Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 06 March 2021. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.
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Fuel supplies drop most on record as US oil refining collapses, leading to largest ever jump in oil supplies
Refinery utilization at an all time low, 10% lower than it’s ever been; oil refined is least on record; record jump in oil inventories, record drop in gasoline inventories; distillates production at a 26 year low, distillates inventories drop most in 18 years; largest jump in oil imports in 39 weeks.
Oil prices jumped this week after OPEC and other producers committed to holding their oil output steady through the end of April…after rising 3.8% to $61.50 a barrel in volatile trading last week as US oil output remained sharply curtailed in the wake of freeze damage to Texas production, the contract price of US light sweet crude for April delivery opened higher on Monday and initially rose more than 2% on progress on a huge U.S. stimulus bill and on hopes for improving oil demand as more vaccines are rolled out, but later tumbled to a loss of 86 cents at $60.64 a barrel on fears that Chinese crude consumption was slowing and that OPEC might increase global supply at a meeting later this week...oil prices then opened lower on Tuesday and extended those losses on worries over a possible supply increase from OPEC to close down 89 cents, or 1.5%, at $59.75 a barrel, its lowest close since February 19th, after OPEC Secretary General Mohammad Barkindo said the outlook for oil demand was looking more positive, particularly in Asia, ostensibly telegraphing an oil production increase…oil prices opened lower again on Wednesday after the API reported a surprise increase in crude inventories, but then reversed and rallied to a $1.53 increase at $61.28 a barrel after the EIA report showed a record drop in domestic fuel inventories in the wake of the deep freeze that had shuttered refineries in several states last week…oil prices were down more than 1% again early Thursday, but then surged more than 7% to the highest in nearly two years after the OPEC+ alliance surprised traders with its decision to keep their output unchanged, signaling a tighter crude market in the months ahead, before settling with a $2.55 increase at $63.83 a barrel, as Saudi Arabia even said it would extend its voluntary oil output cut of 1 million barrels per day in the months ahead before gradually phasing it out...oil prices continued to surge on Friday following a stronger-than-expected U.S. jobs report and the decision by OPEC + not to increase oil supplies in April and settled $2.26 higher at $66.09 a barrel, thus finishing the week with an increase of 7.5% at the highest level since April 2019…
Natural gas prices, on the other hand, finished lower after gas inventories fell much less than had been expected…after falling every day last week to a 4 week low of $2.771 per mmBTU as frozen production resumed and temperatures moderated, the contract price of natural gas for April delivery opened 1% higher on Monday, but only managed to hold a six-tenth cent gain at $2.777 per mmBTU at the close on forecasts for seasonally milder weather and lower heating demand through March…natural gas prices rallied again early Tuesday, climbing on LNG export momentum and hints of increased heating demand in mid-March. and held on to a 6.2 cent gain at $2.839 per mmBTU, but the brief rally’s momentum faded Wednesday and prices fell 2.3 cents to $2.816 per mmBTU…prices then tumbled Thursday despite a recovery in LNG exports after a surprisingly anemic storage withdrawal caught traders off guard and left prices 7.0 cents lower at $2.746 per mmBTU…disappointment in the weak storage withdrawal carried into Friday as traders anticipated the spring ‘shoulder season’ when gas storage is refilled, and natural gas prices fell another 4.5 cents to $2.701 mmBTU and thus ended the week at a 5 week low, 2.5% lower than the prior week’s close…
The natural gas storage report from the EIA for the week ending February 26th indicated that the amount of natural gas held in underground storage in the US fell by 98 billion cubic feet to 1,845 billion cubic feet by the end of the week, which left our gas supplies 277 billion cubic feet, or 13.1% below the 2,122 billion cubic feet that were in storage on February 26th of last year, and 178 billion cubic feet, or 8.8% below the five-year average of 2,032 billion cubic feet of natural gas that have been in storage as of the 26th of February in recent years….the 98 billion cubic feet that were drawn out of US natural gas storage this week was far less than the average forecast of a 137 billion cubic foot withdrawal from an S&P Global Platts survey of analysts, and was also much less than 145 billion cubic foot withdrawal from natural gas storage seen during the corresponding week of a year earlier, but was more than the average withdrawal of 81 billion cubic feet of natural gas that have been pulled out of natural gas storage during the same week over the past 5 years… .
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending February 26th indicated that because of a big drop in our oil refining and a big jump in our oil imports, we had the largest surplus of oil on record left to add to our stored commercial crude supplies, which increased for the fourth time in the past fifteen weeks and for the 13th time in the past thirty-seven weeks…. our imports of crude oil jumped by an average of 1,692,000 barrels per day to an average of 3,941,000 barrels per day, the largest jump in 39 weeks, after falling by an average of 1,299,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 37,000 barrels per day to 2,351,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,285,000 barrels of per day during the week ending February 26th, 1,655,000 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 increased by 300,000 barrels per day to 10,000,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production appears to total an average of 13,941,000 barrels per day during this reporting week…
US oil refineries reported they were processing 9,903,000 barrels of crude per day during the week ending February 26th, 2,237,000 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 record 3,080,000 barrels of oil per day were being added to the supplies of oil stored in the US.…so looking at that 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 957,000 barrels per day more than what what was added to storage plus what our oil refineries reported they used during the week….to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a (-957,000) 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 an error or errors of that magnitude in the oil supply & demand figures we have just transcribed…. moreover, since last week’s fudge factor was at +429,000 barrels per day, there was a 1,386,000 barrel per day balance sheet difference in the unaccounted for crude oil figure from a week ago, which means the week over week supply and demand changes we have just transcribed are nonsense…however, since most everyone treats these weekly EIA figures as gospel and since these figures often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as published, just as they’re watched & believed to be accurate by most everyone in the industry…..(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 5,661,000 barrels per day last week, which was 12.8% less than the 6,459,000 barrel per day average that we were importing over the same four-week period last year…..the record 3,080,000 barrel per day addition to our total 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 300,000 barrels per day higher at 10.000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 300,000 barrels per day higher at 9,500,000 barrels per day, while a 17,000 barrel per day decrease to 464,000 barrels per day in Alaska’s oil production had no impact on the rounded national total….last year’s US crude oil production for the week ending February 28th was rounded to 13,100,000 barrels per day, so this reporting week’s rounded oil production figure was 23.7% below that of a year ago, yet still 18.7% above the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…
Meanwhile, US oil refineries were operating at 56.0% of their capacity while using those 9,903,000 barrels of crude per day during the week ending February 26th, down from 68.6% of capacity during the prior week, and the lowest refinery utilization rate on record…hence, the 9,903,000 barrels per day of oil that were refined this week were also the least on record, 36.9% fewer barrels than the 15,696,000 barrels of crude that were being processed daily during the week ending February 28th of last year, when US refineries were operating at an also low 86.9% of capacity…
Even with the drop in the amount of oil being refined, the gasoline output from our refineries was higher for the 6th time in 15 weeks, increasing by 565,000 barrels per day to 8,301,000 barrels per day during the week ending February 26th, after our gasoline output had decreased by 1,295,000 barrels per day over the prior week…but even with that partial rebound in gasoline production, this week’s gasoline output was 14.9% lower than the 9,757,000 barrels of gasoline that were being produced daily over the same week of last year….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 723,000 barrels per day to an twenty-six year low of 2,898,000 barrels per day, after our distillates output had decreased by a record 953,000 barrels per day to an eleven year low of 3,621,000 barrels per day over the prior week…with distillates’ production thus depressed, that output was 37.7% less than the 4,648,000 barrels of distillates that were being produced daily during the week ending February 28th, 2020…
Despite the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 4th time in sixteen weeks, and for 17th time in 33 weeks, falling by a record 13,624,000 barrels to 243,472,000 barrels during the week ending February 26th, after our gasoline inventories had increased by 12,000 barrels over the prior week…our gasoline supplies decreased this week despite the production jump because the amount of gasoline supplied to US users increased by 941,000 barrels per day to 8,148,000 barrels per day, even as our imports of gasoline rose by 74,000 barrels per day to 605,000 barrels per day, while our exports of gasoline fell by 24,000 barrels per day to 493,000 barrels per day…after this week’s big inventory decrease, our gasoline supplies were 3.4% lower than last February 28th’s gasoline inventories of 252,048,000 barrels, and about 3% below the five year average of our gasoline supplies for this time of the year…
Meanwhile, with the second straight big decrease in our distillates production, our supplies of distillate fuels decreased for the 19th time in 27 weeks and for the 29th time in the past year, falling by a 9,719,000 barrels to 142,996,000 barrels during the week ending February 26th, the largest drop in 18 years, after our distillates supplies had decreased by 4,969,000 barrels during the prior week….our distillates supplies fell by even more this week even though the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 144,000 barrels per day to 3,788,000 barrels per day, in part because our exports of distillates rose by 119,000 barrels per day to 820,000 barrels per day, while our imports of distillates rose by 18,000 barrels per day to 321,000 barrels per day…but even after this week’s big inventory decrease, our distillate supplies at the end of the week were still 6.3% above the 134,464,000 barrels of distillates that we had in storage on February 28th, 2020, while they fell to about 2% below the five year average of distillates stocks for this time of the year…
Finally, with the the big jump in our oil imports and and the record low in our refinery throughput, our commercial supplies of crude oil in storage (not including the commercial oil being stored in the SPR) ended the week higher for the 10th time in the past thirty-two weeks, and for the 29th time in the past year, increasing by a record 21,563,000 barrels, from 463,042,000 barrels on February 19th to 484,605,000 barrels on February 26th…after that record increase, our commercial crude oil inventories rose to 3% above the five-year average of crude oil supplies for this time of year, and about about 40% above the prior 5 year (2011 – 2015) average of our crude oil stocks as of the end of February, 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 spring lockdowns of last year after generally rising over the prior two years, except for during the 10 weeks prior to the last two and during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of February 26th were 9.1% more than the 444,119,000 barrels of oil we had in commercial storage on February 28th of 2020, 7.0% more than the 452,934,000 barrels of oil that we had in storage on March 1st of 2019, and also 13.8% more than the 425,906,000 barrels of oil we had in commercial storage on March 2nd of 2018…
This Week’s Rig Count
The US rig count rose for the 23rd time over the past 25 weeks during the week ending March 5th, but it still remains down by 49.2% from what it was a year ago….Baker Hughes reported that the total count of rotary rigs running in the US was up by 1 to 403 rigs this past week, which was still down by 390 rigs from the 793 rigs that were in use as of the March 6th report of 2020, and was also still one less rig than the all time low rig count prior to 2020, and 1,526 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business….
