Public Utility Commission (PUC). The PUC requires each building in the business park to be metered separately, and this project will connect the 14 buildings at the park to the main gas line, which is located just outside of the park. This will keep more than 300 jobs in 18 businesses within the business park and will help provide growth by bringing more businesses to the area. The total cost of the project is $85,088.
Destined to Fail: Why the Appalachian Natural Gas Boom Failed to Deliver Jobs & Prosperity and What It Teaches Us – Ohio River Valley Institute --Between 2008 and 2019, the twenty-two counties in Ohio, Pennsylvania, and West Virginia that produce 90% of Appalachian natural gas badly trailed the nation in key measures of economic prosperity, including growth in jobs, personal income, and population. That’s despite the fact that, during this period, economic output grew at a rate three times faster than that of the nation.The immense growth in gross domestic product (GDP) in the twenty-two counties we’ll call “Frackalachia” was driven by a natural gas production boom, which caused the Mining, quarrying, and oil and gas sector to grow from 4% of Frackalachia’s economy in 2008 to 35% in 2019.But, for the counties of Frackalachia, the boom, which reshaped the region’s landscape as well pads, pipelines, processing facilities and other gas-related infrastructure proliferated, turned out to be an economic bust and a bad deal that imposed significant burdens on people and communities while giving back little in return.As the prevalence of the Mining sector increased and output as measured by gross domestic product (GDP) skyrocketed, jobs in Frackalachia increased by just 1.6%—more than eight percentage points below the national average. Personal income growth was a third below the national average, and Frackalachia lost over 37,000 people even as the nation’s population was growing by nearly 8%. The question is, why did this disconnect between economic growth and key measures of prosperity happen? Can the problems that prevented job and income growth in Frackalachia be fixed, or at least mitigated? And what can the Frackalachian counties and the rest of us learn from the experience to help us come up with better economic development strategies? This reports attempts to answer these questions.
New reports make case that natural gas production boom was a bust for Appalachia, urge economic transition - Appalachia’s natural gas boom turned out to be an economic bust that local and state officials can rebound from if they embrace the rising clean energy economy.That’s the bottom line of two bottom-line-focused reports released Tuesday by nonprofit think tank Ohio River Valley Institute making an economic case for transitioning away from fossil fuels, especially natural gas development that has failed to convert production into prosperity.“We know that the Appalachian natural gas boom hasn’t just failed to deliver growth and jobs and prosperity so far. We now know that it’s structurally incapable of doing so,” Ohio River Valley Institute senior researcher Sean O’Leary contended during a webinar on the reports Tuesday. “[That] means that a lot of economic development strategies in the region need to be rethought.”The Ohio River Valley Institute’s analysis focuses on changes in income, jobs, population and gross domestic product — the total market value of goods and services produced — in 22 counties in West Virginia, Ohio and Pennsylvania from 2008 to 2019 that suggest a rise natural gas production in that span did little to lift up the economies in those counties.One of the reports calls those 22 counties — which include Doddridge, Harrison, Marshall, Ohio, Ritchie, Tyler and Wetzel counties in West Virginia — “Frackalachia” based on the slang term for hydraulic fracturing of deep rock formations to extract natural gas or oil.Jobs increased in the counties that comprise “Frackalachia” by just 1.6% from 2008 to 2019, 2.3 percentage points behind all West Virginia, Ohio and Pennsylvania counties and 8.3 percentage points below the national average, the report notes.The report concludes that a dramatic increase in gross domestic product in “Frackalachia” over the same span that came with the natural gas boom didn’t yield economic prosperity because the boom depended heavily on out-of-state workers and service suppliers, yielded less leasing and royalty income for property owners than expected and generated comparatively little income going to employee compensation.
Massive Cleanup Underway, 1,200-Gallon ConEd Spill In LI Sound | New Rochelle, NY Patch— Cleanup efforts are taking place around the clock after a massive underground spill discharged more than a 1,000 gallons of oil used to cool transmission lines into the Long Island Sound near Wright Island Marina.By Saturday morning, New Rochelle police had the area closed off. Boats, heavy equipment, pumper trucks and empty tankers were being staged nearby on Drake Street throughout the night on both Saturday and Sunday. Dozens of crews were still working to clean up the spill on Monday morning.Having no way to control the flow without ConEd, New Rochelle HazMat units could only hope to divert and contain the discharge. Because, at the time, unknown fluid was flowing into the nearby marina through storm drains, the help of the Coast Guard and New Rochelle Police Department Marine units was requested by firefighters.The firefighters placed booms by one driveway on Nautilus Place to keep the oil out. Then, with the help of police harbor units, they moved on to placing booms across the mouth of the harbor, to help keep the spill from flowing out to the Long Island Sound.ConEd and the New Rochelle Department of Public Works arrived with an army of tank trucks and sand for the street and began efforts to contain the discharge and stop the leak. Fire officials said the scene was turned over to ConEd at this point.The discharge was triggered by a water main break. Officials said at least 1,200 gallons of dielectric fluid was released from underground utility equipment used by ConEd. The oil sent flowing into the Long Island Sound is described as non-hazardous by the utility company.The cleanup required everything from tanker trucks to hand-cleaning an area several city blocks wide. (Jeff Edwards/Patch)"Right now, the only danger is slippage, things of that nature," New Rochelle Fire Chief Andrew Sandor told CBS News New York's Andrea Grymes. "We're told that it's dielectric oil, not PCBs, anything like that."Emergency crews were originally called to the site after calls began coming in about a possible explosion and street flooding. ConEd said it is still investigating the cause of the accidental discharge.
Alamance County couple raises awareness to Native American land - A couple from Alamance County, Crystal Cavalier-Keck and Jason Crazy Bear Keck, is taking this trip with a totem pole that symbolizes thousands of years of history. They’re joining a group that’s heading to the nation's capital to speak out against the Mountain Valley Pipeline Southgate Project and other Native American land rights issues.Crystal Cavalier-Keck is a member of the Occaneechi Band of the Saponi Nation and Jason is a descendent of the Choctaw Nation. Both said development projects like the MVP are threatening sacred lands and burial grounds.“We have to start standing up and standing together, especially in North Carolina. That's so important for the people here in North Carolina. Like they don't even know that these things are happening in their own back yards,” Crystal Cavalier-Keck of Alamance County said.She also added that “you have neighbors who are being affected by the drinking water and the air quality.” WXII 12 News reached out to representatives with the MVP project. Shawn Day with Capital Results sent a statement:“Federal and state authorities have recognized the MVP Southgate project is needed to meet public demand for natural gas in North Carolina. Dominion Energy North Carolina, a local natural gas distribution company, has added more than 100,000 new customers with no new supply source over the past decade, and local demand is expected to increase based on the state’s projections for continued population growth. North Carolina’s Utilities Commission has recognized MVP Southgate offers the best option for meeting that demand.For the past three years, the MVP Southgate team has worked diligently with landowners, tribes, non-governmental organizations and federal, state and local officials to design a route that minimizes impacts to the environment. These efforts included extensive cultural and environmental survey work to identify any sensitive resources and found the project route would not affect any known burial grounds. In issuing its Final Environmental Impact Statement last year, the Federal Energy Regulatory Commission concluded the project could be built safely and responsibly, with no permanent impacts to surface or ground water resources.”
Pike County residents in quandary over gas - Folks in two areas of Pike county woke up July 14 only to find their gas had been turned off. According to a statement released by Kentucky Frontier Gas, the affected customers are in the Hurricane Creek and Robinson Creek areas of the county. The statement said approximately 100 customers are affected by the shut off. Ky. Frontier’s statement said they serve these ‘Farm Tap’ customers with gas supply off gas gathering pipelines operated by Kinzer Drilling. Ky Frontier said Kinzer “apparently decided to abandon the lines and shut them down July 13 without discussing or warning frontier or affected customers.” Meanwhile, Kinzer Drilling released their own statement saying that “an evaluation was performed of the gas lines which are used to transmit gas on behalf of Ky Frontier Gas for service of its customers on Hurricane Creek and Robinson Creek. It was discovered that these lines have developed serious leaks in populated areas.” The Kinzer statement went on to say Kinzer was “forced to immediately discontinue gas flow through those lines due to imminent threat to public safety.” While Ky Frontier indicated in their statement that they are attempting to work with Kinzer to correct the situation, Kinzer in their statement is encouraging people who have utilized natural gas along these routes to “convert to other sources of energy.” According to national statistics, the cost to switch from gas to electric service could cost between $3,000 to $7,000 depending on the size of the home. Residents in the affected areas are still trying to see if anything else can be done as many have indicated they don’t have the financial means to convert their homes and replace gas appliances with electric ones. Pike Judge-Executive Ray Jones said the county is aware of the situation but at this point there was really very little the county could do. The Kentucky Public Service Commission acknowledged receiving complaints from residents regarding the gas cutoff but offered no further comment.
Some central Virginia property owners plan to fight proposed gas pipeline - Some people in central Virginia are preparing to fight a plan to put a natural gas pipeline through their properties that would serve a yet-to-be-built power plant in Charles City County.While Charles City County has approved the plant, property owners and county government leaders along the pipeline path said they have no information yet about the actual route of the pipeline. Environmental groups say the line would serve a plant that is not needed for Virginia’s electricity needs.“The natural gas industry has written our law in Virginia, and nationally, to a very great extent,” said Lynn Peace Wilson of Henrico County, who received a letter from the pipeline company about her property across the Chickahominy River in New Kent County. “They have written themselves protections that make it very difficult for anyone to question what they are doing.”The company behind the pipeline proposes “to foul our air and our water and our soil and our wetlands”should prepare for a fight, she said.The letters that went out didn’t say so, but the developer of the plant told the Richmond Times-Dispatch that the company won’t try to legally force any property owner to allow use of their land for the pipeline. If any property owners along the proposed route from near Charlottesville to Charles City County object, the company will change the route, said Irfan Ali of Balico LLC.He said the plant would bring revenue to an impoverished county and help Virginia replace coal plants with natural gas, which is cleaner. “There is no way that windmills and solar are going to meet the needs of Virginia, and industry,” he said.The natural gas power plant in question is called Chickahominy Power. The plant would be what’s called a merchant plant — backed by private investors and not owned by a utility. The plant was approved by the Virginia Department of Environmental Quality.It would be on Roxbury Road, about 23 miles from downtown Richmond. It would burn natural gas piped in from other states to create electricity to be sold into a large wholesale market of numerous states. And it would have more electricity-generating capacity than any of the 12 natural gas plants in the state owned by Dominion Energy, Virginia’s largest electric utility.The Virginia General Assembly passed an environmental law in 2020 called the Clean Economy Act aimed at phasing out the use of natural gas to create electricity but, under the law, the plant could operate until at least 2050. Developers of a proposed second gas plant a mile away announced last week that they are canceling the plan.
How Va. pipeline ruling may reshape environmental justice - A leading expert on human health effects of air pollution at New York University, George Thurston says low-income areas and people of color are fighting fossil fuel projects like pipelines on an unequal playing field against well-paid, full-time industry consultants. "I’m just trying to give them the same level of scientific representation that the vested interests have." Thurston is known for publishing the first study in the U.S. linking fine particulate matter or PM2.5 to mortality in 1987. More recently, he has weighed in on emissions from the Lambert compressor station, a natural gas facility in rural Virginia that would help extend the 303-mile Mountain Valley pipeline project an extra 75 miles into North Carolina. Opponents say developers of the MVP Southgate expansion project have not done enough to analyze the facility’s health impacts on the low-income and majority Black Banister District in Pittsylvania County, Va. The outcome of the Mountain Valley battle could influence how pipeline emissions are measured in Virginia, which observers say could shift the environmental justice debate in other states. It also underscores the political, legal and market pressures facing pipeline projects after a string of cancellations ranging from the mammoth Keystone XL oil conduit to the Atlantic Coast natural gas pipeline in the Virginias. Earlier this month, for example, developers of the Byhalia Connection crude oil pipeline in Memphis pulled the plug on the project, which had sparked uproar over its proposed route through predominantly Black neighborhoods in the city (Energywire, July 6). Meanwhile, President Biden has pledged to make environmental justice a pillar of his clean energy agenda. Critics of the push to revamp pollution analysis say it could stymie needed infrastructure projects where developers have already implemented the latest technology to limit environmental footprints. But public health experts say there is a broader need to reframe project development to emphasize the health concerns of low-income and minority residents. "Environmental justice and environmental racism have not been a concern uniformly in considering siting and permitting out of potentially polluting activities. It’s been the exact opposite historically,"
Gas Ban Monitor: Building electrification evolves as 19 states prohibit bans - Local building electrification measures expanded and evolved in the first half of 2021, as the policy also percolated to the federal and international stage. Meanwhile, state laws prohibiting natural gas bans bolstered a growing firewall that now stretches across most of the southern U.S. and from the Rockies to the Midwest. The Biden administration on May 17 announced a building decarbonization policy that seeks to accelerate electrification and support the market for heat pumps. The following day, the International Energy Agency recommended policymakers around the world ban fossil fuel furnace sales by 2025 and adopt building codes that would largely phase out natural gas use in buildings. At the start of July, at least 19 U.S. states had adopted laws that prohibit the very policy that the IEA now endorses as a viable and efficient pathway to achieving net-zero emissions by 2050. Those states accounted for nearly one-third of U.S. residential and commercial gas consumption in 2019. Some of the biggest consumers — Ohio, Texas and Indiana — have passed such laws in recent months. In New York City, city councilors introduced legislation to prohibit fossil fuel combustion in new buildings. Meanwhile, a housing panel delivered recommendations to New York's Climate Action Council to phase out gas use in new and existing buildings statewide and retire parts of the distribution system. As state officials in Massachusetts develop an opt-in stretch energy code for construction — which "stretches" beyond minimum code requirements — some towns and cities are implementing interim measures to spur building electrification. Those include a new bylaw that uses zoning rules to restrict gas use in construction and renovations in Brookline, the first town to pass an East Coast gas ban. In June, Colorado adopted a law that requires investor-owned electric utilities to offer incentives to build all-electric or transition from natural gas and fossil fuel heating and cooking. Notably, however, the law does not allow state regulators to ban new gas hookups or require residents to replace gas-fired furnaces. The state legislature had considered legislation to prohibit local building gas bans, but the bill died in committee. Meanwhile, a Washington law that would phase out gas utility service across the state and a Vermont bill that would allow authorize Burlington to impose a carbon fee on new gas grid-connected buildings did not receive full chamber votes in state legislatures. In Oregon, the Eugene City Council signaled it would soon consider building electrification requirements.
