Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 24 July 2021. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.
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Natural gas prices at a 31 month high; gasoline imports at a 10 year high
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…
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 …
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..
Along 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.
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 Merida markets in the Yucatan 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.
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