The number of rigs drilling for oil increased by 1 rig to 309 oil rigs this week, after rising by 4 oil rigs the prior week, leaving us with 372 fewer oil rigs than were running a year ago, and still less than a fifth 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 92 natural gas rigs, which was still down by 17 natural gas rigs from the 109 natural gas rigs that were drilling a year ago, and just 5.7% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to those rigs drilling for oil or gas, one rig classified as ‘miscellaneous’ continued to drill in Lake County, California this week, while a year ago there were two such “miscellaneous” rigs deployed…
The Gulf of Mexico rig count decreased by 3 to 14 rigs this week, with 12 of those rigs now drilling for oil in Louisiana’s offshore waters and 2 drilling for oil in Alaminos Canyon offshore from Texas…that was 9 fewer Gulf of Mexico rigs than the 23 rigs drilling in the Gulf a year ago, when 20 Gulf rigs were drilling for oil offshore from Louisiana, one rig was drilling for natural gas in the Mississippi Canyon offshore from Louisiana, another rig was drilling for natural gas in the West Delta field offshore from Louisiana, and one rig was drilling for oil offshore from Texas…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 counts…..
The count of active horizontal drilling rigs was up by 3 to 362 horizontal rigs this week, which was down by 346 rigs from the 708 horizontal rigs that were in use in the US on March 6th of last year, and less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….on the other hand, the directional rig count was down by 2 rigs to 16 directional rigs this week, and those were also down by 35 from the 51 directional rigs that were operating during the same week a year ago….meanwhile, the vertical rig count was unchanged at 25 vertical rigs this week, and those were also down by 9 from the 34 vertical rigs that were in use on March 6th 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 March 5th, the second column shows the change in the number of working rigs between last week’s count (February 26th) and this week’s (March 5th) count, the third column shows last week’s February 26th 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 6th of March, 2020..
Although they’re not all obvious, we have a few more rig changes this week than in recent weeks….checking first for the details on the Permian in Texas from the Rigs by State file at Baker Hughes, we find that there were 3 new rigs added in Texas Oil District 8, which corresponds to the core Permian Delaware, and one rig added in Texas Oil District 8A, which includes the northern counties of the Permian Midland basin, which means there was a net increase of 4 rigs in the Texas Permian….since the national Permian rig count was only up by 3, that means that the rig that was removed in New Mexico must have been pulled out of the farthest west reaches of the Permian Delaware, to balance the national Permian total….elsewhere in Texas, there was a rig pulled out of Texas Oil District 1, there were 2 rigs added in Texas Oil District 2, and there was a rig pulled out of Texas Oil District 4, some or all of which could have been offsetting changes in the Eagle Ford shale that could net to no net change and hence wouldn’t show up in the table above…there was such an offsetting change that isn’t evident in the Barnett Shale in Texas Oil District 7B, where a natural gas rig was pulled out and an oil rig was added while the basin’s rig count remained unchaged….there was also a rig added in the panhandle in Texas Oil District 10, which apparently was not in the Granite Wash, since that basin shows no change…other states showing changes include Louisiana, where 3 rigs were pulled out of the state’s Gulf waters while one rig was added in the northern part of the state that apparenly wasn’t in the Haynesville. and North Dakota, where one rig was pulled out of the Bakken shale in the Williston basin…meanwhile, there was a natural gas rig added in an “other’ basin that Baker Hughes doesn’t track, which more than likely was one of the Texas or Louisiana rigs in a basin that we couldn’t easily pin down either..
Southwestern Drills First Ohio Utica Well after Montage Acquisition – Appalachian pure-play Southwestern Energy Co. plans to keep year/year production and spending flat in 2021 even as it assumes a larger asset base and entry into Ohio with its acquisition of Montage Resources Corp. The exploration and production company laid out its vision for the year last week, joining peers in announcing a plan aimed at prioritizing free cash flow (FCF) generation, “disciplined investment” at maintenance levels and debt reduction. “Our maintenance capital program will hold fourth quarter 2021 production flat with our fourth quarter 2020 level including the Montage assets,” said CEO Bill Way. “Due to our strategy, investments will be focused on the highest return projects at strip prices. And given the strength of our inventory, we expect to have activity in all of our core operating areas.” In addition to its core areas in Northeast Pennsylvania and northern West Virginia, the company gained a foothold in Ohio with the acquisition of Montage, a tie-up that created Appalachia’s third largest oil and gas producer with more than 1 Tcfe of production anticipated this year. Way said the company moved a rig into Ohio and has since drilled its first dry gas Utica Shale well there. Southwestern plans to spend $850-925 million this year and intends to exit 4Q2021 producing about 3.05 Bcfe/d. Management said the company would bring 75-90 wells to sales, including up to 15 in the Ohio Utica’s dry gas window. Capital investment would be split evenly between Southwestern’s dry and liquids-rich acreage across Ohio, Pennsylvania and West Virginia. The company spent $899 million last year. This year’s budget is based on the assumption that Henry Hub prices will average $2.77/Mcf and West Texas Intermediate prices will average $50.00/bbl. The company expects to generate more than $275 million of FCF after having delivered $55 million in FCF in 4Q2020.