U.S. natgas futures hit 30-month high on rising air conditioning use (Reuters) - U.S. natural gas futures jumped almost 3% to a 30-month high on Monday on soaring global gas prices and forecasts for more air conditioning demand next week than previously expected. The U.S. price increase occurred despite a 5% drop in crude futures and forecasts for a little less hot weather and lower air conditioning demand this week than previously expected. Gas futures often follow big moves in oil prices, but not on Monday. O/R Front-month gas futures rose 10.5 cents, or 2.9%, to settle at $3.779 per million British thermal units (mmBtu), their highest close since December 2018. Speculators, meanwhile, cut their net long futures and options positions on the New York Mercantile and Intercontinental Exchanges last week for the first time in seven weeks as buyers cashed in some of their gains after front-month futures rose over 15% during the prior three weeks. Data provider Refinitiv said U.S. output in the Lower 48 states slipped to 91.5 billion cubic feet per day (bcfd) so far in July, due mostly to pipeline problems in West Virginia earlier in the month. That compares with an average of 92.2 bcfd in June and an all-time high of 95.4 bcfd in November 2019. Refinitiv projected average gas demand, including exports, would rise from 92.3 bcfd this week to 94.7 bcfd next week as the weather turns seasonally hotter. The forecast for next week was higher than Refinitiv predicted on Friday. The amount of gas flowing to U.S. liquefied natural gas (LNG) export plants averaged 10.9 bcfd so far in July, up from 10.1 bcfd in June but still below the record 11.5 bcfd in April. With European and Asian gas trading near $13 and $14 per mmBtu, respectively, analysts said buyers around the world would keep purchasing all the LNG the United States can produce.
US working natural gas volumes in underground storage increase 49 Bcf: EIA | S&P Global Platts - The natural gas injection into US storage fields in the week ended July 16 measured 12 Bcf more than the five-year average, but upcoming builds look more in line with historical norms as the Henry Hub winter strip surpasses $4/MMBtu, which is $1.35 more than this time last July. Working gas in storage increased by 49 Bcf to 2.678 Tcf for the week, the US Energy Information Administration reported July 22. It was more than the 43 Bcf addition expected by an S&P Global Platts' survey of analysts. It also outgained the five-year average build of 36 Bcf and last year's 38 Bcf injection in the corresponding week. Storage volumes now stand 532 Bcf, or 16.6%, less than the year-ago level of 3.210 Tcf and 176 Bcf, or 6.2%, less than the five-year average of 2.854 Tcf. The build was less than the 55 Bcf injection reported for the week prior as demand increases outpaced those in supply. Total US demand averaged roughly 2.2 Bcf/d higher week over week, according to Platts Analytics. Gas-fired power demand grew across multiple regions, most notably in the US Southwest where burns increased by nearly 1 Bcf/d week over week. The NYMEX Henry Hub August contract added 2 cents to $3.98/MMBtu in trading following the release of the weekly storage report. The balance-of-summer averaged $3.97, which is only 5 cents less than the winter strip, providing little to no incentive to inject. November through March are up 1.6 cents/MMBtu for an average $4.02/MMBtu. This time last year, when storage measured 436 Bcf more than the five-year average, the winter strip was $2.65/MMBtu and 90 cents above the balance of summer. The EIA's Pacific region posted a net withdrawal of 3 Bcf for the week. This reflected the heat wave impacting California and other Western states, while the eastern half of the US was more temperate. Storage injections in the EIA's Pacific region have lagged behind typical levels this summer, as operators struggle to meet elevated demand while maintaining steady injections. Pacific storage activity trended bearish relative to the five-year average in April and May, adding 71 Bcf versus 63 Bcf during the shoulder season. The arrival of hot weather reversed that, with June and July injecting 16 Bcf in 2021 versus the five-year average of 24 Bcf over the same period. Platts Analytics' supply and demand model currently forecasts a 33 Bcf injection for the week ending July 23, which would measure 5 Bcf more than the five-year average. Fundamentals this week have tightened further, but to a lesser degree, as demand has risen by around 400 MMcf/d while supplies fell 300 MMcf/d. The following week shows a 27 Bcf addition compared to the five-year average injection of 30 Bcf.
August Natural Gas Futures Eclipse $4.00 Threshold as Demand Surges - Traders looked past a bearish storage print by the Energy Information Administration (EIA) on Thursday and focused instead on persistently strong demand and relatively light production, a combination favorable for continued strength in natural gas prices. The prompt month has climbed five straight days and on Thursday topped the $4.00/MMBtu threshold for the first time since 2018. The August Nymex contract gained 4.4 cents day/day and settled at $4.003/MMBtu. September advanced 4.4 cents to $3.982. NGI’s Spot Gas National Avg., meanwhile, stepped back after three days of gains, declining 2.5 cents to $3.785. EIA reported an injection of 49 Bcf natural gas into storage for the week ended July 16 – higher than analysts’ median expectations and historic averages. While scorching hot and dry conditions covered much of the West during the covered week, parts of the nation’s midsection and much of the East saw average temperatures and demand. By region, the Midwest and East led with builds of 21 Bcf and 19 Bcf, respectively, according to EIA. Ahead of the report, major surveys foreshadowed a build in the mid-40s Bcf. Reuters’ poll of analysts produced a median injection of 45 Bcf, while a Bloomberg survey landed at a median injection of 43 Bcf. NGI’s model predicted a 30 Bcf injection. In the similar week a year earlier, EIA recorded a 38 Bcf build, while the five-year average injection is 36 Bcf. The bearish result for last week pointed to a modest mid-summer loosening of balances after a 55 Bcf build a week earlier, Bespoke Weather Services said, initially sending futures lower after the EIA print. However, Bespoke added, demand has outstripped supply most of the summer, and with heat expected to intensify in August and export activity poised to accelerate, storage levels are likely to prove lighter than average heading into the fall. The build for the July 16 week lifted inventories to 2,678 Bcf, though that was well below the year-earlier level of 3,210 Bcf and shy of the five-year average of 2,854 Bcf. Production in July has hovered around 91 Bcf/d – below highs earlier in the summer around 92-93 Bcf — and did so again Thursday. At the same time, liquefied natural gas (LNG) volumes were close to 11 Bcf on Thursday – approaching record levels. Export demand is strong from both Asia and Europe, where supplies are light following a harsh winter and an unusually cool spring. “Low European storage combined with increasing decarbonization efforts as well as seasonally peaking demand are all major contributors to the price spikes abroad. These elevated international prices have greatly benefited U.S. LNG exporters, who despite higher Henry Hub prices, are making tremendous profits off the growing arbitrage,” “U.S. LNG exporters are heavily incentivized to continue to export enough LNG that we are quickly approaching the U.S. LNG market’s nameplate capacity at 11.6 Bcf/d,” the Gelber analysts said. Looking ahead to next week’s storage report, participants on The Desk’s online energy platform Enelyst were anticipating a build in the 40s Bcf. Bespoke preliminarily modeled a 41 Bcf injection
U.S. natgas futures hit 31-month high on hotter forecasts (Reuters) - U.S. natural gas futures rose to a fresh 31-month high on Friday on forecasts for hotter weather and higher air conditioning demand over the next two weeks than previously expected. Front-month gas futures NGc1 rose 5.7 cents, or 1.4%, to settle at $4.060 per million British thermal units (mmBtu), their highest close since December 2018 for a fifth day in a row. That put the front-month up almost 11% for the week after holding steady last week, its biggest weekly percentage gain since February. Data provider Refinitiv said U.S. output in the Lower 48 states slipped to 91.5 billion cubic feet per day (bcfd) so far in July, due mostly to pipeline problems in West Virginia earlier in the month. That compares with an average of 92.2 bcfd in June and an all-time high of 95.4 bcfd in November 2019. Refinitiv projected average gas demand, including exports, would rise from 92.5 bcfd this week to 95.5 bcfd next week and 95.6 bcfd in two weeks as the weather turns hotter than normal. Those forecasts were slightly higher than Refinitiv predicted on Thursday on expectations power generators will burn more gas to meet rising air conditioning demand. "Gas demand from the power sector has largely outperformed this summer and continues to hold a larger than expected share of the generation mix. Recent coal retirements have reduced that fuel’s ability to cover the shortfall left by lagging renewables this summer, placing the onus on gas to answer the call," analysts at Gelber & Associates in Houston said in a note. The amount of gas flowing to U.S. liquefied natural gas (LNG) export plants has averaged 10.8 bcfd so far in July, up from 10.1 bcfd in June but still below the record 11.5 bcfd in April. With European TRNLTTFMc1 and Asian JKMc1 gas trading near $12 and $14 per mmBtu, respectively, analysts said buyers around the world would keep purchasing all the LNG the United States can produce. U.S. pipeline exports to Mexico, meanwhile, have averaged 6.6 bcfd so far in July, down from a record 6.7 bcfd in June.
U.S. liquefied natural gas exports were at record high levels in the first half of 2021 -U.S. exports of liquefied natural gas (LNG) continued to grow in the first six months of 2021, averaging 9.5 billion cubic feet per day (Bcf/d). This average marks an increase of 41%, or 2.8 Bcf/d, compared with the same period in 2020, according to the U.S. Department of Energy’s LNG Monthly reports and our estimates for June 2021, based on shipping data from Bloomberg Finance L.P. In the summer months of 2020, U.S. LNG exports fell to record lows, but then they set consecutive record highs in November and December.U.S. LNG exports increased in the first half of this year because of an increase in international natural gas and LNG spot prices in Asia and Europe, an increase in global LNG demand following easing of COVID-19 restrictions, and continuous unplanned outages at LNG export facilities in several countries, including Australia, Malaysia, Nigeria, Algeria, Norway, and Trinidad and Tobago.In Asia, colder-than-normal winter temperatures led to increased demand for spot LNG imports. Natural gas demand in the spring continued to rise amid low post-winter inventories, which contributed to unseasonably high natural gas prices, attracting higher volumes of flexible LNG supplies, particularly from the United States.In Europe, natural gas storage inventories were also low following a cold winter. Increasingly hot temperatures in May and June and higher natural gas demand from the electric power sector contributed to high natural gas spot prices. Europe’s natural gas spot prices have historically been lower than prices in Asia; however, this year, Europe’s natural gas prices are tracking Asia’s spot LNG prices more closely to attract flexible LNG supplies from around the world to refill storage inventories. The U.S. Henry Hub natural gas benchmark and U.S. LNG spot market prices have been lower than international natural gas and LNG spot prices this year, which has supported record-high volumes of U.S. LNG exports. U.S. LNG exports also increased because of new export capacity added in 2020. The final liquefaction units were commissioned at Freeport, Cameron, and Corpus Christi LNG, and the remaining small-scale units were placed in service at Elba Island LNG, increasing total U.S. LNG peak export capacity by a combined 2.3 Bcf/d for a total of 10.8 Bcf/d. As in 2020, Asia remained the main destination for U.S. LNG exports from January through May 2021, accounting for 46% of the total, followed by Europe with a five-month average share of 37%. Exports to Latin America also increased, particularly to Brazil, which is experiencing its worst drought in more than 90 years.
U.S. natural gas exports to Mexico established a new monthly record in June 2021 --Natural gas pipeline exports from the United States to Mexico surpassed 7 billion cubic feet per day (Bcf/d) on multiple days during June, according to data from Wood Mackenzie. The highest amount of pipeline exports, 7.4 Bcf/d, was sent out on June 17.Over the past few years, Mexico has expanded its natural gas pipeline infrastructure and has relied increasingly on imported natural gas from U.S. pipelines. Pipeline imports accounted for 76% of Mexico’s total natural gas supply in June 2021, compared with 40% in June 2015. Mexico has reduced both its natural gas production and imports of liquefied natural gas (LNG) as a share of its total natural gas supply.U.S. natural gas pipeline exports to Mexico averaged 6.8 Bcf/d in June 2021, up 25% from June 2020 and 44% more than the previous five-year (2016–2020) monthly average. We expect these record-high flows, which were driven by increased power demand, high temperatures, and greater industrial demand in June, to continue through the summer. New pipeline additions that went into service during 2020 and in the first half of 2021 increased the volume of natural gas flowing to natural gas-fired power plants, industrial plants, and pipeline interconnections throughout Mexico. Two cross-border pipelines drove the growth: the Sur de Texas-Tuxpan Pipeline, which has a capacity of 2.6 Bcf/d and delivers natural gas from the U.S. border at Brownsville, Texas, to Tuxpan in Veracruz, Mexico, and the Trans-Pecos Pipeline (part of the Wahalajara system), which has a capacity of 1.4 Bcf/d and delivers natural gas to the U.S. border at Presidio, Texas.The Sur de Texas-Tuxpan Pipeline increased flows to an estimated 1.7 Bcf/d in June 2021, compared with year-ago levels of 0.8 Bcf/d. The pipeline’s volume increased because of expanded infrastructure in Mexico, which has allowed more natural gas to flow to power plants in the Mexico City region and to Mérida markets in the Yucatán Peninsula.The Trans-Pecos Pipeline increased flows to the Wahalajara pipeline system to 0.8 Bcf/d, compared with year-ago levels of 0.2 Bcf/d. This pipeline connects the Waha Hub in West Texas to Guadalajara and other population centers in West-Central Mexico. Some of this increase is the result of the increased flow capacity on the Villa de Reyes-Aguascalientes-Guadalajara Pipeline (VAG) in Central Mexico and subsequent delivery points that entered service when the pipeline was completed in October 2020. Because of increased access to natural gas imports, Mexico has increased its use of natural gas to generate electricity. Power plants in Mexico used about 4.9 Bcf/d of natural gas for power generation in June, up 19% compared with last year. Seasonally high temperatures in areas of Northern and Central Mexico during parts of June also increased demand for electricity. Industrial sector natural gas demand reached 3.3 Bcf/d in June, up 31% compared with last year, largely driven by the return to pre-pandemic demand levels and the reversal of related economic effects.
Company asks for revocation of federal, state permits for Byhalia Connection Pipeline - Plains All American Pipeline is giving up its state and federal permits for the proposed Byhalia Pipeline as it continues to close out the project since the company announced July 2 it was abandoning its plans.Patrick Parker, an attorney with the Tennessee Department of Environment and Conservation, told an administrative law judge Monday that the company asked that its state permit be revoked. Parker spoke during a status call on pipeline opponents’ appeal of TDEC’s decision to grant an aquatic resource alteration permit.“They are going to relinquish their permit and we’re going to revoke it,” Parker told Judge Michael Begley.Plains will also drop the federal permit it obtained from the U.S. Army Corps of Engineers, a company official said in a July 8 letter to the Memphis and Vicksburg districts of the Corps. “Due to changes in energy production post-COVID, Byhalia has determined that it will no longer pursue this pipeline construction project and respectfully requests the Army Corps of Engineers revoke the 2017 Nationwide Permit 12 verification,” said Carol E. Howard, Plains’ Senior Environmental Permitting and Compliance Specialist.The Nationwide Permit 12 gives companies a fast-track process that requires a single federal permit for water crossings rather than individual permits for each, and does not require an environmental impact statement or notification to the public at any point in the process. Attorneys involved expect to complete paperwork to finalize the state permit revocation by July 30.
Memphis activists push ordinances to protect community against future oil pipelines – — The fight against the Byhalia Pipeline may be over, but a group wants to ensure the company behind it can never come back to Memphis and try to build one. The group, Memphis Community Against the Pipeline, is calling on the Memphis City Council to act and set limits on what companies like them can do in the future. It’s a fight that hasn’t ended for many. Representatives for MCAP, Protect Our Aquifer, Southern Alliance for Clean Energy and Center for Transforming Communities met at the National Civil Rights Museum where they, along with supporters, listened to passionate speeches about why the ordinances are necessary. That was followed by a walk to city hall, where that vote will be taking place. One ordinance sets a 1,500-foot distance between any potential pipeline and a residential neighborhood, and the other creates an infrastructure review board. The Byhalia Pipeline has been abandoned by Plains All American, the company that sought to construct the pipeline, but supporters said they felt the company could come back and try again. The votes were scheduled to take place at the city council’s regularly scheduled meeting.
Ordinances protecting Memphis water, sewer approved on first reading (WMC) - There was a show of support in downtown Memphis Tuesday for the protection of Memphis water and beyond. Members of Memphis Community Against the Pipeline (MCAP), Protect Our Aquifer, Southern Alliance for Clean Energy, and Center for Transforming Communities marched from the National Civil Rights Museum to City Hall. They were demonstrating ahead of a vote on two ordinances affecting Memphis water. “So, these two ordinances would provide that protection to ensure that our most vulnerable communities and our drinking water supply are safe from crude oil infrastructure,” said Sarah Houston, executive director of Protect Our Aquifer. One ordinance updates requirements for industrial users of the city’s sewer system to meet federal and state regulations, and protects the city’s sewer collection system. The other ordinance further protects the Memphis Sand Aquifer, where we get our drinking water. Both ordinances were approved Tuesday.
Gulf of Mexico Player May Exit Oil and Gas Industry -- BHP Group is considering getting out of oil and gas in a multibillion-dollar exit that would accelerate its retreat from fossil fuels, according to people familiar with the matter. The world’s biggest miner is reviewing its petroleum business and considering options including a trade sale, said the people, who asked not to be identified as the talks are private. The business, which is forecast to earn more than $2 billion this year, could be worth an estimated $15 billion or more, one of the people said. BHP’s energy assets make it an outlier among the world’s biggest miners -- rival Anglo American Plc has already exited thermal coal under investor pressure and BHP is trying to follow suit. The company has long said the oil business was one of its strategic pillars and argued that it will make money for at least another decade. But as the world tries to shift away from fossil fuels, BHP wants to avoid getting stuck with assets that more become more difficult to sell, the people said. The deliberations are still at an early stage and no final decision has been made, the people said. A spokesman for BHP declined to comment. The move comes as oil supermajors grapple with how to respond to investor pressure over climate, in some cases by shrinking their core production and adding renewable energy assets. BHP wants to exit while it can still get a good price for the assets, aiming to repeat a 2018 sale of its shale business to BP Plc for $10.4 billion, the people said. And unlike big-oil rivals, BHP doesn’t depend on profits from the energy business, which are dwarfed by the company’s giant iron ore and copper units. The timing could be good for an oil exit. The economic recovery from Covid-19 has transformed the fortunes of oil producers, with Brent oil futures having rallied about 60% in the past year. By contrast, the company’s efforts to get out of thermal coal so far have been disappointing, after early bids for mines in Australia came in lower than the company’s own valuations last year. Getting out of both thermal coal and petroleum would help BHP make its case to investors as a company geared toward commodities of the future. The miner is also expected to sanction a giant potash mine in Canada next month, which could make it a key supplier of the crop nutrient once production begins. BHP is scheduled to report annual results on Aug. 17.
Halted Texas Plastics Project May Resume-- Motiva Enterprises LLC is eying the revival of a multibillion-dollar expansion project at its Texas Gulf Coast refinery in 2023 that would produce petrochemicals used to make everything from plastic water bottles to grocery bags. Engineering and excavation work had already been done before the project was halted nearly two years ago. Now, Saudi Aramco’s U.S. refining arm is considering reactivating the expansion, minus an ethane cracker, which it no longer needs, according to people familiar with the plans, who asked not to be identified because the information isn’t public. Motiva originally intended to construct an ethane cracker that produces ethylene, a key component for making plastics and solvents, as well as other downstream units to process the ethylene. The refiner suspended the project when it bought the adjacent Flint Hills Resources LLC’s chemical plant in late 2019, which gave it an ethane cracker, but not all the downstream units needed to turn the ethylene into plastics and other products. Motiva is re-evaluating the massive expansion in Texas as consumption of plastics skyrockets. Oil majors including Exxon Mobil Corp. and Royal Dutch Shell Plc are making more money from their petrochemical operations than they have in years. Supply disruptions and pandemic-related demand has bolstered the need for construction, manufacturing and consumer products that heavily rely on the processing of chemicals like ethylene. Ethylene, which traded at a seven-year high of 59.5 cents a pound in March, is down from the highs but trended upward recently. The spot price Friday was at 52.5 cents a pound, up 11 cents from the prior week, according to ICIS, a data and analytics provider. An alternative plan in discussion for Port Arthur involves Motiva buying another chemical facility in the area that would give it access to downstream process units without having to build them. Motiva has been sending the ethylene from its ethane cracker to local chemical plants for further processing or selling the ethylene outright. The value of the original project was estimated at $6.6 billion in 2018, according to local media reports, citing information from the Texas Comptroller’s office. The majority of the value was for building the ethane cracker, estimated at about $4.7 billion. Motiva’s 607,000 barrel-a-day refinery in Port Arthur, Texas, is the largest in the U.S. Its corporate offices are in Houston.
Keystone XL - Lite -- Flipping The Capline -- July 19, 2021 - An answer to the Keystone XL that was killed? Remember, the whole purpose of the Keystone XL pipeline (and other pipelines from the north, flowing south) was to bring heavier oil from Canada to the US refineries along the Texas-Louisiana gulf coast to "balance out" all that light WTI oil arriving at refineries configured to handle heavier oil. Re-posting from earlier this morning: RBN Energy: the St James crude oil hub readies for Capline-related changes, part 3. Archived.In just a few months, heavy crude from Western Canada will start flowing south on the Capline pipeline from the Patoka, IL, hub to the one at St. James, LA. While the initial volumes will be modest, Capline’s long-awaited reversal will provide Louisiana refineries and export terminals with easier, lower-cost access to oil sands and other Alberta production. Flipping the pipeline’s direction of flow also means more changes for the St. James storage and distribution hub — one of the U.S.’s largest — which has already seen more than its share of evolution during the Shale Era. Today, we continue our Capline/St. James blog series with a look at St. James’s terminals and pipelines, the Louisiana refineries they supply, and the changes coming with the Capline reversal. The obvious question is this: how does western Canadian oil sands oil get to Patoka. From RBN Energy(archived here; not-accessible to readers): There are five pipelines flowing into Patoka with a combined capacity of just over 2 MMb/d:
- MPLX’s 454-Mb/d Woodpat Pipeline, which receives crude oil from two upstream pipelines — MPLX’s 360-Mb/d Ozark Pipeline from Cushing and Enbridge’s 145-Mb/d Platte Pipeline from Casper and Guernsey, WY. The Platte Pipeline transports heavy Western Canadian crude fed into it by the Express Pipeline as well as light crude produced in the Bakken, the Powder River Basin, and the Denver-Julesburg (DJ) Basin.
- TC Energy’s 590-Mb/d Keystone Pipeline — not to be confused with the company’s now-deadKeystone XL — which runs from Hardisty, AB, to Steele City, NE; from there, one spur of the pipeline heads east to Wood River and Patoka and the other heads to the Cushing hub, where it connects to TC Energy’s Marketlink Pipeline to the Gulf Coast.
- The 570-Mb/d Dakota Access Pipeline (DAPL), which runs from the Bakken to Patoka and which is co-owned by Energy Transfer (with a ~36% share), Enbridge (with ~28%), Phillips 66 (with 25%), MPLX (with ~9%), and ExxonMobil (with ~2%). DAPL is part of the Bakken Pipeline System, which also includes the 742-mile Energy Transfer Crude Oil Pipeline (ETCOP; mustard line) from Patoka to Nederland, TX. (Our most recent review of DAPL was Don’t Wanna Lose You in February, 2021.)
- Enbridge and MPLX’s 300-Mb/d Southern Access Extension Pipeline, a 168-mile connector between Flanagan, IL, and Patoka that receives Western Canadian crude oil from Enbridge’s 900-Mb/d Southern Access Pipeline (light purple line), which is part of Enbridge’s 2.9-MMb/d Mainline system. (Enbridge holds a 65% ownership interest in Southern Access Extension and MPLX holds 35%.)
- ExxonMobil and Enbridge’s 100-Mb/d Mustang Pipeline, which runs from Lockport, IL (a suburb of Chicago) to Patoka. (ExxonMobil has a 70% stake in Mustang and Enbridge has a 30% stake.)
Analysis Shows Oil and Gas Execs Using More Environmental Buzzwords-- The world’s biggest oil and gas companies are more likely to talk to Wall Street about emissions than how their businesses might grow. That, at least, is according to a Bloomberg analysis of conference calls for the world’s 25 biggest fossil fuel producers including Exxon Mobil Corp. and Gazprom PJSC. The data shows how environmental buzzwords and key phrases such as “carbon”, “climate change” and “renewables” are finding its way into conversations with analysts and investors like never before. The trend suggests that management teams, at least publicly, are increasingly engaged on the topic. They’re coming under mounting pressure from investors and environmentalists to come up with a plan to slash greenhouse-gas emissions and prepare for a low-carbon future. That push comes as the world’s largest economies aim to accelerate a shift from more polluting hydrocarbons to cleaner energy sources. Beyond the dialog, how far those companies have gone in terms of concrete steps to tackle environmental, social and governance issues — particularly the “E” in ESG — varies and is the subject of much contention. While energy giants such as BP Plc and Royal Dutch Shell Plc have set targets for net zero carbon emissions by 2050, most of their peers are lagging to varying degrees. When it comes to ESG, it remains to be seen if the energy industry can do more than just talk. “The fact that they are feeling the pressure shows that there is going to be more pressure to have that lip service and the potential for greenwashing.” Investors who dialed in to company conference calls of fossil-fuel giants this year heard the word “carbon” uttered 800 times, exceeding the 790 mentions of “growth” for the first time ever. References to words tied to energy transition so far this year have already outnumbered those for all of 2020. The terms “carbon”, “methane”, “climate change”, “renewables” and “emission” have been said more times in calls this year than in any of the years going back to 2013. References to “net zero” emissions targets surfaced in calls held by 21 of the companies analyzed. The Bloomberg analysis is based on a search of words related to ESG issues in transcripts of quarterly earnings calls and other investor events from the largest energy companies that regularly hold calls in English. . Carbon capture and sequestration, a costly technology climate scientists have long considered an essential component of meeting emission-reduction targets, has also emerged as a hot topic. It was cited more than 160 times this year -- three times more than in 2020 -- in calls of companies including Equinor ASA and Ecopetrol SA. Fossil-fuel companies are increasingly touting their plans on emerging clean-energy technologies.
After Kelcy Warren’s Energy Transfer Partners Made Billions from the Deadly Texas Blackouts, He Gave $1 Million to Greg Abbott - The Texas electric grid collapse during the February winter storm killed hundreds of Texans and caused an estimated $295 billion in damages, while generating seismic gains for a small and powerful few. The natural gas industry was by far the biggest winner, collecting $11 billion in profit by selling fuel at unprecedented prices to desperate power generators and utilities during the state’s energy crisis. No one won bigger than Dallas pipeline tycoon Kelcy Warren: Energy Transfer Partners—the energy empire Warren founded and now is executive chairman of—raked in $2.4 billionduring the blackouts.That immense bounty soon trickled down to Governor Greg Abbott. On June 23, Warren cut a check to Abbott’s campaign for $1 million, according to the governor’s latest campaign finance filing, which covers January through June. That’s four times more than the $250,000 checks that the billionaire has given to Abbott in prior years—and the most he’s ever given to a state politician in Texas.In the months after one of the worst energy disasters in U.S. history, Abbott has dutifully steered scrutiny away from his patrons in the oil and gas industry. Last month, the governor signed into law a series of bills that strengthened regulation of the state’s grid. But experts warned that lawmakers didn’t go far enough to prevent another grid failure and failed to crack down on natural gas companies. At a bill signing ceremony on June 8, Abbott proclaimed that “everything that needed to be done was done to fix the power grid in Texas.” The unusually large contribution from the blackout’s biggest profiteer raises questions about Warren’s influence over the governor and has prompted outrage at what many see as a blatant political kickback for kowtowing to the powerful natural gas industry.“When Governor Abbott said that we did everything we needed to do to fix the grid, what he meant was we did everything we needed to do that doesn’t interfere with my cronies’ profit margins,” says Democratic state Representative Erin Zwiener, who chairs the House Climate, Environment, and Energy Caucus. The governor’s office and his campaign did not respond to emails requesting comment, nor did Energy Transfer Partners.