Commissioners anticipate oil and gas progress – The Belmont County Board of Commissioners answered questions about the future of oil and gas activity during their Wednesday meeting. Guests included Bill Lample of the Dillies Bottom area along Ohio 7, near the site of a potential ethane cracker plant, who asked questions about whether the new presidential administration might prove harmful to fracking locally. He referred to executive orders from the office of President Joe Biden, including revoking a permit for a Keystone XL pipeline. The proposed pipeline would be nearly 1,200 miles from Canada to the Gulf Coast.“All these executive orders on the oil, pipelines and drilling, is it going to affect Belmont County?”Lample said.“It’s hard to say an exact yes or no,” Belmont County Commissioner Jerry Echemann said, adding the order is aimed at federal land. “I don’t think it will. Obviously I think we have a president now who is less friendly to oil and gas than the previous president, but I don’t think we’re going to be impacted too much by the executive orders that Biden put into place, because the main ones are on federal land, and none of our fracking is on federal land,” Echemann elaborated after the meeting.“The only federal land we really have nearby is the Wayne National Forest,” he said, naming the forest located in southeastern Ohio among the Appalachian Mountains, the southern edge of Monroe County on Ohio 7.“I don’t think that in and of itself will hurt it. The big challenge now are the low energy prices. They’re wanting to see energy prices come up, so that they can do more drilling and be more aggressive at it,” Echemann said.Lample said, “In Dillies Bottom and around Moundsville, there’s a lot of trailer parks. A lot of trailers.”“These certainly are not the best of times for the oil and gas industry,” Echemann said, adding he hoped for a better turn. “It’s all a function of price, when you look at the activity going on,” Commissioner J.P. Dutton said, adding there had been a slow-down even prior to the COVID-19 pandemic. “I think if we see prices creep up a little bit.”
Work begins on controversial Hamilton County Duke Energy pipeline – Work has begun on a controversial natural gas pipeline that will run through much of Hamilton County. Duke Energy’s Central Corridor Pipeline has been in the works for years, and the utility company’s local spokeswoman, Sally Thelen, said it will mean better service to its customers. “It’s critical that we get this pipeline in,” she told WCPO, calling it the “backbone of the system” in Southwest Ohio. “Hamilton County is our most populated county that we serve, so it’s critical that we get this pipeline in so that we can continue to do that.” Once completed, the pipeline will span 13 miles from Golf Manor to Sycamore Township’s northern annex adjacent to Sharonville. The pipeline will also run through neighborhoods in Cincinnati, Amberley Village, Evendale, Blue Ash, Reading and Sharonville. Work began Monday at the pipeline’s northern terminus after years of pushback from neighbors who live along the route, as well as from county leaders. In 2016, then-Hamilton County Commissioner Todd Portune called the pipeline a bad idea. “They’re bad for Hamilton County. They’re bad for the neighborhoods they run through. They’re bad for Duke (Energy),” he said. As recently as 2019, residents were still concerned. “We listened to some of the feedback we’ve gotten from neighbors, customers, local officials . We’ve reduced the size and the pressure of the pipeline. So we are very confident in using the latest building materials and monitoring capabilities that are out there now. This pipeline will be very safe,” she said, adding that the energy company has experience installing infrastructure like the Central Corridor Pipeline.
Revolution pipeline back in service as Energy Transfer and regulators reach yet another deal -Natural gas began flowing Monday in the Revolution pipeline, 2½ years after it slid down a rain-soaked Center Township hillside and burst into flames.Since then, Texas-based Energy Transfer Corp. and the Pennsylvania Department of Environmental Protection, its primary regulator, have been battling over whether the pipeline owner had done enough to prevent the explosion in Beaver County and whether it was doing enough now to avoid another.The company was prohibited from repairing the ruptured portion of the pipe while it worked to stabilize the hill behind Ivy Lane, which stubbornly kept slipping, and on other steep slopes along the 40.5-mile project designed to ferry gas from fracked shale wells through Butler, Beaver, Allegheny and Washington counties.The company’s inability to shore up sliding soil along its right of way after the explosion Sept. 10, 2018, and trouble with construction on the much larger Mariner East pipeline corridor prompted the DEP to issue a permit ban that was lifted in January 2020. When Energy Transfer finally got the go-ahead to reroute the broken piece of pipe onto flatter ground and prepared to put Revolution back in service in the fall, the DEP intervened again, in November.Regulators found unstable slopes that hadn’t been properly secured and ordered the company not to fill the pipe with gas and, if it had, to empty it – a sign that regulators weren’t fully sure of the status of Energy Transfer’s plans.Energy Transfer took that order to court.Late last month, the company signed a settlement agreement with the DEP that said the Revolution pipeline could restart March 1 with increased slope monitoring. It also gave the company 60 days to submit a permanent stabilization plan for a steep hill near Penny Hollow Road. The DEP said the company has shown that the pipeline now is overbuilt to the point that it has a high safety factor. While the DEP previously insisted that the entire right of way must be permanently stabilized before gas could flow again, the settlement gives Energy Transfer more time to reach that goal. In the meantime, instruments installed at certain slopes will measure stability, groundwater levels and ground movement.DEP inspectors, who have visited the pipeline 43 times so far this year, have continued to mark outstanding violations but recorded progress in their inspection notes. The settlement deal also includes a $125,000 civil penalty. That follows a record $30.6 million penalty that the DEP fined Energy Transfer in January 2020 as part of another consent order and agreement that also called on the company to repair stream and wetland damage.
Groups Oppose Pittsburgh-Area Frack Waste Injection Well – Environmental groups are asking Gov. Tom Wolf to revoke state permits for a fracking waste injection well in the Pittsburgh suburb of Plum. It’s one of a handful of new injection wells permitted to operate in Pennsylvania by the EPA. The wells receive fluid drilling waste created by fracking and gas production. The groups are worried that these waters – too toxic to be processed at municipal wastewater plants – will threaten private well water, the nearby Allegheny River, and that the high-pressure injection could induce earthquakes. In a letter to Gov. Tom Wolf, the groups said the well “would present devastating risks to several downstream Allegheny River public drinking water systems, including the Pittsburgh Water and Sewer Authority” which provides drinking water to hundreds of thousands of people. The letter points to a 2016 U.S. Geological Survey study that found oil and gas waste from an underground injection well in West Virginia had contaminated a nearby creek. The groups warn fracking waste could seep into groundwater and tributaries to the Allegheny River through a well casing failure or underground fissures caused by nearby coal mines and gas wells. Representatives from Delmont, Pa.-based Penneco Environmental Solutions, the company developing the well, did not respond to requests for comment. The company’s website states that the process of underground injection is safe and “is crucial to environmental protection and energy production.” In April 2020, the Pennsylvania Department of Environmental Protection gave Penneco a permit to pump 54,000 barrels of waste (42 gallons per barrel) a month into the Murrysville sandstone, an 80-foot thick rock layer 1,900 feet below the ground. A spokeswoman for Wolf said the governor would look into the issue, but said there wasn’t much he could do. “(T)he governor does not have the authority to himself revoke or suspend permits,”
Stopping Radioactive Water: Officials Want to Ban Oil & Gas Injection Wells at Pennsylvania Headwaters to Block EPA Permit – When you zoom in to Clara, dirt roads appear. And between wide, tree-covered hills, houses pop up, where 181 people live in Potter County, 30 minutes from the New York State border. Clean water in Clara is essential to local cattle, horses, wildlife, world-class fisheries, and residents who, without access to a public water system, all rely on wells or springs. Water from Clara pours out of the Appalachian Mountains as part of the Triple Divide: where rainfall splits from one mountain range to three sides of the country. Only four places on the continent have this kind of hydrological reach.But there’s more than wildlife and farms in Clara. Hundreds of conventional and unconventional (a.k.a. fracking) oil and gas wells are cut into the landscape. And that means there’s oil and gas waste, too.In a rusty, grayish-blue building down a dirt road surrounded by trees and backed by beautiful mountains, sits Roulette Oil & Gas. It’s a 15-minute drive from Clara Township. The company operates 271 conventional and 3 unconventional oil and gas wells in Potter County.Conventional wells are drilled vertically to reach shallow reservoirs of oil and gas. It’s a simpler and older process than unconventional, horizontal, hydraulic fracturing today, commonly known as “fracking.” Regardless of the well type, drilling creates large amounts of wastewater, that industry and regulators often describe with harmless names like “salt water”, “brine”, or “produced water.”In September 2020, Roulette Oil & Gas submitted a permit application to the U.S. Environmental Protection Agency (EPA) which asks to convert one of their conventional wells in northwest Clara Township into a Class II-D injection well to dispose of brine from 110 of Roulette’s conventional wells in the area. That means shooting wastewater thousands of feet underground at high pressure into a cavern that once held fossil fuels.A Public Herald review of EPA’s permit authorization for Roulette Oil & Gas found that it doesn’t exclude injecting waste from the three unconventional wells operated by the company. The permit allows for the injection of 15,500 barrels of wastewater a month, and it can also be modified – leaving it open to accepting waste from more oil and gas operators in the future.