Victim’s family files $250M lawsuit over fatal natural-gas explosion in Collin County - The family of one of the victims of a fatal Collin County natural-gas explosion last month is suing over the blast, alleging that negligence led to the man’s death. Melissa Tarver, the widow of Deric Tarver, filed the wrongful-death lawsuit Friday in Dallas County, court records show. The lawsuit, which seeks damages in excess of $250 million, names Atmos Energy and Bobcat Contracting as defendants. Neither company immediately responded to a request for comment. Tarver, 35, was working at an Atmos facility in Farmersville, about 15 miles east of McKinney, on June 28 when an explosion killed him and another worker, 22-year-old Ethan Knight, and injured two others. The lawsuit says Atmos had hired Tarver’s employer, Fesco Petroleum, and Bobcat Contracting to use a pipeline inspection gauge — a “pig” — at the site to check on the condition of part of the pipeline. The pig is inserted into a trap at one end of the pipe segment and then propelled to a trap at the other end. In this case, Tarver was standing near the pipeline using a pushrod to manually move the pig. But, the lawsuit says, Bobcat’s contractors failed to ground at least one of the traps, resulting in a static discharge that ignited residual gas in the pipeline, causing an explosion that “ripped apart the fabric binding a young, blossoming family.” The lawsuit alleges that Atmos and Bobcat failed to ensure that Tarver had safe working conditions by neglecting to properly maintain the pipeline and failing to train employees about industry standards, among other omissions. That inaction amounts to gross negligence, according to the lawsuit. In a written statement, the Tarver family’s attorneys noted other natural-gas explosions involving Atmos, including a February 2018 blast in northwest Dallas that killed 12-year-old Linda “Michellita” Rogers. The Railroad Commission of Texas determined that Atmos failed to detect leaks leading up to that explosion and proposed a record $1.6 million fine. The company settled a lawsuit with the girl’s family for an undisclosed amount.
The U.S. Shale Revolution Has Surrendered to Reality - “Drill, baby, drill is gone forever.” That was the recent assessment of Saudi Prince Abdulaziz bin Salman of the American oil industry’s future potential. As Saudi Arabia’s energy minister, Prince Abdulaziz is one of the most influential voices in the global oil markets. Fortune termed it a “bold taunt,” and a warning to U.S. frackers to not increase oil production. The response by the U.S. producers — to shut up and take it — quietly confirms this reality. Shale oil’s era of growth appears to be over. The reason is that even as global oil demand and prices rise, the economics of the shale oil business model continue to not work. The U.S. shale industry has lost hundreds of billions of dollars in the past decade producing oil and selling it for less than it cost to produce.This was possible because despite the losses, investors kept giving the industry money. But now investors appear to have grown tired of losing money on U.S. shale companies and new lending to the industry has dropped dramatically.As reported this month by The Wall Street Journal, “capital markets showed little interest in funding expansive new drilling campaigns” for the U.S. shale industry. Shaia Hosseinzadeh, a partner at investment firm OnyxPoint Global Management LP, told The Journal that the problem facing fracking companies is that “they can’t access cheap capital any longer.” Without new infusions of money, the industry can’t drill for more oil, and that is why the Saudis feel confident taunting the U.S. oil industry. Prince Abdulaziz’s confidence is based in the financial realities of U.S. shale.What’s happening with the U.S. shale industry in this high price oil environment is unusual. Oil is typically a very predictable boom-and-bust business: When prices go up, oil drillers produce as much as they can, and when prices go down they stop.But for American drillers right now, the money isn’t there because investors no longer are willingto lend to frackers based on promises of future profits that have yet to materialize for the industry. In July 2020, accounting firm DeLoitte released a report stating that, “The U.S. shale industry registered net negative free cash flows of $300 billion, impaired more than $450 billion of invested capital, and saw more than 190 bankruptcies since 2010” — supporting the claim that the industry has peaked without ever making money.Investors have taken notice, including the private equity industry that has invested heavily in the fracking boom. Dan Pickering, head of energy investment firm Pickering Energy Partners, highlighted how private equity has lost interest in further investment in the shale industry in his keynote presentation at Hart Energy’s annual Energy Capital Conference in June. The U.S. shale industry has been accurately described as being composed of “capital destruction machines”. The hundreds of billions in losses the industry has accumulated in the past decade prove that it’s true. With few investors willing to provide new capital to feed the machine, the only option is not drilling, even though prices are the highest they have been in years, at nearly $75 per barrel.
Has OPEC finally won the war against shale oil? -- I have maintained for the past six years that a key goal of OPEC has been to so demoralize investors in shale oil that they stop sending money to the companies that drill for it. As I've written previously, I believe that OPEC's contest with the shale oil industry is "part of a broader strategy meant to maximize Saudi revenues as production in the kingdom hovers at an all-time high over the next decade before beginning a decline." It now appears that OPEC may have finally won its war against shale. Investment in shale oil companies has finally collapsed—even as oil prices levitate. It has been a long time coming. The industry would like you to believe that it is now showing "restraint" in its capital spending. But, to use a dieting analogy, there is a big difference between watching what you eat and having your jaw wired shut. The industry has experienced the equivalent of the latter in the capital markets. What has amazed all of us who watched this battle play out is that OPEC didn't win sooner. The relentless tolerance for losses among investors was beyond belief. And, when those investors returned in force after a brief vacation during the oil price bust in 2015, we skeptics grew concerned that rational thought had been eliminated from the universe. One estimate puts shale oil and gas industry losses at around $500 billion in the last five years. But the industry was losing money as a whole before that even when oil was above $100 per barrel early in the last decade. The problem is that shale oil is difficult and costly to extract and the technologies that enabled that extraction were never efficient enough to create widespread profitability.The problem from here forward is that most of the sweet spots in U.S. shale plays have been exploited. As the industry runs out of them and increasingly moves toward developing more difficult shale deposits, costs will rise—thus making it even more difficult to turn a profit on shale oil.There is an oil price that would certainly make shale deposits profitable. But that price is likely too high for the economy and consumers to bear without falling into a recession. That, it turns out, is the conundrum for the oil industry as a whole. The price band that is affordable to consumers in the long run no longer overlaps with the price band that will allow oil companies to exploit increasingly difficult-to-extract deposits. That may already be reflected in the fact that oil production worldwide peaked in November 2018, long before the pandemic began. Those of us who have been concerned about a near-term peak in world production are starting to believe that we've already passed it. It may turn out that all the hype over shale oil had people looking the wrong way when one of the most momentous developments in modern history was taking place in plain view.
Permian pipeline operators merge amid obstacles to market recovery - A pair of Permian Basin oil and gas midstream companies combined their resources in the fossil fuel basin spanning from southeast New Mexico into West Texas. Pipeline operator Plains All American and Oryx Midstream announced on July 13 that they planned to merge Permian assets to form a new joint venture Plains Oryx Permian. The deal would include all the two companies’ Permian Basin asset excluding Plains’ long-haul pipeline system and certain intra-basin terminals. More: Work continuing in New Mexico to reuse oil and gas wastewater in other sectors When finalized, Plains will own 65 percent of the joint venture with Oryx owning 35 percent, with Plains serving as operator. Oryx Chief Executive Officer Brett Wiggs said the deal would boost returns to investors while also expanding Oryx’s operations and increasing efficiency as it will combine acreage and infrastructure already operating adjacently. “This combination is a natural evolution of the Oryx growth story and perpetuates that commitment, creating the premier crude oil logistics system in the basin, increasing connectivity, enhancing reliability, and strengthening efficiencies for our customers,” Wiggs said. When the deal is complete, Plays Oryx Permian will have 5,500 miles of pipelines with a capacity of 6.8 million barrels per day, read a news release, bringing oil products to all major downstream markets. The system would sit on about 4.1 million dedicated acres in the region.
US oil, gas rig count jumps 24 to 604 amid recovery confidence from early Q2 calls - The US oil and gas rig count jumped 24 to 604 in the week ending July 23 Enverus said, as early second-quarter earnings calls from oil services framed a picture of an upturning oil industry, slightly looser 2022 upstream capital budgets and more activity to come. The Permian Basin accounted for nearly half the additions, leapfrogging 11 week on week to 259 rigs. The West Texas/Southeast New Mexico basin accounts for about 4.5 million b/d of oil production and nearly 18 Bcf/d of gas output. Analysts believe WTI oil prices at $70/b-plus since early June no doubt have helped push up the rig count, although experts always caution week-to-week gains may not necessarily mean anything. "Oil companies typically make these decisions quarter by quarter, so [the recent jump in rig counts] is likely a reaction to being in a new quarter, and we have had prices for several months that will obviously get good return rates on wells," said James Williams, founder and president of WTRG Economics. S&P Global Platts Analytics analyst Taylor Cavey said recent price strength is no doubt playing a role in producer behavior. "We continually ask ourselves whether or not they will break from the maintenance mode mindset or not," Cavey said. Cavey noted rig gains were slower at the start of July, when the rig count dropped 12 the first week of the month followed by a gain of four and 24 in the most recent week. "Month to date, we're at plus 18 compared to June, which is largely in line with our forecast," he said. While some operators may raise their spending slightly in second-half 2021, operators should largely stick to stated budgets, Cavey said. Apart from the Permian, most of the US' other largest basins saw smalls gains or losses. The Haynesville Shale of East Texas/Northwest Louisiana gained two rigs to 55, while the SCOOP-STACK (28 rigs) play of Oklahoma, the DJ Basin (14 rigs) of Colorado, and the Utica Shale (13 rigs) of mostly Ohio were all up by one rig apiece. The Marcellus Shale, largely sited in Pennsylvania, shed a rig leaving 32, while the Bakken Shale of North Dakota/Montana and the Eagle Ford Shale in South Texas were unchanged, leaving totals of 23 and 45, respectively.
Oil and gas: Policy should not impede industry regrowth from COVID-19 -Oil and gas industry leaders from New Mexico and Texas, representing the Permian Basin, maligned efforts by the administration of President Joe Biden they said could stymie oil and gas operations throughout the U.S. Some representatives of energy companies also worried Congress could impose higher taxes on domestic fossil fuels as it considered a $1.2 trillion infrastructure package that could include such a measure.Language for the bill was not available as of Tuesday, but groups representing energy companies already began making their case for policy that supported their bottom lines.The two states’ major oil and gas trade associations collaborated with the American Petroleum Institute (API) to release an economic impact study Tuesday intended to display the importance of oil and gas revenue and argued the industry would play a key role in economic recovery both on state and national levels. The New Mexico Oil and Gas Association (NMOGA) pointed to $18.8 billion added to the state’s gross domestic product (GDP) by oil and gas in 2019, the year before the U.S. was struck by the COVID-19 pandemic.That’s 17.9 percent of the state’s economy, per the study, supporting 46,000 direct jobs.The health crisis brought on a year of sinking oil and gas prices and stymied production throughout 2020, but the markets recovered this year as vaccines became widely available.NMOGA Chairman Leland Gould said the industry was essential to New Mexico’s economy as it hoped to rebuild after COVID-19 and that public policy should support the regrowth of oil and gas production. “Oil and natural gas are a big part of New Mexico’s economy and will continue to play a leading role in driving our state from recovery to prosperity,” he said. “New Mexico has enormous oil and natural gas potential, and we should continue to make this state a magnet for capital investment and job creation by prioritizing the development of these resources right here in our own backyard.” Gould said oil and gas in New Mexico contributed to public services like education and infrastructure not only in high-producing regions like the Permian Basin in the southeast corner of the state, but throughout New Mexico.
Kansas gas well that blew 100 feet high now fixed; complaints of illnesses, smell linger - Authorities said Friday that a natural gas well outside of Lyons that exploded during maintenance the day before is now safe and repaired. Local residents had complained of an odor and a lingering haze, but a Northern Natural Gas official said there is no danger to the public. The complaints of a noxious smell began after the underground storage well blew open after 3 p.m. Thursday southeast of Lyons, causing water and natural gas to fly up into the air. Area resident Jacob Voorhies said the natural gas well shot 100 feet in the air and left a haze that descended on the city Thursday night. By Friday morning, the haze seemed to lift, but a natural morning fog did linger, he said. “There was definitely a haze over the city and it wasn’t like fog,” he said. “It was something else. I think everyone says certain things for lawyers. I live a mile away and whenever you look across the street you could clearly see there was something in the air … I guarantee you walk around town and ask 80 people, all 80 people will say, ‘Yeah, there was something different last night.’” A company spokesperson said the initial rupture caused a mixture of natural gas and water molecules to rupture into the air, causing a haze that would have been visible from town. The amount of gas lost would be calculated during the company’s roughly three-week investigation into the leak, spokesperson Mike Loeffler said. Kansas Corporation Commission spokesperson Linda Berry said the multi-state operation would be investigated by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration. The organization did not reply to The Eagle, but Berry said she was told the organization is investigating. Loeffler said measurements taken near the edge of Lyons didn’t detect any levels of sulfur or natural gas. About people’s complaints of a smell, Loeffler said it is likely sulfur that forms in the Arbuckle Formation, where the well is located.
City, county leaders join calls to stop Enbridge pipeline projects in Minnesota, Wisconsin - Local leaders are drafting resolutions in support of people working to stop the expansion of Enbridge Energy pipelines that transport Canadian oil across Minnesota and Wisconsin. The Madison City Council is expected to vote on a resolution Tuesday in support of Indigenous sovereignty and calling on local, state and federal leaders to stop the reroute of Line 5 in northern Wisconsin and construction of Enbridge’s $2.9 billion Line 3 replacement in Minnesota. The resolution, which has 13 sponsors, notes that each of the lines crosses dozens of rivers, streams and wetlands, including the Mississippi River, and cites spills in 1991 and 2010 that leaked millions of gallons of oil into rivers. Dane County Board member Heidi Wegleitner said she plans to introduce a similar resolution later this week. Speaking at a send-off event Monday for several protestors heading to camps along the Line 3 pipeline route through northern Minnesota, Madison City Council President Syed Abbas said people in the United States are fortunate to have clean water. “We are blessed and we have to say thanks to the Indigenous community for that,” Abbas said. “We need to stand with them. We might tomorrow get to a similar situation where we don’t have clean water because of contamination.” Abbas added that extracting and burning the tar sands oil Enbridge transports through the lines is especially carbon-intensive and not in line with the city’s commitment to eliminating greenhouse gas emissions.
White House adviser Susan Rice divests from company building Midwest pipeline - The director of President Joe Biden's Domestic Policy Council, Susan Rice, has divested herself of millions of dollars' worth of holdings in a company that's leading a contentious pipeline project supported by the Biden administration.According to newly released financial disclosure reports and a White House official, Rice has liquidated nearly $2.7 million worth of shares she and her husband owned in Enbridge, a Canadian company building the Line 3 pipeline, which would carry hundreds of thousands of barrels of Canadian oil through Minnesota and Wisconsin. Last month, the Biden administration gave a public boost to the Trump-era pipeline project, calling for the dismissal of a court challenge brought by environmental groups seeking to protect Minnesota watershed and tribal lands from the pipeline.A certificate of divestiture issued by the Office of Government Ethics last week shows Rice's plans to sell holdings in more than three dozen companies and several investment funds that she and her family own -- assets currently worth a total of more than $30 million.Enbridge's stock price has been on an upward trend since November, and the value of Rice's holdings in the company has increased from roughly $2.4 million when she joined the Biden administration earlier this year to nearly $2.7 million as of Friday. It's unclear if Rice netted any capital gains from the sale of her Enbridge shares, but those who divest assets under a certificate of divestiture are allowed to defer taxes on capital gains.
Line 3 opponents seek restraining order against sheriff – Activists opposed to the Line 3 Pipeline project in northern Minnesota are asking a judge to issue a restraining order against Hubbard County, Sheriff Cory Aukes, and the local land commissioner.Winona LaDuke and Tara Houska claim that the sheriff has unlawfully blockaded access to a camp serving as a convergence space and home for Indigenous-led activities by water protectors. The activists say law enforcement formed riot lines and blockaded the only means of entry and exit to the camp.LaDuke and Houska say the actions are “an escalation of a months-long unlawful campaign of harassment, arrests, disruption, surveillance and baseless pullovers of Indigenous water protectors and land defenders and their allies who oppose the Line 3 pipeline expansion.” The lawsuit argues that the blockade is a violation of private property rights, including an easement covering the driveway to the property.
Water Activist Winona LaDuke And Others Arrested Near Park Rapids, MN - — Environmental activist Winona LaDuke is among a small group of people arrested at Shell River near Park Rapids. They were protesting work on the river for the Line 3 replacement project by Enbridge. Honor the Earth, of which LaDuke is executive director, says a total of seven women were zip-tied and taken into custody. Enbridge says work on the final portion of the pipeline in Minnesota is 70% complete. They are adjusting work plans to comply with a DNR order to suspend the use of some water sources due to low levels from the drought.
Winona LaDuke released from jail after three days amid Enbridge Line 3 protests - Ojibwe activist and former Green Party vice presidential candidate Winona LaDuke was released from jail Thursday after her arrest Monday while protesting construction of an oil pipeline in northern Minnesota.She and six other women were sitting together praying on an easement and protesting construction of the Enbridge Line 3 oil pipeline near Park Rapids at the Shell River — which the pipeline will cross in five places — when they were arrested for trespassing. She was transferred late Wednesday to the Aitkin County jail, while the other women were released from the Wadena County jail that day.“I think this is what you call the Enbridge way — make sure that hundreds of Minnesota citizens are put in jail so that they can steal 5 billion gallons of water and put the last tar sands pipeline in,” LaDuke said in an Instagram post after her release. Enbridge released a statement to the Reformer saying in part that “Police are responsible for public safety. Officers decide when protesters are breaking the law. Our first priority is the safety of all involved — our workers, men and women in law enforcement and the protestors themselves.” The protests that led to the arrests are just the latest direct action seeking to stop construction of the pipeline, which will replace an existing pipeline the company says is needed for safe transport of oil and rising demand. Local communities and construction trade unions say the 337-mile, $2.9 billion crude oil pipeline is a key source of economic vitality in struggling communities.So far, more than 500 people have been arrested during protests led by Ojibwe tribes and environmentalists, the activists say. LaDuke is charged with trespassing, harassment, two unlawful assembly misdemeanors and public nuisance and posted a $6,000 bond, according to court documents.
Minnesota Cop: Oil Pipeline Budget Boost Means New Guns - A FEW WEEKS before a controversial oil pipeline was approved for construction in his area, Aitkin County, Minnesota, Sheriff’s Deputy Aaron Cook bought a new assault rifle that cost $725. The purchase was part of an effort to standardize police weaponry, said Cook’s boss, the local sheriff, and was unrelated to the Line 3 pipeline being built by Enbridge. Cook himself, however, told the gun seller that Enbridge could play a role in boosting the agency’s arsenal. “Our budget took a hit last week, so that’s all we will be ordering for now,” the deputy said in a November 2020 email about his purchase. “I’m hoping the pipeline will give us an extra boost to next year’s budget, which should make it easy for me to propose an upgrade/trade to your rifles rather than a rebuild of our 8 Bushmasters” — a reference to another make of assault rifles. The email suggests that at least some law enforcement officers anticipate new policing resources if the pipeline, Enbridge’s Line 3, is completed. The document, obtained through a public records request, provides an elegant example of how everyday oil and gas investments make it all the harder for local economies to transition away from the fossil fuel industry. The deputy appeared to be describing a banal but lucrative benefit aligning local police interests with the oil pipeline: property taxes. “They clearly have a belief or awareness that there is a pot of gold should they succeed in stopping the water protectors from being able to stop Line 3,” said Mara Verheyden-Hilliard, director of the Partnership for Civil Justice Fund’s Center for Protest Law and Litigation and an attorney representing water protectors. “This deputy is obviously looking to line the county sheriff’s armory with this money.”
MDU Resources Subsidiary Begins Construction on ND Natural Gas Pipeline Project - WBI Energy, Inc., a subsidiary of MDU Resources Group, Inc. (NYSE: MDU), began construction this week on the North Bakken Expansion project in northwestern North Dakota. This natural gas pipeline expansion will have capacity to transport 250 million cubic feet of natural gas per day from the Bakken Formation. WBI Energy received a notice to proceed on July 8 from the Federal Energy Regulatory Commission, allowing construction to commence. "WBI Energy transports more than 50% of the natural gas produced from the Bakken. This project will bring WBI's total pipeline system capacity to more than 2.4 billion cubic feet per day while reducing natural gas flaring in the region by allowing producers to move more gas to market. Producers have reinforced their need for this additional capacity by committing to long-term transportation contracts with WBI," The North Bakken Expansion project includes construction of approximately 63 miles of 24-inch natural gas pipeline and 30 miles of 12-inch natural gas pipeline, as well as a new compressor station and additional associated infrastructure. It is estimated to cost $260 million and, during peak construction, is expected to employ up to 450 people. WBI Energy expects to have the pipeline in service by the end of the year.
Oil production flat in North Dakota due to worker shortage (AP) — Oil production is flat in North Dakota due to a workforce shortage as the industry recovers from the coronavirus pandemic. Companies say they are in need of workers to inject water, sand and chemicals down wells to crack open rock and release oil, a process known as hydraulic fracking. State Mineral Resources Director Lynn Helms said eight crews are currently working in North Dakota, down from at least 20 which would typically be working in the state at today's oil prices. “Most of these folks went to Texas where activity was still significantly higher than it was here, where they didn’t have winter and where there were jobs in their industry,” Helms tells the Bismarck Tribune. “It’s going to take higher pay and housing incentives and that sort of thing to get them here.” North Dakota’s oil production rose 4,000 barrels per day in May, a negligible increase. The state produced about 1 million barrels of oil per day in May, the latest month for which data is available. The fracking side of the industry is also experimenting with new techniques to reduce costs. One company is using saltwater to replace some of the freshwater used in the fracking process. The fluid is being transported several miles through a flat line hose tucked inside another hose to prevent leaks until it reaches a fracking site, Helms said.
Pipeline break spews 41,000 gallons of oilfield wastewater (AP) — Nearly 41,000 gallons of oilfield wastewater has spilled from a broken pipeline in western North Dakota, impacting an unknown amount of land, state regulators said Wednesday.The North Dakota Department of Environmental quality said Kansas-based Tallgrass Energy reported the produced water spill on Monday. The break occured about 6 1/2 miles south of Watford City.It was not immediately known what caused the leak to the 4-inch plastic composite pipeline. Agency officials were on scene Wednesday to oversee the cleanup and investigate the spill, said Karl Rockman, director of the department’s division of water quality.Rockman said the wastewater migrated at least a half-mile from the break in the pipeline and “varied in width along its path." Some of the water spilled in a dry drainage ditch that connects to Spring Creek, a tributary to the Little Missouri River.“There is no indication that drinking water sources were threatened,” Rockman said. “There are still questions about the full extent of (the spill).” Rockman said cleanup will involve excavating contaminated soil.Produced water is a mixture of saltwater and oil that can contain drilling chemicals. It’s a byproduct of oil and gas development. Brine is an unwanted byproduct of oil production and is considered an environmental hazard by the state. It is many times saltier than sea water and can easily kill vegetation exposed to it.
US regulator issues notice to Dakota Access pipeline over safety concerns (Reuters) — The U.S. Department of Transportation’s pipeline regulator on Thursday put the operator of the Dakota Access Pipeline (DAPL), Energy Transfer LP (ET.N), on notice for probable violations of safety regulations and proposed a civil penalty against it.The U.S. Pipeline and Hazardous Materials Safety Administration (PHMSA) notice listed probable violations ranging from the location of storm water drainage at six pipeline facilities and failure to follow assessment guidelines relating to possible incidents in sensitive areas where the pipeline operates.The PHMSA recommended a civil penalty of $93,200 against the company for the violations and said failure to correct the issues may result in further enforcement action.In June, a U.S. district court closed a long-running case against the DAPL, a 570,000-barrel-per-day pipeline out of North Dakota that travels under a Missouri River reservoir, but allowed for Native American tribes and other opponents of the line to file additional actions against it. read moreEnergy Transfer was not immediately available to comment.“An oil spill from this pipeline would be devastating to our drinking water supply and that of millions of people downstream, placing us all in harm’s way. That’s why we have opposed DAPL from the very beginning and fought its continued operation at every turn,” Standing Rock Sioux Tribe’s vice chairman, Ira Taken Alive, said in a statement issued on Thursday by Earthjustice group, which represents the tribe in the lawsuit.
Saltwater spills reported in McKenzie County Two saltwater spills occurred in McKenzie County this week, according to the North Dakota Department of Environmental Quality.Tallgrass Energy reported a spill from one of its pipelines on Monday. The company estimated 850 barrels or 35,700 gallons spilled, affecting private property about 7 miles south of Watford City, according to a report it filed with the state.Saltwater is known as produced water or brine in the oil fields, and it can render land infertile when it spills. It's a byproduct of oil production, typically transported by truck or pipeline from an oil well to a disposal site.Tallgrass has not determined what caused its spill. A lightning strike is to blame for a separate incident that caused a fire and 820 barrels or 34,440 gallons of saltwater to spill at a disposal site about 5 miles south of Keene on Tuesday, according to a report the site operator, Bullrock, made with the state.Both companies are working to clean up the spills. State investigators will continue to monitor those efforts.
Pipeline break and lightning strike cause brine spills – A brine spill occurred during a pipeline break about six and a half miles south of Watford City. Most recent estimates indicate 35,700 gallons of brine were released on private property. Operated by Tallgrass Energy, the company first discovered the spill on Monday. Brine or produced water is a byproduct of oil production. It is typically carried from an oil well by pipeline or truck to a disposal site where it is injected back into the ground for permanent storage. A brine spill also occurred Tuesday, resulting from a lightning strike at the Alfred Brown Saltwater Disposal owned by Bullrock, LLC, about five miles south of Keene. The North Dakota Department of Environmental Quality was notified of both incidents. Initial estimates indicate 34,440 gallons of brine were released at the Keene area site. The spill occurred on private agricultural property. At this time, no surface water was impacted. Personnel from the Environmental Quality Department will be on site to monitor the investigations and remediations.
Pad Fire North Of Keene, ND -- July 24, 2021 --Because I did not want to incorrectly identify a pad fire at the wrong location (and the operator by association), I pulled the original post regarding that pad fire off the blog. A reader had sent me a note saying the rig in the photo is a workover rig and would not show up on the NDIC map as a drilling rig. I thought it was a workover rig at the time I posted the original note and should have not gone further with trying to locate the pad based on that error. So, the original post has been pulled. [To complete the story, a reader went by the pad I identified in the original post and said there was no fire and there had been no fire at that site. The reader suggested where the pad was likely to be, but I won't post that until / unless confirmed by other sources..] Here are the photos again taken "north of Keene" and posted on Facebook. Apparently the photos were taken about 10:37 p.m., Thursday night, July 22, 2021.I searched the local newspapers for any oil fires in this area. I couldn't find the story Thursday night. But Friday night, via twitter, I found the story. The link is to The Bismarck Tribune (https://bismarcktribune.com/news/state-and-regional/crews-respond-to-fire-at-mckenzie-county-oil-well-site/article_c1f9e4be-5ec4-58c3-8a02-19f52622f290.html): The US Forest Service is monitroing an active fire on an oil well site just south of Lake Sakakawea in McKenzie County (and north of Keene, ND).No injuries had been reported, according to a news release from the Dakota Prairie Grasslands office. The fire was contained to the well pad and no surface grassland or groundwater resources were affected Friday evening. Response teams are working to manage the incident.The cause of the fire is under investigation. More at the link. So, we're at square one. The pad fire could be at any number of locations north of Keene, ND, and south of the lake.