Fractured: Harmful chemicals and unknowns haunt Pennsylvanians surrounded by fracking – part 1 – 13-year-old Gunnar Bjornson r lives with his mom, dad, older brothers and younger sister about 35 miles south of Pittsburgh in the aptly-named community of Scenery Hill, where narrow country roads wind through shady woods that open up onto hilltop vistas of rolling fields. The hills are peppered with farmhouses, fruit orchards, and fields of corn and squash. The roadsides are punctuated by little white churches, farm stands, and dirt driveways marked with hand-painted signs like “The Jones’s” and “Hidden Family Farm.” Scenery Hill is in Washington County, the most heavily fracked county in Pennsylvania, with about 1,584 wells in its 861 square miles, so the idyllic country roads are also flanked with signs directing oil and gas well traffic: “No well traffic beyond this point,” “Staging area —->,” “Truck traffic: No engine breaks,” and ads that read, “We buy mineral rights!” August 19, 2019, was a typical day for Gunnar – he played drums, took the dog outside, and argued and joked with his siblings. But unbeknownst to him and his family, Gunnar had a number of harmful chemicals coursing through his body. A urine sample taken from Gunnar that day contained 11 harmful industrial chemicals, including benzene, toluene, naphthalene, and lesser-known chemicals linked to a range of health effects including respiratory and gastrointestinal problems, skin and eye irritation, organ damage, reproductive harm, and increased cancer risk. These chemicals are found in things like gasoline, pesticides, industrial solvents and glues, varnishes, paints, car exhaust, industrial emissions, and tobacco smoke. They’re also commonly detected in air emissions from fracking wells. In Texas, researchers found that babies born near frequent flaring – the burning off of excess natural gas from fracking wells – are 50 percent more likely to be premature. In Colorado, the state Department of Health found that people living near fracking sites face elevated risk of nosebleeds, headaches, breathing trouble, and dizziness. In Pennsylvania, researchers found that people living near fracking face increased rates of infant mortality, depression, and hospitalizations for skin and urinary issues. Studies of fracking communities throughout the country have found that living near fracking wells increases the risk of premature births, high-risk pregnancies, asthma, migraines, fatigue, nasal and sinus symptoms, skin disorders and heart failure; and laboratory studies have linkedchemicals used in fracking fluid to endocrine disruption – which can cause hormone imbalance, reproductive harm, early puberty, brain and behavior problems, improper immune function, and cancer.
Fractured: Buffered from fracking but still battling pollution – part 4 – On a balmy evening in September of 2019, eight women gathered around a conference table in a small office about 25 miles southeast of Pittsburgh. — The group chattered and laughed through the presentation until Ann LeCuyer pulled up a map of the planned route for the Mariner East 2 Pipeline, sending a brief hush through the room. “It’s so close to my house!” someone exclaimed. “Look, I’m in the blast zone and I didn’t even know until now.” Mariner East 2 is one of three pipelines (along with Mariner East 1 and Mariner East 2X) being constructed to carry highly flammable natural gas liquids – liquid components of natural gas that have been separated out – 350 miles from the Utica and Marcellus Shale plays in eastern Ohio, the northern panhandle of West Virginia, and across Pennsylvania to processing facilities at Philadelphia ports. From there, the end products will be carried overseas by ship for use in plastics production. (Ethane, a byproduct of fracking, is used to manufacture plastics.) Executive Director of Protect PT Gillian Graber of Trafford explains a map of community and natural gas infrastructure to Protect PT members during an event at the non-profit’s Harrison City, Pennsylvania, headquarters. (Credit: Connor Mulvaney for Environmental Health News) The project is orchestrated by Sunoco’s parent company Energy Transfer LP, which also owns the controversial Dakota Access Pipeline. The Mariner East pipeline projects have been rife with accidents, spills, and controversy, in part because Pennsylvania doesn’t have a state agency that oversees the placement of such pipelines. The planned route runs across people’s yards and within a half mile of 23 public schools and 17 private schools, which worries residents due to the company’s safety record: Between 2002 and the end of 2017, Energy Transfer LP pipelines experienced a leak or an accident every 11 days on average. Pipeline construction in Pennsylvania has already resulted in sinkholes, polluted waterways on public land, and an explosion in a town 35 miles west of Pittsburgh that destroyed a house. At least 25 other sites along the proposed pipeline route have been identified as being at risk for similar accidents. The Pennsylvania Utility Commission is fighting in court to keep its calculations on potential damage if such accidents occured secret, even though a recent investigation by Spotlight PA found many communities in the “blast zone” – the areas adjacent to the pipeline that could be engulfed in flames in the event of a pipeline explosion – lack adequate emergency response plans.
Fractured: Distrustful of frackers, abandoned by regulators – part 3 – For nearly a decade, Bryan Latkanich has been telling anyone who’d listen that allowing two fracking wells to be drilled on his farm is the worst mistake he’s ever made. He’s a single father on disability who leased his land in 2010 at the height of the fracking boom, thrilled to have two wells 400 feet from his home in exchange for what he thought would be millions of dollars in royalties, only to run into problem after problem. The drilling disturbed more land than had been agreed to or permitted, which he alleges damaged the foundation of his home. He caught workers illegally pumping water out of a pit into the woods behind his property. His well water became undrinkable and he and his son Ryan, who was 2 years-old when the wells went in, developed a rash of ongoing, mysterious health issues. The royalties were a pittance compared to what he expected. Chevron, which owned and operated the two wells, denies any responsibility for these problems, and Bryan has gotten few answers from the state agencies he’s called upon to investigate. “I was a total cheerleader for this industry at the beginning,” Bryan told Environmental Health News (EHN). “Now I just want to make sure no one else makes the same mistake I did. This has ruined my health and my kid’s health and destroyed my farm. It has ruined my life.” In fracking towns across the state and country, people like Bryan have struggled to get answers about what’s happening on their land, in their communities – even in their bodies. The state agencies tasked with overseeing the industry and responding to citizen complaints about pollution and health issues are often under-budgeted, understaffed, and overwhelmed. In Ohio, for example, a three-year investigation published in September 2020 by environmental advocacy group Earthworks showed that the Ohio Environmental Protection Agency and Ohio Department of Natural Resources failed to act on 39 percent of public complaints filed regarding air pollution from the oil and gas industry. The consequences are exemplified by a 2018 incident: After an explosion at an Exxon fracking well in Belmont County, Ohio, the site leaked methane at a rate of about 132 U.S. tons an hour for 20 days, ultimately emitting more of the powerful greenhouse gas than the entire oil and gas industries of France, Norway or the Netherlands do in an entire year. Methane is 84 times more climate-warming than carbon dioxide over a 20-year period.
Pennsylvania Families Exposed to Unusually High Levels of Oil and Gas Industry Chemicals, Report Finds – DeSmog –A groundbreaking four-part report by Environmental Health News (EHN) offers new scientific evidence that living near oil and gas development can expose people to a wide array of hazardous and carcinogenic chemicals – not just those living near shale drilling and fracking, but also those living near older conventional oil and gas wells. The two-year EHN investigation sought to fill in a gap in the scientific understanding of fracking and chemical exposures by undertaking some research themselves, under the guidance of scientific advisors and with approval from an Independent Review Board. They collected air, water, and urine samples from five Pennsylvania families and sent the samples off to researchers at the University of Missouri for analysis. Those tested also wore personal air monitors for up to eight hours on most days samples were collected. The testing cost the publication an average of $12,000 per family, reporter Kristina Marusic said. Researchers also collected data about the families’ activities and other potential sources of chemical exposure before and during the sampling. The researchers discovered striking levels of chemicals associated with oil and gas and their “biomarkers,” substances produced when the body processes chemicals – like mandelic acid, which can be evidence of exposure to ethylbenzene or styrene, or hippuric acid, a biomarker for toluene. The compounds they found biomarkers for, which also included benzene, can cause irritation of the skin, nose, and eyes, central nervous system problems, and liver and kidney damage; some are also carcinogens. “We were pretty shocked at some of these really high levels of these biomarkers in kids,” Marusic told Allegheny Front, adding that she was also surprised to see that some of the highest readings were also found in people who lived further away from shale wells but close to conventional oil wells. That said, the investigative reporting was intended to be a pilot project, she added, not proof that that the chemicals found pose a threat to people’s health. “A lot of times the purpose of a pilot study is to say, ‘Hey, I think there might be something here. We should really look into this further,” she said. “This investigation represents the first comprehensive body burden analysis of residents living in areas targeted by fracking,” Dr. Sandra Steingraber of Concerned Health Professionals of New York, which publishes a compendium of research into the “risks and harms” associated with unconventional oil and gas, said in a statement. “As such, it fills an important data gap and strongly suggests that the toxic emissions from fracking operations are entering the bodies of nearby residents at levels known to cause harm.”