Chevron fails to hit targets with giant CCS scheme at Gorgon LNG - Chevron is receiving heavy flak and potential fines for failing to meet emissions reduction targets at its troubled carbon capture and storage (CCS) scheme that forms a crucial element of the Gorgon liquefied natural gas (LNG) export project in Australia. Its partners include Shell and ExxonMobil. Yesterday, Chevron admitted that its CCS project, described by the US giant as the world’s largest, has failed to meet a five-year target for burying carbon dioxide (CO2) under Barrow Island off Western Australia. The Gorgon joint venture, which also includes Osaka Gas, Tokyo Gas and JERA, shipped its first LNG cargo in 2016. The $3 billion CCS project, which started operating in 2019 and about three years late, has been beset by technical difficulties. Peter Milne, a Perth-based industry analyst at Boiling Cold, wrote that “Gorgon has been in production for 5.5 years, but there has not been a single day when all elements of Gorgon’s CO2 injection system have worked at the same time.” Significantly, it is the world’s largest CCS project dedicated to cutting greenhouse gas emissions, not enhancing oil recovery. Worryingly, if Chevron, backed by Shell and ExxonMobil, cannot get CCS right more than a decade after the project was approved, then expectations of a massive global CCS rollout before 2050 look doubtful, warned Milne. Chevron, which operates the Gorgon LNG development, has not met the official requirement to capture and store at least 80% of the emissions generated over the first five years of the project, or around 4 million tonnes per year. The emissions reduction target formed a key part of the environmental approval process. The Western Australian environmental minister, Amber-Jade Sanderson, is now seeking an “explanation of how the company intends to address the issue.” An analysis last year suggested Chevron could face a bill of more than A$100 million ($73 million) if it is required to offset all emissions that breached its approval requirements. Chevron’s managing director in Australia, Mark Hatfield, said the company is working with the regulator on “making up the shortfall”, which he did not quantify. He added the company would release a public report on the issue later this year. Analysts believe that the report will likely find that the project only captured 30% of what it was supposed to.
Quebec Quashes Energie Saguenay LNG Terminal on Environmental Grounds - Quebec upheld its reputation as no-go territory for fossil fuel projects Wednesday by denying environmental approval for a US$10.6 billion liquefied natural gas (LNG) export plan. GNL Quebec’s proposed Energie Saguenay terminal and Gazoduq pipeline failed to prove it would cut global greenhouse gas emissions, provincial Environment Minister Benoit Charette said in announcing the rejection. The decision ended hope for LNG exports of Western Canadian gas from Canada’s Atlantic seaboard. Pieridae Energy Ltd. earlier this month shelved the only other active East Coast proposal — the US$10 billion Goldboro LNG project in Nova Scotia. The Quebec decision did not surprise the Alberta-based Canadian oil and gas industry, where the LNG plan’s fate is seen as just the latest example of a well-established pattern. Since 2016 Quebec banned hydraulic fracturing to tap Utica Shale gas and led opposition that aborted TC Energy Corp.’s C$16 billion (US$12.8 billion) Energy East plan for a cross-Canada oil pipeline. Charette said flaws in the GNL Quebec proposal emerged from a prolonged and hotly contested examination of potential project effects by the provincial Bureau d’audiences publiques sur l’environnement (BAPE). The case drew a protest avalanche from urban academics and environmental groups, leaving the LNG project supported only by small centers at the proposed terminal site 277 miles east of Montreal at the junction of the St. Lawrence and Saguenay Rivers. Only a week before the rejection decision GNL president Tony Le Verger indicated Energie Saguenay and Gazoduq were still live economic propositions. The Covid-19 pandemic inflicted a two-year construction delay. But GNL had a connection deal with TC’s national natural gas pipeline and an agreement with a European LNG import project, and was negotiating for supplies from Alberta and British Columbia. The French Canadian LNG plan’s sponsors in the United States — the Ruby Capital team of California entrepreneurs Jim Illich and Jim Breyer — launched GNL Quebec in 2014, well before all the province’s political parties turned cold on fossil fuel projects. The prevailing mood in Quebec shows in Charette’s full official title. He is ministère de l’Environnement et de la Lutte contre les changements climatiques – Minister of the Environment and the Struggle Against Climate Change. While fossil-fuel foes celebrated Charette’s announcement as a victory for global energy transition and climate change policies, the pro-development Montreal Economic Institute mourned the LNG project’s end as a loss for Quebec investment and employment.
US won't block completion of Russia's Nord Stream 2 pipeline - The Biden administration won't block the completion of Russia’s Nord Stream 2 pipeline and will announce an agreement with Germany on the natural gas line’s construction in the coming days, according to top officials. Reuters first reported Monday that the U.S. and Germany were close to reaching a deal following discussions among officials from both countries over continued U.S. concerns that the nearly complete pipeline would make Europe too heavily dependent on Russia for gas. The U.S. has also warned the pipeline could rid Ukraine of the transit fees on gas currently pumped in a pipeline through the country. President Biden and German Chancellor Angela Merkel were not able to reach a deal on the pipeline during their meeting at the White House last week in what was likely the outgoing German leader’s last official visit to D.C. The Wall Street Journal reported Tuesday that one source familiar with the discussions among top officials said a deal was expected to be unveiled in the coming days, with another person saying the announcement could come as early as Wednesday. When asked about the reports on Tuesday, White House press secretary Jen Psaki said that she expected “the State Department and others will have more on this soon.” Psaki told reporters in the White House press briefing that the administration following Biden’s meeting with Merkel “made clear that this was a point of discussion, and that the president was planning to have a discussion about the fact that we have ongoing concerns about how the project threatens European energy security, undermines Ukraine security and the security of our eastern flank NATO allies and partners.” “He had directed his team to work with her team to see how we can address those concerns, even as the pipeline was 90 percent finished when this administration took office,” she added. The pipeline, which is now roughly 98 percent complete, had been opposed by U.S. officials under the two previous presidential administrations.
U.S., Germany strike a deal to allow completion of controversial Russian Nord Stream 2 pipeline – The United States and Germany reached an agreement to allow completion of the $11 billion Nord Stream 2 pipeline, a thorny, long-standing point of contention between the otherwise stalwart allies. The agreement reached between Washington and Berlin, which was announced Wednesday, aims to invest more than 200 million euros in energy security in Ukraine as well as sustainable energy across Europe. "Should Russia attempt to use energy as a weapon or commit further aggressive acts against Ukraine, Germany will take action at the national level and press for effective measures at the European level, including sanctions to limit Russian export capabilities to Europe in the energy sector," a senior State Department official said on a call with reporters on Wednesday. The senior State Department official, who requested anonymity in order to discuss the agreement candidly, added the U.S. will also retain the prerogative of levying sanctions in case Russia uses energy as a tool of coercion. The official said the United States and Germany are "resolutely committed to the sovereignty and territorial integrity" of Ukraine and therefore, consulted closely with Kyiv on this matter. The unease surrounding the nearly complete Nord Stream 2 project, a sprawling undersea pipeline that will pump Russian gas directly into Germany, stems from Moscow's history of using the energy sector to gain leverage over Russia's neighbors, namely Ukraine. When completed, the undersea pipeline will span 764 miles from R ussia to Germany, making it one of the longest offshore gas pipelines in the world. Last month, the Kremlin said that only 62 miles of Nord Stream 2 were left to build.In May, the United States waived sanctions on the Swiss-based company Nord Stream 2 AG, which is running the pipeline project, and its German chief executive. The waiver gave Berlin and Washington three more months to reach an agreement on Nord Stream 2.. The agreement comes on the back of German Chancellor Angela Merkel's visit to the White House, the first by a European leader since Biden took office and likely her last trip to Washington after nearly 16 years at the helm of Europe's largest economy. Merkel, the first woman to lead Germany, has previously said she will step down after the September national elections. During a joint press conference at the White House, Merkel pledged to take a tough stance against Russia if Moscow misused the energy sector for political gains.
Estonian seaport hit by oil spill - In north-eastern Estonia, an oil spill has been found near the Baltic Sea Port of Sillamäe, Estonian public broadcaster ERR reports. On Sunday, July 18, the Estonian Police and Border Guard Board’s Maritime Surveillance Centre was notified of 20 or more litres of oil spilled into the Baltic Sea. The responsible services accessed the site with a drone and estimated the spill to have an area of 500×200 metres. The pollution is thought to have leaked from a tanker in the Port of Sillamäe. From Tallinn the anti-pollution ship General Kurvits with its crew has been sent to collect the oil and continues to work in the area on Monday, July 19. In a joint emergency operation, the Estonian Rescue Board, the Environment Board and the Estonian Police and Border Guard Board are working to clear the pollution from the Baltic Sea, ERR reports. Oil prices briefly reached $75 a barrel in 2018 but haven’t been consistently higher than that since 2014.According to the shale oil industry, these prices are well above what is needed to make a profit. But the industry isn’t drilling, and in areas like the Bakken shale play in North Dakota, production is actually falling.And yet, with prices above $70 a barrel, Bakken production is not increasing. The current rate of just above one million barrels a day is down 26 percent from the 2019 peak of almost 1.5 million barrels per day.As DeSmog has recently documented, the challenges facing this region’s oil producers mean that “Bakken’s best days are a thing of the past.”
Halliburton Wins 7-Year Oman Contract - A large international oil company (IOC) in Oman has awarded Halliburton Co. (NYSE: HAL) a seven-year contract to provide production chemicals and associated services, Halliburton reported Wednesday.Without identifying the customer, Halliburton noted in a written statement that it will supply the IOC with customized products and specialized services to support in-field chemical treatments. “This collaboration aims to improve operational efficiencies and reliability by applying tailored solutions and close alignment between parties.” Halliburton stated that its facilities in Oman will support the project. The service company added that it will manufacture key raw materials for the contract’s portfolio at its new Halliburton Saudi Chemical Reaction Plant. The facility, which opens late this year, will boast capabilities to manufacture various chemicals for stimulation, production, midstream, and downstream engineered treatment programs, the firm explained. Halliburton also pointed out that it expects to hire and develop local personnel to deliver the Oman contract’s scope of work.
Halliburton Readies for Years of Expansion -- For the first time in seven years, Halliburton Co., the biggest provider of fracking services, is expanding in both U.S. and foreign markets as spending recovers in the global energy industry. “The economy feels more than 2% shut in, so the demand growth is there,” Chief Executive Officer Jeff Miller said Tuesday in an interview on Bloomberg TV. Drillers are “going to require a lot of services as we meet global demand for oil and gas.” Exploration customers are profitable at current oil prices in the $60-to-$70 range, he said. Their spending could increase by percentages in the double digits over the next couple of years as a result. The Houston-based contractor rose 5.8% Tuesday after reporting better-than-expected second-quarter earnings. The bullish outlook from the world’s No. 3 oil-services provider follows comments last month from its rival, Schlumberger, which said the global economic recovery will trigger an energy-industry “supercycle” that should lead to wider margins. That represents a dramatic rebound for the sector, which was laid low last year by the pandemic and forced to lay off tens of thousands of workers. The three biggest companies -- Halliburton, Schlumberger and Baker Hughes Inc. -- all report earnings this week and are expected to boost profits by at least 20% compared with the first three months of the year, according to an average of analysts’ estimates compiled by Bloomberg. Oil-services providers haven’t seen three straight quarters of share appreciation since the days of $100-a-barrel crude back in 2014. Now, as drilling accelerates around the world, the Philadelphia Oil Service Index is showing just that. Halliburton reported second-quarter earnings per share excluding one-time items of 26 cents, exceeding the 23-cent average of analysts’ estimates, while revenue of $3.7 billion trailed the $3.75 billion average. Halliburton reported its largest North American quarterly sales since the onset of the pandemic last year. Miller, who slashed more than $1 billion in costs during the downturn, reaffirmed an outlook for double-digit year-on-year growth in international orders during the second half of this year.
State company defends UAE pipeline deal, says oil spill risks 'negligible' | The Times of Israel -The state-owned Europe Asia Pipeline Company on Monday dismissed concerns of opponents of its deal to pipe Gulf oil through Israel on the way to European markets, telling the High Court that a petition filed by green groups to declare the agreement invalid had “no factual foundation” and that a risk survey found the threat of environmental damage to be “negligible.”In the petition, submitted in May, three green organizations charged that the Memorandum of Understanding signed by the EAPC with the United Arab Emirates in October should be made null and void given that it was neither discussed nor approved by the government, nor opened for consultation with experts and the public.The accord provides for the EAPC to transfer crude oil and oil-related products from its Red Sea terminal in Eilat to its terminal in Ashkelon on the southern Mediterranean coast via a land-based pipeline that connects the two.It is opposed by the former and current environmental protection ministers, the Israel Nature and Parks Authority, the local coastal authorities, a forum of some 20 environmental organizations, scores of scientists and Eilat residents.The opposition is due in large part to the EAPC’s shoddy environmental record and numerous past leaks — it was responsible, seven years ago, for the largest environmental disaster in Israel’s history when one of its pipelines ruptured, sending some 1.3 million gallons of crude oil into the Evrona Nature Reserve in southern IsraelThere are also real fears for Eilat’s coral reefs, with impacts not only to the city’s tourism and employment sectors but also globally.In its response to the petition, the EAPC said it had commissioned a risk survey, which had shown that “severe damage leading to full loss of the entire content of a tanker or external damage to a tanker and significant loss of content” would only occur once every 366,300 years.The likelihood of leakage in a pipe carrying fuel to a ship was determined to be so low it would only occur once every 1,111 years, the company went on. “An insignificant spill,” which was not quantified, was likely to take place once every 24 years. If such a spill happened, said the EAPC, the leak would be pooled and “no environmental damage or marine pollution would be caused at all.”
Environmental Groups in Israel Rise in Opposition to the Eilat - Ashkelon Oil Pipeline -Several 'green' groups in Israel have banded together to oppose further development of the Eilat - Ashkelon pipeline, transporting Gulf oil through Israel on its way to European markets.In their petition before the Court, submitted this May, three green organizations charged that the Memorandum of Understanding signed by the European Asian Pipeline Company (EAPC) with the United Arab Emirates in October should be made null and void given that it was neither discussed nor approved by the government, nor opened for consultation with experts and the public.The accord provides for the EAPC to transfer crude oil and oil-related products from its Red Sea terminal in Eilat to its terminal in Ashkelon on the southern Mediterranean coast via a land-based pipeline that connects the two.Opposition is widespread among environmental organizations, scientists and residents of Eilat itself, as they recall EAPC's recent operational performance where one of its pipelines burst, sending 1.3 million gallons of crude into the Evrona Nature Reserve in southern Israel.The EAPC has set up an oil boom in Eilat, designed to catch any potential oil spill before it leaks more broadly into the sea. The company has also spent around $10 million on the purchase of vapor combustion units for its ports in Eilat and in Ashkelon to treat the vapors emitted from ships during loading, and is pouring an additional more-than-$10 million into upgrading the pipeline system in a project that will be completed this year. During the year, it will send a special robot through the pipes to pinpoint where local repairs might be needed.Every tanker that called at Eilat was insured for $100 million per event, it said. The company has maintained throughout the legal contest that any prospective oil spill, particularly in light of the preventive measures the company has been taken around Eilat, would be small and negligible.