Sky-High Levels of Fracking Chemicals Detected in Children’s Bodies -While the hazards of fracking to human health are well-documented, first-of-its-kind research from Environmental Health News shows the actual levels of biomarkers for fracking chemicals in the bodies of children living near fracking wells far higher than in the general population.The research fills a gap in the science between the health harms experienced by those living near frackingand the known harms caused by fracking chemicals: whether fracking chemicals were actually in people’s bodies. They are. Of the southwestern Pennsylvania families who participated in the study, those who lived closer to fracking wells had higher levels of fracking chemicals or their biomarkers than those who lived far away.One nine-year-old boy had biomarkers for toluene, which can damage the nervous system or kidneys, 91 times higher than the average American. Another had biomarkers for ethylbenzene and styrene, 55 times higher than the average American. Exposure to ethylbenzene and styrene is linked to skin, eye, and respiratory tract irritation, reproductive harm, endocrine disruption, and increased cancer risk. The research is part one of a multi-part series by Environmental Health News exploring the multifaceted “body burden” of fracking.As reported by Environmental Health News: In Texas, researchers found that babies born near frequent flaring – the burning off of excess natural gas from fracking wells – are 50 percent more likely to be premature. In Colorado, the state Department of Health found that people living near fracking sites face elevated risk of nosebleeds, headaches, breathing trouble, and dizziness. In Pennsylvania, researchers found that people living near fracking face increased rates of infant mortality, depression, andhospitalizations for skin and urinary issues. Studies of fracking communities throughout the country have found that living near fracking wells increases the risk of premature births, high-risk pregnancies, asthma, migraines, fatigue, nasal and sinus symptoms, skin disorders and heart failure; and laboratory studies have linked chemicals used in fracking fluid to endocrine disruption – which can cause hormone imbalance, reproductive harm, early puberty, brain and behavior problems, improper immune function, and cancer.
Investigation Into Chemical Exposure From Fracking in Pennsylvania Provokes Call for Rapid Phaseout – “While financial analysts, policymakers, and massive corporations squabble over the finer points of the fracking debate, families living amidst the wells day in and day out live in constant fear about what the industry might cost them – if they had another child, would they need to worry about birth defects? Are these exposures increasing their kids’ cancer risk? Would it be safer to move to a place far away from all of this, even if it would also mean being far from their extended families, friends, and communities? And even if they could move, how far would they have to go to feel safe?”Those are just some of the questions facing the western Pennsylvania families featured in a report published Monday by Environmental Health News (EHN), a publication of the nonprofit Environmental Health Sciences. Five families from the region participated in a pilot study on the chemicals commonly found in emissions from fracking sites. Concerned Health Professionals of New YorkSandra Steingraber of Concerned Health Professionals of New York, a group that has long sounded the alarm about the impact of fracking – which largely affects poor and rural households – responded by calling for an end to the process.”Consider[ed] together with the results of previous studies, the findings of this multi-part investigation serve as a powerful moral indictment of the Pennsylvania Department of Public Health, which has long privileged gas industry interests over protecting the health of Pennsylvania residents,” Steingraber said. “Pennsylvania’s children should not be used as laboratory rats in an uncontrolled human experiment involv[ing] toxic exposures.””In light of today’s revelatory investigation, Concerned Health Professionals of New York reiterates our call: The risks and harms of fracking to public health are inherent to its operation,” Steingraber added. “The only method of mitigating fracking’s grave threats to public health is a rapid, comprehensive phaseout of fracking.” Aided by scientific advisers, EHN conducted a two-year investigation intended to “provide a snapshot of environmental exposures in people living near fracking wells and help pave the way for additional research on a larger scale.” Over the course of nine weeks in 2019, EHN collected a total of 59 urine samples, 39 air samples, and 13 water samples from five nonsmoking local households, all of which had at least one child. We found chemicals like benzene and butylcyclohexane in drinking water and air samples, and breakdown products for chemicals like ethylbenzene, styrene, and toluene in the bodies of children living near fracking wells at levels up to 91 times as high as the average American and substantially higher than levels seen in the average adult cigarette smoker.The chemicals we found in the air and water – and inside of people’s bodies – are linked to a wide range of harmful health impacts, from skin and respiratory irritation to organ damage and increased cancer risk.
When the Kids Started Getting Sick – -On an evening in August, 2008, Cindy Valent learned that her twenty-year-old son, Curt, was in the hospital. Valent, who was fifty-three, with frosted hair and a matter-of-fact manner, lived in Cecil, a small town in southwestern Pennsylvania, which has become a hub of the natural-gas industry. For nearly a year, Curt, a junior at Robert Morris University, had been complaining that his shoulder hurt. That weekend, while with his girlfriend, Erin, he began running a fever and having chest pains. “I thought it was no big deal,” Valent told me recently. In the evening, routine imaging at the hospital revealed a spot near his lung. A few weeks later, Curt was diagnosed with Ewing’s sarcoma, a virulent form of bone cancer, which had spread to his lungs, liver, lymph nodes, and spleen.mWhen Curt began chemotherapy, she cut her hours so that she could stay with him in the hospital during treatment. At one point, she got a medical bill for 1.3 million dollars and wasn’t sure that her insurance would cover it. “We live by the seat of our pants, and without the seat of our pants, we’re screwed,” she said. Kendra Smith, the mother of one of Valent’s preschool students, heard about the situation and offered Valent a more flexible job at a law firm where she and her husband, John, were partners. At the time, the Smiths were beginning to handle cases dealing with environmental issues. When Valent joined, John Smith was representing a local library board in a dispute over the proposed location for a new building. Soil tests had revealed that the planned site was contaminated with benzene, an industrial chemical and known carcinogen, but the county’s development authority wanted to save money by removing only a little of the pollutant before construction. The Smiths helped the library fight for a more extensive cleanup. In December, 2010, while on a snowboarding trip, Curt asked Erin to marry him. On Monday, he finished his college coursework and handed in his last papers. Valent didn’t spend a lot of time thinking about why Curt had gotten sick. It seemed useless to dwell on it. But, in 2011, she learned that Kyle Deliere, a local twenty-five-year-old, had also been diagnosed with Ewing’s sarcoma. The Valents knew Kyle because he had grown up about a half mile from their house, and because he played with the Cecil Township Youth Baseball Association; Curt had played pitcher with the group as a child, and, as he grew older, was an occasional umpire. Valent thought nothing of the coincidence. Then, in December, 2013, she learned that her sixteen-year-old neighbor, Luke Blanock, who also played with the association, had been diagnosed with Ewing’s. As Luke grew sicker, his battle with cancer gained national attention: in early 2016, his wedding to his high-school sweetheart was filmed for an episode of “Inside Edition.” He died that August, and the Pittsburgh Pirates held a moment of silence in his honor during a game.
Pennsylvania Saw Modest Increase in Unconventional Natural Gas Production Last Year, but Activity Down – Pennsylvania unconventional natural gas production surpassed 7 Tcf last year, up 3.9% from 2019, the lowest growth rate on record for a full year of production, according to the state’s Independent Fiscal Office (IFO). Fourth quarter production increased 2.9% year/year to 1.8 Tcf, flat with the annual growth level in the third quarter. Quarterly production growth hit a peak in 2018 of 18.6%, but decelerated for eight consecutive quarters until plateauing at 2.9% in 4Q2020. Activity across the Appalachian Basin has declined as producers have cut budgets and scaled back operations. Demand was hit hard last year by the Covid-19 pandemic and investors have demanded more discipline from the upstream sector. The IFO said 99 horizontal wells were spud in the final three months of 2020, the lowest quarterly spud count since 2Q2016. Preliminary data for 2021 also show that the number of wells spud in January and February decreased by roughly 25% from the same time last year. The number of horizontal producing wells, which account for more than 99% of all unconventional production, increased by 5.9% to 9,868 in the fourth quarter. The IFO also tracks results from vertical wells drilled to unconventional formations, but they account for a marginal share of quarterly volumes. “This growth rate is the smallest year-over-year increase in quarterly horizontal producing wells on record,” the IFO said. “Decelerating growth in producing wells is due to less drilling activity and older wells being shut in or plugged.” The office added that “without a significant uptick in new wells spud, producing well growth will likely continue to decelerate.” While Henry Hub prices declined throughout 2020, they increased in 4Q2020 by 5.6% year/year to average $2.47/MMBtu during the period, driven by winter weather and higher electricity demand. However, IFO noted that regional prices fell steeply throughout the year. In the fourth quarter, average prices in Pennsylvania declined 21.8% year/year to $1.39/MMBtu.
Bankrupt Philadelphia Energy Solutions blames ‘mislabeled’ pipe for big blast that led to refinery’s closure The bankrupt former operator of a South Philadelphia refinery has blamed the supplier of an allegedly mislabeled elbow section of pipe for the 2019 leak and explosion that led to the permanent closure of the plant.Philadelphia Energy Solutions Refining and Marketing LLC, along with the trust that is liquidating the company’s remaining assets, has sued Babcock & Wilcox Co. for allegedly mislabeling the pipe, whose failure authorities say led to the catastrophic accident. The pipe was installed 46 years before the explosion when the refinery was owned by Gulf Oil.“B&W inadequately and defectively marketed the failed elbow joint by mislabeling the failed elbow joint and misleading the purchaser,” according to the complaint, filed Friday in Philadelphia Common Pleas Court. The suit was first reported by Law360.com.The refinery property was sold last year in bankruptcy court for $225.5 million to Hilco Redevelopment Partners, which promised to demolish and clean up the 1,300-acre site and rebuild it as a mixed-use industrial park. PES was the East Coast’s largest refinery until the June 21, 2019 accident damaged the plant and tipped public sentiment against its continued operation.Though the 150-year-old refinery is closed for good, PES continues to sort out the settlement of millions of dollars in liabilities owed to creditors. The lawsuit filed Friday in Philadelphia Common Pleas Court seeks damages from Babcock & Wilcox for allegedly mislabeling the failed pipe joint, and makes claims for negligence, product liability, and breach of warranty.A preliminary 2019 report by the U.S. Chemical Safety and Hazard Investigation Board identified the 8-inch diameter section of pipe in the refinery’s alkylation unit as the source of the leak of flammable liquids and hydrofluoric acid (HF), which formed a vapor cloud that exploded. The alkylation unit produces a chemical that boosts octane level of gasoline.A series of explosions released 5,239 pounds of deadly HF and launched pieces of shrapnel as large as 19 tons across the refinery. Despite the release of hydrofluoric acid, only five refinery workers experienced minor injuries that required first aid treatment.The piping circuit in the alkylation unit that contained the ruptured elbow was installed in about 1973, when a previous owner, Gulf Oil, had installed the unit. CSB said the piping appeared to be original. The CSB report said that a section of pipe that leaked had corroded to about half the thickness of a credit card, or a mere 0.012 inches thick, 7% of the minimum thickness allowed. It said the faulty section of steel pipe contained a high amount of copper and nickel, whose presence in a steel alloy can cause greater corrosion when it comes in contact with HF.
Fracking banned in Delaware River Basin – In a historic ruling, the Delaware River Basin Commission voted Feb. 25 to permanently ban fracking (hydraulic fracturing) for natural gas in the Delaware River Watershed. This ruling formally affirms a drilling moratorium the DRBC imposed in 2010. Representatives of the four states with waterways the Delaware River drains – Pennsylvania, New York, New Jersey and Delaware – voted in favor of the ban. But the federal government representative from the U.S. Army Corps of Engineers abstained, claiming more time was needed to coordinate with the Biden administration.Executive Director Wenonah Hauter of Food & Water Watch, one of several groups who fought for the ban, criticized the federal abstention: “Grassroots activists stopped a plan to frack the Delaware River and never stopped fighting until today’s victory was assured. . . . Fracking is a threat to the Delaware River and everywhere else. Communities living with the harms of fracking have known for years that there is no way to make fracking safe.“The White House chose political expediency today over protecting the drinking water of 15 million people. Biden should listen to communities and science and support a ban on fracking everywhere.” (foodandwaterwatch.org)The DRBC ban prohibits fracking activity in areas of northeastern Pennsylvania and southern New York that sit atop natural gas deposits in the Marcellus Shale formation. Because New York State banned fracking in 2014, the ban only impacts Pennsylvania drilling. The Marcellus Shale does not extend into Delaware or New Jersey.More than 15 million people, a population including New York City; Philadelphia and Trenton, N.J.; and Wilmington, Del., rely on the 13,539-square-mile Delaware River Basin for their drinking water. The protected area includes the Delaware Water Gap and the Upper Delaware Scenic and Recreational River areas – parks that attracted three million visitors and generated $130 million in economic activity in 2019, according to the National Parks Conservation Association.Environmental and community activists have pressured the DRBC for over a decade to ban fracking in the area. Thousands of people signed petitions, wrote letters, demonstrated and spoke out at public hearings. This campaign expanded the broader struggle across the U.S. to ban fracking and to stop building dangerous pipelines to transport petroleum and natural gas extracted through fracking.
US Natural Gas Production Fell 1% in 2020 Amid Pandemic, Lower Prices, EIA Says — U.S. annual natural gas production in 2020 declined 1% year/year and averaged 111.2 billion Bcf/d, a reflection in part of the pullback in drilling activity following the demand destruction and downward pressure on prices caused by the coronavirus pandemic.In releasing its latest 2020 estimate, measured by gross withdrawals, the U.S. Energy Administration (EIA) also on Tuesday noted that a robust increase in production during 2019 resulted in elevated volumes of gas in storage and additional stress on prices early in 2020.Domestic natural gas production grew by 9.8 Bcf/d, or 10% year/year, in 2019, and averaged 111.5 Bcf/d.The agency said production volumes reached a 2020 low in May of 106.4 Bcf/d, before gradually recovering in the second half the year. By December, EIA said, production had increased to 113.0 Bcf/d, though that marked a monthly high not expected to be sustained on an annual basis this year.In the previously released Annual Energy Outlook 2021, EIA said its base case outlook assumed that domestic gas production would recover to pre-pandemic levels by 2023 before continuing to rise through 2050, driven by Lower 48 shale and tight resources, as well as associated gas from oil plays.Under that assumption, the agency said, “more than half of the growth in shale gas production between 2020 and 2050 comes from shale gas plays in the Appalachian Basin in the East region, and most of the remaining growth comes from plays in the Gulf Coast and Southwest regions.” EIA noted Tuesday that Appalachia remains the largest gas-producing region in the United States and is still expanding. Within the Appalachia region, the agency noted, West Virginia was home to the biggest increase in production last year, up 20% to an annual average 7.1 Bcf/d. Production from the Marcellus and Utica/Point Pleasant shales of Ohio, Pennsylvania and West Virginia continues to expand as well. In total, 2020 production from these three states increased to 33.6 Bcf/d in 2020 from 32.1 Bcf/d in 2019, EIA said. Texas remained the largest gas producing state, though its output decreased from 28.4 Bcf/d in 2019 to 28.1 Bcf/d in 2020. Meanwhile, Oklahoma had the largest gas production decrease, falling 13% to 7.6 Bcf/d, according to EIA.
Pipeline firm outlines eminent domain case at Supreme Court — Wednesday, March 3, 2021 — The developer of the PennEast pipeline called for the Supreme Court to overturn a lower court’s “deeply flawed” decision blocking the company from seizing state-controlled land in New Jersey to build its 116-mile natural gas pipeline.Both the state of Kentucky and the companies that issued bonds guaranteeing clean-up and reclamation of the dynamite-blasted landscape warned in court proceedings that there might not be enough money to do all the required work. With other U.S. coal-mining companies in similar financial straits and demand for coal plummeting, Blackjewel’s situation is a harbinger of the trouble ahead in coal country. Coal mining companies are required to post bonds to cover the costs of reclamation should they go bankrupt. They are also supposed to reclaim idled mine sites contemporaneously, as they are mining new areas. As the industry rapidly loses market share and continues its lurch toward the financial abyss, part of its legacy could involve scarred, strip-mined landscapes left behind by serial bankruptcies and government programs that may not be able to step in and finance clean-up and reclamation, environmental and citizens groups fear. “There just is not the capital left in the coal industry to satisfy all the remaining outstanding reclamation obligations,” said Peter Morgan, a Sierra Club attorney who closely follows coal-industry bankruptcy cases nationally. “These companies have been allowed to kick the can down the road time and time again, and now they are running out of road.” Morgan said he sees the Blackjewel case as “the tip of the iceberg,” with other major bankruptcies on the horizon. “There will be a lot more Blackjewels,” he said.