Sleep-deprived workers at Shell’s Prelude FLNG make official complaint - Workers onboard Shell’s Prelude floating liquefied natural gas (FLNG) facility offshore Western Australia are complaining about occupational health and safety (OHS) breaches after being forced to work on only two to three hours of sleep.
New Report Reveals Top Retail Shipping Polluters - 
Assam: Oil leak from ONGC pipeline spills into farmland in Sivasagar -- Crude oil leaking from an underground pipeline of Oil and Natural Gas Corporation (ONGC) at Nazira in upper Assam‘s Sivasagar district has spilled over vast swathes of farmland affecting scores of farmers in the area. The breach occured in a pipeline at Borpathar which is located between two adjacent villages — Mesagarh and Molagaon — in the Nazira sub-division. Technical teams from the ONGC Nazira office has rushed to the area to locate and plug the leak. Huge quanity of crude oil has already spilled over and it has a risk of catching fire. So far, 20 bighas of paddy fields have been affected by the oil spill. Nazira sub-divisional officer (SDO) Sabyasachi Kashyap said the leakage was first spotted by farmers on Thursday evening and was brought to the notice of the administration on Friday.“We were informed about the oil leakage at around 10.30am. Immediately, we contacted the ONGC office and asked them to cut off the supply of crude oil through that pipeline. But already a huge quantity of crude oil had gushed out and spilled into the surrounding paddy fields. The pipeline passes under a vast 1,000-bigha field and out of that around 20 bighas have been affected. A thick and blackish layer of oil has formed above the paddy fields. We have been told that the pipeline was quite old. The leak may have occured due to regular wear and tear but we are not ruling out the possibility of sabotage by oil thieves,” Kashyap on Friday said.
Shell’s Niger Delta oil-spill case to be heard in UK courts - Anglo-Dutch supermajor Shell has run out of time to appeal a UK court ruling earlier this year which found that a five-year-old case on environmental pollution in the Niger Delta should be heard in the UK and not Nigeria. In February, Shell’s lawyers failed to convince the High Court in London over the jurisdictional argument that the trial would be better decided in Nigeria, although Shell was given leave to appeal but declined to so. Leigh Day, the London-based law firm representing the Ogale and Bille communities in the Niger Delta, said last week: "Unprecedented oil pollution claims against Royal Dutch Shell and its Nigerian subsidiary, Shell Petroleum Development Company (SPDC), will finally be heard in the High Court in London after the oil giant dropped its attempts to avoid English jurisdiction." By including the subsidiary in the UK proceedings, more documents about Shell’s work in Nigeria are likely to be made public, the law firm said. The High Court's February 2021 decision was grounded on the plaintiffs establishing an arguable case that the parent company should be treated as the anchor defendant, enabling the case to proceed to a judgment on civil law in the UK. The claimants have yet to demonstrate that Shell should be held responsible for events that took place in Nigeria, on the merits of the case, while they still need to prove that the supermajor owes a duty of care and that, critically, this was breached, according to a source with knowledge of the legal proceedings.
OPEC and allies target full end to oil production cuts by September 2022, increase supply as prices climb - — The Organization of Petroleum Exporting Countries (OPEC) and its non-OPEC allies reached a deal Sunday to phase out 5.8 million barrels per day of oil production cuts by September 2022 as prices of the commodity hit their highest levels in more than two years. Coordinated increases in oil supply from the group, known as OPEC+, will begin in August, OPEC announced in a statement. Overall production will increase by 400,000 barrels per day on a monthly basis from that point onward. The International Energy Agency estimates a 1.5 million barrel per day shortfall for the second half of this year, indicating a tight market despite the gradual OPEC supply boost. OPEC+ agreed in the spring of 2020 to cumulatively cut a historic nearly 10 million barrels per day of crude production as it faced a pandemic-induced crash in oil prices. The alliance gradually whittled down the cuts to about 5.8 million barrels per day. The 19th OPEC and non-OPEC ministerial meeting noted that worldwide oil demand showed "clear signs of improvement and OECD stocks falling, as the economic recovery continued in most parts of the world" thanks to accelerating vaccination programs. International benchmark Brent crude is up 43% year-to-date and up more than 60% from this time last year, with many forecasters expecting to see oil trading at $80 a barrel in the second half of 2021. Brent closed at $73.59 a barrel at the end of the trading day on Friday. The agreement followed a temporary but unprecedented gridlock that began in early July and saw the United Arab Emirates reject a coordinated oil production plan for the group spearheaded by its kingpin, Saudi Arabia. While the 13-member organization has seen disagreements before, this was the first public rift between the UAE and Saudi Arabia, which are close allies. Abu Dhabi had demanded that its own "baseline" for crude production — the maximum volume it's recognized by OPEC as being able to produce — be raised because this figure then determines the size of production cuts and quotas it must follow as per the group's output agreements. Members cut the same percentage from their baseline, so having a higher baseline would allow the UAE a greater production quota. Sunday's agreement revealed baseline increases for four of OPEC's member states and one non-OPEC state beginning in May of 2022: the UAE, Saudi Arabia, Iraq, Kuwait, and Russia, the last of which is not an OPEC member but a leader of OPEC+. The UAE's baseline for oil production will be raised from 3.16 million barrels per day to 3.5 million barrels per day, though short of the 3.8 million it reportedly initially requested. Saudi Arabia's baseline will be increased from 11 million to 11.5 million barrels per day.
Riyadh and Moscow claim biggest wins from OPEC+ deal - -- Saudi Arabia and Russia clinched a deal for an OPEC+ production increase by partly submitting to the United Arab Emirates’ demands for a more generous quota. But the compromise still leaves Riyadh and Moscow on top. Of all the adjustments agreed on Sunday to the cartel’s baselines -- the level from which each member’s cuts are measured -- the two largest OPEC+ members awarded themselves the biggest increases. While the UAE’s baseline will rise by about 330,000 barrels a day to 3.5 million in May 2022 -- a 10% increase -- Moscow and Riyadh’s will jump by 500,000 barrels a day to 11.5 million That may seem academic. Saudi Arabia has pumped that much only on the rarest of occasions, and the International Energy Agency sees Russia’s true capacity at 10.4 million barrels a day. Yet the generous headroom offered by these large numbers means the two countries will get back to pre-Covid output levels more quickly than fellow members, and keep going even higher if they are able. As early as November, Saudi Arabia is on track to restore production to March 2020 levels -- before the worst effects of the Covid-19 pandemic and before the price war that briefly pushed the kingdom’s output to a record. Russia will pass that milestone in April 2022, assuming the 400,000 barrel-a-day monthly production increases are shared out proportionally between the Organization of Petroleum Exporting Countries and its allies. By September 2022, when OPEC+ expects to have revived all of the oil production halted because of the pandemic, the UAE’s quota limit may still be pumping less than it did before the Covid-19 crisis. © 2021 Bloomberg L.P.
U.S. oil drops 7% to below $70 as OPEC prepares to boost production, Covid concerns weigh - West Texas Intermediate crude futures fell below the key $70 level Monday for the first time in more than a month as OPEC and its allies agreed to raise output, and as the delta Covid variant threatens global demand. U.S. oil dropped more than 7% to hit a session low of $66.35 for its biggest one-day decline since September 2020. The contract is now 13% below its recent high of $76.98 from July 6, which was the highest level in more than six years. International benchmark Brent crude slipped 6.7% to trade at $68.71 per barrel. The group of 23 nations, known as OPEC+, agreed Sunday to increase production by 400,000 barrels each month beginning in August. The output hike will continue through September 2022, at which point the entirety of the nearly 6 million barrels per day the group is still withholding will be back on the market. The announcement came after the group's initial meeting July 1 fell apart amid a disagreement between Saudi Arabia and the United Arab Emirates over the latter's baseline production quota. "We view [Sunday's] deal as supportive to our constructive oil price view with supply increasingly becoming the source of the bullish impulse and evidence of non-OPEC supply shortfalls likely in the coming months," Goldman Sachs said in a note to clients. The firm pointed to discipline among U.S. producers as providing a floor for oil prices, although it noted that the delta variant could lead to price gyrations in the coming weeks. OPEC+'s July meeting ending without an agreement sent the oil market into turmoil because it opened the door for the group to potentially disband, with each nation pursuing an independent production policy. "This was a renewal of OPEC+ vows," RBC's Helima Croft said Monday on CNBC's "Worldwide Exchange." "We think the market can absolutely absorb the additional 400,000 barrels per month...this is a constructive agreement." Despite Monday's downturn some Wall Street firms believe a tight market will continue to support prices. Credit Suisse raised its forecasts Sunday night and now sees Brent averaging $70 per barrel in 2021, up from a prior estimate of $66.50. The firm raised its WTI forecast to $67 for the year, up from $62. Citi, meanwhile, sees Brent and WTI climbing to $85 or higher this year. "The summer season for petroleum markets should be stronger than usual this year on pent-up leisure demand," the firm said in a note to clients. Even with Monday's drop, WTI is still up 38% for the year amid a recovery in demand as worldwide economies reopened, and as producers kept supply in check. In April 2020 OPEC+ implemented historic cuts of nearly 10 million barrels per day in an effort to support prices as demand for petroleum products plunged. WTI briefly traded in negative territory for the first time on record.
Just a speed bump? Oil has taken a dive, but Goldman is still bullish - A panic-induced sell-off in the oil market triggered by virus concerns has thrown the commodity's upward march into question — but energy experts at Goldman Sachs don't appear to be rattled. Fears over the surging delta coronavirus variant and a fresh supply boost agreement from OPEC+ sent oil prices tumbling down more than 7% as the trading week opened Monday. The drop was the steepest since March, a rude awakening for oil bulls who'd been enjoying the commodities' highest prices in 2½ years. International benchmark Brent crude was trading at $68.42 a barrel at 2:15 p.m. in London on Tuesday, down just over 7% from its Friday close of $73.59 a barrel. Oil analysts were quick to stress the uncertain road ahead for demand as new waves of Covid-19 infections ― many among communities that have high vaccination rates ― threaten the recent months of economic recovery. "The market is clearly unsettled about the demand outlook. And rightly so. The rise in delta variant cases is raising questions about the sustainability of demand," S But analysts at Goldman Sachs led by Senior Commodity Strategist Damien Courvalin see the current setback as merely a speedbump, with little concrete reason for oil bulls to be worried. Oil balances globally are tighter than they were before, despite the agreement between OPEC and its allies over the weekend to cumulatively increase crude production by 400,000 barrels a day on a monthly basis beginning in August. The International Energy Agency estimated a 1.5 million barrel per day shortfall for the second half of this year compared to its demand predictions in the absence of an OPEC supply deal. And Goldman predicts the impact from delta to be in the neighborhood of "a potential 1 mb/d (million barrels per day) hit for only a couple months, and even less if vaccines prove effective at lowering hospitalizations in DMs (developing markets), the origin of most summer demand improvements," as per its latest report. Goldman's call is in line with its previously bullish stance, which saw it forecasting Brent hitting $80 per barrel in the second half of this year.
Oil futures bounced back on Tuesday - Perhaps a little bit overdone to the downside, oil futures bounced back on Tuesday, erasing some of the panic selling seen on Monday after OPEC+ agreed to boost supplies, and as concern over the surging delta coronavirus variant increased. Despite today's modest bounce, oil investors remain cautious about buying the commodity given the demand picture has quickly turned cold as inflation hits economic growth and the coronavirus Delta variant becomes a bigger concern in the US and globally. The expiring August WTI contract added $1.00, or 1.5%, to settle at $67.42 a barrel, while the September contract tacked on 84 cents, or 1.3%, to settle at $67.20 a barrel. Brent for September delivery settled at $69.35 a barrel, up .73 cents, or 1.1%. August RBOB added 1% to $2.13 a gallon and August heating oil added 1.4% to $2.01 a gallon. Oil balances globally are tighter than they were before despite the agreement between OPEC and its allies over the weekend to cumulatively increase crude production by 400,000 barrels per day on a monthly basis beginning in August. This has worked to cool concerns tied to the spread of the delta variant of the coronavirus that causes COVID-19. The near future of this market will be closely tied to the spread of the virus, and unless it spreads like wildfire, prices should be able to gain momentum to the upside. At this point, this market may be lacking a support base and therefore, any rally may be short lived. Goldman Sachs expects Brent prices in the third quarter to average $75/barrel, down $5 from a previous estimate and $80/barrel in the fourth quarter, up from a previous forecast of $75/barrel. It forecast an oil deficit of 1.5 million bpd in the third quarter compared with a previous estimate of 1.9 million bpd and a deficit of 1.7 million bpd in the fourth quarter. The bank said oil prices may continue to gyrate in the coming weeks given the Delta variant uncertainties and the slow velocity of supply developments. It said the bottom-up estimate of the impact that a Delta wave could have on global oil demand points to a potential 1 million bpd hit for only a couple of months. It also stated that non-OPEC+ production outside of North America will surprise consensus to the downside in the coming months. Goldman Sachs also said that progress on a U.S.-Iran nuclear deal has stalled leading to increased risks that the potential increase in Iranian exports is later than its October base-case. RBC analysts said the timing of the OPEC meeting is a coincidence rather than a cause as prices fell 8% amid concerns about the COVID-19 delta variant.
WTI Tumbles After Surprise Crude Build -Oil prices rebounded modestly today but were far from able to reverse yesterday's bloodbathery as delta variant (demand) scares combined with OPEC+'s production deal (supply) dominated any equity-exuberance spillover affect with WTI unable to get back above $68.Behind the burst of volatility is a realization that vaccines won't prevent episodic flare-ups in infection and the introduction of measures to control new variants, according to Marwan Younes, chief investment officer at Massar Capital Management, a commodities-focused hedge fund.And the next driver of that vol will be tonight's inventory dataAPI
- Crude +806k (-5.4mm exp)
- Cushing -3.57mm
- Gasoline +3.31mm
- Distillates
Analysts expected a 9th straight weekly crude draw but were disappointed when API reported a 806k barrel build. Gasoline stocks also saw a decent build. WTI traded around $67.50 ahead of the print, and dived lower to a $66 handle after the surprise crude build...