Maine natural gas company pulls plug on $90 million midcoast project — A Maine natural gas company is withdrawing plans for a $90 million project announced earlier this year. In announcing the withdrawal, Summit Natural Gas alluded to political opposition to the gas pipeline that would have expanded natural gas access in Waldo and Knox counties. “Without regional alignment on the best ways to reduce emissions and promote cleaner energy usage, we will no longer pursue plans to bring natural gas to this part of Maine,” CEO Kurt Adams said Tuesday. The pipeline project had attracted early support from leaders in Rockport and Belfast, but opposition was growing against the project, with groups like Sierra Club Maine campaigning against the “fracked gas line.” Summit had pitched the pipeline as a move to limit climate change, coming at a time when Gov. Janet Mills has pledged to make Maine climate neutral by 2045. The company said the project would have reduced Maine’s carbon emissions by 263,000 metric tons over five years, which is equivalent to removing 56,000 cars from the road. Natural gas is a “relatively clean burning” fossil fuel, according to the U.S. Energy Information Administration, and the use of natural gas results in lower rates of carbon dioxide emissions than oil or coal.
Florsheim Announces Sale of NRG Plant, Possible Energy Storage Plan – A gas-fired power plant that drew controversy over plans to build a new turbine was among the fossil fuel plants NRG Energy is selling, Middletown Mayor Ben Florsheim said Monday night.NRG announced Monday that it was selling 4.8 GW of fossil fuel generating assets to Generation Bridge, an affiliate of ArcLight Capital Partners, for $760 million. Florsheim said the company announced in a meeting on Monday morning these assets include the Middletown power plant, as well as plants in New York and California.The announcement comes just over two weeks after NRG failed to secure funding in a regional energy auction it needed to build a new turbine to replace two half-century-old turbines at its plant on the Connecticut River in the south of Middletown.Shortly after that auction, NRG officials held a meeting with the Middletown Common Council and residents opposed to the new turbine. NRG indicated it would be looking into a different proposal for the plant that would include energy storage that the company believed would be more competitive with the regional auction price. “Suffice it to say, this is going to significantly impact the future of this project in ways that we can’t quite anticipate yet,” Florsheim said.
Manchin emphasizes natural gas in second letter to Biden – – For the second time this week, U.S. Sen. Joe Manchin, D-W.Va., has reached out to President Joe Biden on energy policy.Manchin, the chairman of the Senate Energy and Natural Resources Committee, wrote to the president Friday in support of natural gas production, stressing the related impact on the economy and energy security.“Responsible production of natural gas and practices like hydraulic fracturing have improved our nation’s energy security while supporting the nearly 1.5 million hard working Americans the industry employs, including in rural communities across our great nation,” Manchin said. “It is my hope that you will consider these benefits as you evaluate the federal oil and gas leasing program and consider other policies and regulations related to the energy industry.” Friday’s letter follows Manchin’s request for Biden to reconsider his decision to revoke the permit for the Keystone XL oil pipeline. Biden, through executive action, rescinded approval of the project, which would have resulted in the transportation of 800,000 barrels of oil daily from Alberta, Canada to Nebraska.The senator noted Friday the opportunities for natural gas projects in Appalachia with the Marcellus and Point Pleasant-Utica Shale formations, which go from the West Virginia-Virginia border to New York. According to the U.S. Geological Survey, the formations contain an estimated average of 214 trillion cubic feet of natural gas.“Responsible production of our abundant resources is critical,” Manchin said. “That includes using existing technologies and continuing to innovate new ways to reduce methane flaring and leaks from oil and gas systems and expanding our energy infrastructure and gathering lines to instead get that product to market.Manchin said the use of natural gas liquids has increased due to the manufacturing of chemicals, plastics and synthetic materials. He added China’s demand is also expected to continue growing as part of the country’s economic competitiveness strategy.
U.S. natgas hold near 4-week low as weather turns seasonally milder (Reuters) – U.S. natural gas futures held near a four-week low on Monday on forecasts for seasonally milder weather and lower heating demand in March. After falling for seven days in a row, front-month gas futures NGc1 edged up 0.6 cents, or 0.2%, to settle at $2.777 per million British thermal units. On Friday, the contract closed at its lowest since Jan. 29. Refinitiv said output in the Lower 48 U.S. states dropped to an average of 86.5 billion cubic feet per day (bcfd) in February as extreme weather froze gas wells and pipes in Texas and the central United States, the lowest in a month since October 2018. That compares with 91.1 bcfd in January and an all-time monthly high of 95.4 bcfd in November 2019. Refinitiv projected average gas demand, including exports, would drop from 111.3 bcfd this week to 102.9 bcfd next week as the weather turns seasonally milder. That, however, was higher than Refinitiv forecast on Friday. The amount of gas flowing to U.S. LNG export plants fell to an average of 8.5 bcfd in February as extreme cold cut power and gas supplies, the lowest since October 2020. That compares with an average of 10.4 bcfd in January and a monthly record high of 10.7 bcfd in December. Buyers around the world continue to purchase near record amounts of U.S. gas because prices in Europe and Asiaremain high enough over U.S. futures to make it profitable to ship American gas across the oceans. Traders, however, noted U.S. LNG exports cannot rise much more until new units enter service in 2022 since U.S. export capacity is only 10.5 bcfd. LNG plants can pull in a little more gas than they can export since they use some of the fuel to run the facility.
Hints of Heating Demand Boost April Natural Gas Futures – Natural gas futures rallied on Tuesday, climbing on liquefied natural gas (LNG) export momentum and hints of increased heating demand in mid-March. The April Nymex contract climbed 6.2 cents day/day and settled at $2.839/MMBtu, building upon a modest gain a day earlier. May advanced 5.7 cents to $2.875. NGI’s Spot Gas National Avg., meanwhile, lost 12.5 cents to $2.840, led lower by sharp declines in the volatile Northeast region. Futures opened trading in the green on Tuesday and gained strength through the session. Mild weather is widely anticipated much of next week across the Lower 48, but forecasters noted the potential for cooler conditions the following week that could inject a dose of heating demand before spring settles in for good. Though above normal temperatures are still anticipated, projections for the March 12-16 time frame trended colder for the eastern two thirds of the Lower 48 early Tuesday, Maxar’s Weather Desk said. This change is “echoed among the various models over the past 24 hours,” the forecaster said. Production, meanwhile, hovered around 86 Bcf as trading got underway Tuesday, still well below the roughly 90 Bcf level reached prior to the paralyzing winter freeze that gripped Texas in mid-February. The U.S. Energy Information Administration (EIA) estimated that natural gas production in Texas dropped nearly 45% during the week ended Feb. 13, hitting a low of 11.8 Bcf/d on Feb. 17. It is gradually recovering.