WTI Shrugs Off Unexpectedly Large Crude Inventory Build -After the initial tumble last night - after API reported an unexpected build in crude inventories (and big build in gasoline stocks) - oil prices have surged higher overnight and across the US equity market open as all those Monday fears appear to be evaporating once again.“Risk-on is the main driver,” “I still believe oil fundamentals themselves are supportive, but the last 72 hours were primarily driven by shifts in investors’ attitude to risk.”Maybe this morning's official data will reignote some sense of fundamentals in the energy complex... however fleeting.DOE
- Crude +2.11mm (-3.7mm exp)
- Cushing -1.347mm
- Gasoline -121k (-1.0mm exp)
- Distillates -1.349mm
Analysts expected a 9th straight weekly draw in crude stocks, even after API reported an unexpected build, but were wrong when the official data showed an even bigger 2.11mm barrel increase. Gasoline stocks dropped very marginally, but not the build we saw in API data...Some have suggested the lack of a continued drop in gasoline demand is responsible for the market's refusal to drop on the crude build but the rise in demand is de minimus ...
U.S. oil prices up over 4% as inventories at Cushing decline to 18 month low - Oil futures posted a more than 4% gain on Wednesday, as a decline in crude stocks at the Cushing, Okla. storage hub to the lowest level since early 2020 provided support, outweighing any pressure from the first weekly U.S. crude inventory rise since mid-May.The Energy Information Administration reported on Wednesday that U.S. crude inventories rose by 2.1 million barrels for the week ended July 16, marking the first weekly rise in nine weeks. At 439.7 million barrels, crude supplies are about 7% below the five-year average for this time of year, the EIA said.On average, analysts polled by S&P Global Platts forecast a decline of 6.7 million barrels for crude stocks, while the American Petroleum Institute on Tuesday reported an 806,000 barrel increase.The EIA data also showed crude stocks at the Cushing, Okla., storage hub declined by 1.4 million barrels for the week to 36.7 million barrels. Stocks at the storage hub haven’t been this low since January 2020, EIA data show. .“We did see a big surprise surge of imports and that kept the market somewhat at bay but if you look at the draw in Cushing, Oklahoma, we’re getting to a dangerously low level,” “We’re almost out of oil at the Cushing delivery point if we continue to draw at this rate.”The market has been “draining” crude stocks in storage at Cushing at an “incredible pace — it’s unbelievable,” said Flynn. Stocks may fall “below the minimum operating levels for that storage point pretty soon.”West Texas Intermediate crude for September delivery rose $3.10, or 4.6%, to settle at $70.30 a barrel on the New York Mercantile Exchange, extending a 1.3% rise from Tuesday.September Brent crude, the global benchmark, gained $2.88, or nearly 4.2%, to settle at $72.23 a barrel on ICE Futures Europe.The EIA also reported that gasoline supplies edged down by 100,000 barrels, while distillate stockpiles fell by 1.3 million barrels for the week. The S&P Global Platts survey forecast a supply decrease of 1.1 million barrels for gasoline and 600,000 barrels for distillates.
Oil gains as demand recovery seen tightening supply -Oil prices inched up on Thursday, extending gains made in previous sessions on expectations of tighter supplies through 2021 as economies recover from the coronavirus crisis. Brent crude advanced $1.56, or 2.2%, to settle at $73.79 per barrel, after rising 4.2% in the previous session. U.S. West Texas Intermediate (WTI) crude added $1.61, or 2.3%, to settle at $71.91 per barrel, after gaining 4.6% on Wednesday. "Some soft spots have emerged in the oil demand recovery, but this is unlikely to change the outlook fundamentally," Morgan Stanley said in a note. Members of the Organization of the Petroleum Exporting Countries and other producers including Russia, collectively known as OPEC+, agreed this week on a deal to boost oil supply by 400,000 barrels per day from August to December to cool prices and meet growing demand. But as demand was still set to outstrip supply in the second half of the year, Morgan Stanley forecast that global benchmark Brent will trade in the mid to high-$70s per barrel for the remainder of 2021. "In the end, the global GDP (gross domestic product) recovery will likely remain on track, inventory data continues to be encouraging, our balances show tightness in H2 and we expect OPEC to remain cohesive," it said. Crude inventories in the United States, the world's top oil consumer, rose unexpectedly by 2.1 million barrels last week to 439.7 million barrels, up for the first time since May, U.S. Energy Information Administration data showed. Inventories at the Cushing, Oklahoma crude storage hub and delivery point for WTI, however, has plunged for six continuous weeks, and hit their lowest since January 2020 last week. "Supplies fell further by 1.3 million barrels to lowest level since early last year, theoretically offering support to the WTI curve," said Jim Ritterbusch of Ritterbusch and Associates. Barclays analysts also expected a faster-than-expected draw in global oil inventories to pre-pandemic levels, prompting the bank to raise its 2021 oil price forecast by $3 to $5 to average $69 a barrel. "Notwithstanding the tail risks, supply-demand dynamics point to a slow grind higher in prices over the next few months," Barclays said in a report.
Oil prices move up to end the volatile week with a modest gain - -Oil futures moved up on Friday, with gains for a fourth-straight session allowing prices to rebound from the lowest settlements since May after a sharp drop on Monday."Traders were uncertain as to whether the OPEC+ agreement was bullish, representing continued cohesion, or bearish, signaling more oil on the market," Michael Lynch, president at Strategic Energy & Economic Research, told MarketWatch. The Organization of the Petroleum Exporting Countries and their allies, together known as OPEC+, decided on Sunday to gradually increase production levels each month starting in August.Meanwhile, the spread of coronavirus delta variant is "seemingly bearish, but the demand data, at least for the U.S., remains bullish," said Lynch. That "gives you a price on the seesaw."West Texas Intermediate crude for September delivery rose 16 cents, or 0.2%, to settle at $72.07 a barrel on the New York Mercantile Exchange. That led the U.S. benchmark up by 0.7% for the week, based on the front-month contract, according to Dow Jones Market Data.September Brent crude , the global benchmark, added 31 cents, or 0.4%, at $74.10 a barrel on ICE Futures Europe, leaving it with a 0.7% climb for the week.Oil prices had plunged in the early part of the week on "concerns that rising global delta variant infection rates could undermine the economic rebound," or slow it down, said Michael Hewson, chief market analyst at CMC Markets UK.These worries haven't gone away, but even with the new OPEC+ agreement, there are still "residual concerns" that the market "could see supply struggle to keep up with demand, hence the recovery in prices heading into the weekend," he said in a market update.Crude plunged Monday, with WTI dropping more than 7%, in a broad selloff (link) that was attributed in part to worries about the spread of the delta variant of the coronavirus and it's impact on energy demand. Crude and other assets, including equities, subsequently bounced back as investors proved eager to buy the dip.The market's rebound "confirms our hypothesis that the selloff was ultimately sparked by external factors," said Eugen Weinberg, commodity analyst at Commerzbank, in a note.Weinberg said it also backs up the expectation that the OPEC+ agreement to add 400,000 barrels a day each month to output as it unwinds production curbs will prevent a repeat of last year's breakdown in the cartel."The supply situation remains tight, while the agreement underlines the unity of OPEC+, and the response of non-OPEC+ producers so far to the significantly higher prices leaves much to be desired," he wrote. "This suggests that OPEC+ will maintain its 'pricing power,' which will lead to high prices."Data from the Energy Information Administration released Wednesday revealed (link) a weekly increase in U.S. crude supplies, following eight-straight weeks of declines, but stocks at the nation's storage hub at Cushing, Okla. fell to their lowest since January 2020.Baker Hughes (BKR), meanwhile, reported on Friday that the number of active U.S. rigs drilling for oil (link) climbed for a fourth week in a row, implying an production increase ahead.
Oil Prices Edge Upward for the Week -- Oil squeezed out its first weekly gain in three on signs that global demand is holding up despite concerns that the renewed spread of the virus could stall the recovery. Futures in New York rose 0.2% this week, completely recouping a selloff on Monday that was stoked by the rapidly spreading delta variant. Fuel demand and road traffic from the U.S. to Asia and Europe remains resilient, underscoring expectations that the recovery hasn’t been derailed and global inventories will continue to shrink. “The fact of the matter is that we’re not going to see, at least in the U.S. and in Europe, a massive return to strict lockdown,” said Ed Moya, senior market analyst at Oanda Corp. Crude has rallied nearly 50% this year as ongoing vaccination campaigns have propelled reopenings. Data this week showed gasoline demand is essentially back to normal in many of the biggest consuming countries. Meanwhile, OPEC+ and U.S. shale producers have shown discipline in returning shuttered supplies to the market. The 7.5% price slump on Monday came just a day after the Organization of Petroleum Exporting Countries and its allies led by Saudi Arabia and Russia finalized an agreement to gradually restore production they halted during the pandemic. OPEC+’s modest increase eased fears around concerns of oversupply. “Everybody thinks they are going to flood the market, and then they take a step back and realize that, hey, they’re adding because the supply is being burned off,” said Phil Streible, chief market strategist at Blue Line Futures LLC in Chicago. The recent dip in prices is a buying opportunity and Brent prices should hit $100 per barrel next year, said a group of analysts at Bank of America Corp. in a recent note to clients. West Texas Intermediate crude for September delivery added 16 cents to settle at $72.07 a barrel in New York. Brent for the same month rose 31 cents to end session at $74.10 a barrel. This week, Schlumberger and Baker Hughes Inc. suggested the rebound in the U.S. shale patch will likely slow this year as companies keep a lid on spending. Despite a strong recovery in crude prices in 2021, the shale industry is largely resisting adding new supply.
Iran opens new oil terminal in bid to bypass crucial Strait of Hormuz for exports– Iran on Thursday opened its first oil terminal in the Gulf of Oman, a move aimed at making Iranian President Hassan Rouhani's regime less dependent on the Strait of Hormuz, often a source of international tension. The location of the new oil terminal — a project that began in 2019 and will cost some $2 billion — will also reduce transportation and insurance expenses for oil tankers. "This is a strategic move and an important step for Iran. It will secure the continuation of our oil exports," Rouhani said in a televised speech, according to state-run media. The Strait of Hormuz, a crucial channel located between the Persian Gulf and the Gulf of Oman, is used by oil producers to transport crude from the Middle East. Approximately 20% of the world's crude oil passes through the waterway. The new terminal gives Iran more space to operate. The Strait of Hormuz is a narrow strip of water between Iran and the United Arab Emirates that connects the Persian Gulf to more open waters. The new terminal is to the east on the wider Gulf of Oman, which opens into the vast Arabian Sea. Iran has previously threatened to close the strait in response to Trump administration's decision to reimpose sanctions. "This new crude export terminal shows the failure of Washington's sanctions on Iran," Rouhani said, adding that Iran plans to export 1 million barrels per day of oil. Washington placed sanctions on Tehran after former then-President Donald Trump withdrew from the Joint Comprehensive Plan of Action, or JCPOA, nuclear agreement in 2018. The JCPOA, brokered by the Obama administration in 2015, lifted sanctions on Iran that had hampered its economy and cut its oil exports roughly in half. In exchange for billions of dollars in sanctions relief, Iran agreed to dismantle some of its nuclear programs and open its facilities to more extensive international inspections.
Pentagon carries out first air strike in Somalia under Biden - The U.S. military on Tuesday conducted an air strike against an al-Qaeda-affiliated group in Somalia, the first such strike in the country since President Biden took office, multiple outlets have reported.The strike on the al-Shabaab militant group, first reported by Agence France-Presse, took place “in the vicinity of Galkayo, Somalia,” about 430 miles northeast of Mogadishu, Pentagon spokeswoman Cindi King said in a statement to the outlet.U.S. Africa Command (AFRICOM) carried out the single air strike in coordination with the Somali government.“A battle-damage assessment is still pending due to the ongoing engagement between al-Shabaab and Somali forces, however, the command's initial assessment is that no civilians were injured or killed as a result of this strike,” King added.The Somali government also confirmed the strike in a statement, noting that it occurred at 11:05 a.m. local time in the Galmudug State of the country “to protect the brave commandos of the Somali National Army.”The government did not say who carried out the action.The Pentagon did not respond to a request for comment from The Hill."The last U.S. air strike in Somalia took place on Jan. 19, one day before President Biden entered the White HouseFollowing Biden’s inauguration, he initiated a review of the policy on drone strikes and commando raids outside of conventional war zones and imposed temporary limits on such strikes.The move came after former President Donald Trump had loosened the rules for drone strikes when he was in office.Pentagon s pokesman John Kirby then told reporters in March that any planned strikes outside Afghanistan, Syria and Iraq had to be submitted to the White House “to ensure that the president has full visibility on proposed significant actions.”
US launches airstrikes against Taliban as Afghan forces crumble - US warplanes carried out at least four sets of airstrikes in Afghanistan this week in support of Afghan government troops who have ceded ever-growing swathes of the country to the Taliban Islamist insurgency. The Pentagon acknowledged the bombing raids, which took place on Wednesday and Thursday, but refused to provide any details as to the aircraft or munitions involved. The targets struck were in southern Kandahar province, the historic stronghold of the Taliban, and in Kunduz in the north. Among the targets were materiel captured by the Taliban from government forces, including at least one piece of artillery and armored vehicles, Pentagon officials said. In both Kunduz and Kandahar, the security forces of Afghanistan’s puppet government are facing increasing pressure from Taliban on their respective provincial capitals. In a Pentagon press conference on Wednesday, the chairman of the Joint Chiefs of Staff, Gen. Mark Milley, provided a confirmation of the breadth and speed of the Taliban’s advances, acknowledging that the insurgency had seized about half of the country’s 419 district centers. Just last month, he told Congress that the Taliban held only 81 centers. This official count is no doubt a significant underestimate. And, in many cases, district centers still held by the government forces are islands surrounded by Taliban-controlled countryside. “Strategic momentum appears to be sort of with the Taliban,” Milley said, in what constitutes one of the understatements of the year. Insisting that “a negative outcome, a Taliban automatic military takeover, is not a forgone conclusion,” Milley added, “We will continue to monitor the situation closely and make adjustments as necessary.” Spelling out what such “adjustments” would entail, the Joint Chiefs chairman stated that a “package of long-range bombers, additional fighter-bombers and troop formations are postured to quickly respond if necessary and directed.”
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