US gas storage volumes fall much less than expected as Henry Hub summer strip dips | S&P Global Platts –Forecasts proved well off the mark as US natural gas in storage fell by only 98 Bcf for the week ended Feb. 26 following the week prior’s monster draw of 338 Bcf, prompting a decline for the Henry Hub summer strip. Storage inventories decreased by 98 Bcf to 1.845 Tcf for the week-ended Feb. 26, the US Energy Information Administration reported the morning of March 4. The withdrawal was much weaker than the 137 Bcf draw expected by an S&P Global Platts survey of analysts. It was the largest miss by the storage survey in at least five years. By comparison, the survey has missed the EIA estimate by an average of 8 Bcf year to date. The closest figure of the survey to the EIA estimate was still well above the mark, calling for a 117 Bcf draw. The extent of the disconnect between the EIA and the market is possibly the largest it has ever been in the shale era, likely because of the compounding uncertainties related to the recovery of both production and demand in the wake of the mid-February cold front that brought massive volatility to the US gas market, according to S&P Global Platts Analytics. The draw was closer to the five-year average of 81 Bcf, and, as a result, the deficit to the five-year average increased from 161 Bcf to 178 Bcf. The EIA’s South Central region posted a net change of zero for the week as the salt dome facilities added 9 Bcf, while the non-salt storage fields withdrew 9 Bcf. Over the past five years, the region has posted a net draw of 15 Bcf. Platts Analytics models pointed to a 28 Bcf draw for the region. Natural gas prices searched for direction this week, with the April NYMEX oscillating between $2.70/MMBtu and $2.90/MMBtu. The NYMEX Henry Hub April contract slipped 7 cents to $2.75/MMBtu following the release of the weekly storage report. The summer strip, April through October, fell 6 cents to average $2.85/MMBtu. A lack of intimidating cold in the March forecasts has kept market bulls at bay, while a constructive inventory backdrop has kept market bears from accelerating selling pressure. The market is clearly not reading too much into the report, as the large miss could be more a sign of transient issues post freeze-off events or simply data collection errors. Platts Analytics supply and demand model currently forecasts a 67 Bcf withdrawal for the week ending March 5, which would measure 22 Bcf weaker than the five-year average, as the withdrawal season enters its final month. Production for the week in progress was not impacted by the freeze-off event earlier in the month leading to a production gain of 5.4 Bcf/d week over week. Milder temperatures also reduced total demand by nearly 6 Bcf/d.
April Natural Gas Futures Stumble as Bearish Storage Report Overshadows LNG Recovery – A surprisingly anemic storage withdrawal caught markets off guard on Thursday, fueling bearish demand sentiment and driving natural gas futures lower despite robust liquefied natural gas (LNG) levels.The April Nymex contract dropped 7.0 cents on the day and settled at $2.746/MMBtu. May shed 6.8 cents to $2.781.Diminished near-term weather demand also dragged spot gas prices lower. NGI’s Spot Gas National Avg. shed 16.5 cents to $3.005. LNG export volumes exceeded 11 Bcf Thursday, NGI data showed, marking a return to near-record levels on strong demand from Asia and parts of Europe. LNG feed gas levels were temporarily muted amid the disruptions imposed in February by the Artic freeze that gripped Texas and threw Gulf Coast energy operations out of sync. They have since recovered and on Thursday were on par with the peak reached during the height of winter in January. However, production also recovered to the pre-freeze level of 90 Bcf. “Production levels rebounded quickly after most freeze-offs and other cold related impacts resolved just a week after production bottomed out at around 70 Bcf/d on Feb. 17,” Wood Mackenzie analyst Dan Spangler said in a note to clients Thursday. What’s more, weather outlooks provided little in the way of new momentum for heating demand.
Small Gains for Natural Gas Forwards as LNG Demand Roars Back; More Upside May Wait Until After Spring — Shoulder season may be setting in across U.S. natural gas forward markets weeks ahead of schedule, with modest price changes seen across the country, according to NGI’s Forward Look. A quick return to business as usual following last month’s historic winter freeze combined with near-perfect temperatures to drive April forward prices up only 6.0 cents from Feb. 26-March 3. A similar increase was seen for May forwards, while the summer (April-October) strip and next winter (November-March) posted smaller gains, Forward Look data showed. Rather than winter weather providing any momentum for forward prices this week, the latest weather data showed only a brief bout of cold over the next couple of weeks, with models favoring chilly air over the West then moving eastward around the middle of the month. However, before and after the projected cold snap, conditions are expected to be fairly mild, and NatGasWeather noted weather models are now at odds on just how cold it may become. The European model has grown chillier in recent runs, while the American model has warmed. “Statistically, the latest European Centre is more than 25 heating degree days colder versus the Global Forecast System for the coming 15 days,” NatGasWeather said. Rather than banking too much on the weather, traders may have relied on technical support to spur the rebound, according to EBW Analytics Group. However, further price gains may prove difficult to come by, barring a more substantial bullish forecast shift. The EBW analysts said the market surprisingly shrugged off the recent 338 Bcf storage withdrawal, which was the second largest on record. The withdrawal finally flipped the storage surplus to the five-year average to a deficit. Then, the Energy Information Administration (EIA) followed up the massive draw with another stunner on Thursday. The EIA reported a shockingly low 98 Bcf withdrawal from storage inventories for the week ending Feb. 26. Participants on The Desk’s online energy chat Enelyst questioned the validity of the data, especially in the South Central region. The EIA reported no net change in stocks for the period, with the 9 Bcf build in salt facilities being negated by the 9 Bcf draw in nonsalts. Some estimates had pointed to a draw in the high 20s Bcf. Some market observers also noted that refineries along the Gulf Coast have experienced a much slower return following the Arctic blast, while others said ethane rejection in the Permian Basin may have boosted production in the region. Elsewhere across the country, the Midwest withdrew 43 Bcf out of storage, and the East took out 41 Bcf, according to EIA. Both the Mountain and Pacific regions pulled out less than 10 Bcf. Total working gas in storage fell to 1,845 Bcf, which is 277 Bcf lower than year-ago levels and 178 Bcf below the five-year average. Ahead of the EIA report, estimates were pointing to a much steeper withdrawal near 135 Bcf, which would have pushed the deficit to the five-year average to around 215 Bcf.
EDITORIAL: Move tankers away from Mayfield homes —RESIDENTS of Fredericksburg’s Mayfield neighborhood have a good reason to complain about the dozens of tanker cars CSX Transportation has parked near their homes: They can smell the liquefied petroleum gas (LPG) and other hazardous chemicals the cars contain. That prompted the City Council to pass a resolution requesting that the railroad stop storing tanker cars near the residential area. CSX officials responded that although it “may occasionally have rail cars temporarily in the Fredericksburg yard waiting to be moved to customers,” the tankers are “generally empty,” and “moved daily.” Then why are nearby residents still getting unwelcome whiffs of their contents? It would be one thing if this was the first time that CSX used tracks in the city to store tanker cars containing hazardous chemicals. It’s not. Mayfield residents, including Vice Mayor Chuck Frye, Ward 4, still remember a 2016 incident in which a tanker car parked there leaked a small amount of ethanol being transferred from a subsidiary’s now-defunct ethanol plant in Spotsylvania County. At that time, CSX promised to build a 1.5-mile spur line at its rail yard on Railroad Avenue to keep tanker cars out of the city’s residential areas. The spur line was built with CSX contributing $414,000 and the commonwealth dedicating $900,000 of state money to the project. For the week ending Feb. 27, CSX moved 123,488 carloads of freight containing everything from grain and farm products to petroleum products, lumber, steel scrap, coal and shipping containers – a 2.9 percent increase over the same week in 2020. Since capacity is limited to the amount of space on its tracks, which are shared by Amtrak and the Virginia Railway Express, the railroad often has to pull railcars onto spur lines to let more urgent traffic pass.
How a Gas Company Grossly Underestimated One of the Biggest Pipeline Spills in U.S. History | The New Republic (part 1 of 3) Last year, on August 14, two teenagers riding their ATVs through the woods in Huntersville, North Carolina, noticed a strange liquid bubbling from the earth. They stopped to take a look. The pair, who soon informed their local fire department, had no clue of the scale of the disaster they were looking at. And thanks to the craftiness of Colonial Pipeline, the rest of the country wouldn’t, either.The Colonial Pipeline system, described by a former CEO as a “superhighway of energy,” consists of two parallel pipelines that stretch a combined 5,500 miles, running through 12 southeastern states carrying gas from Houston to New Jersey. We now know the spill started sometime in early August 2020, caused by a crack in one of the pipes, and that the flow of gas was cut off shortly after the local fire department called it in. At first, the company said only around 63,000 gallons of gasoline had spilled, according to local news reports from WSOC. Then, as August turned to September, the number grew to 273,000. In November, as the company assured Huntersville residents that it was “deeply committed to keeping them informed throughout the process,” the number increased again, this time stopping in the neighborhood of 360,000 gallons. By then, the North Carolina Department of Environmental Quality, which was overseeing the cleanup process, released a statement that found that Colonial “has significantly underestimated the volume of gasoline” spilled into the natural preserve. Less than a week later, a Colonial spokesperson admitted toWFAE that the company in fact had no clue how much gas had been pouring from its pipe and that it would, “release a number when we believe it’s accurate and verified through multiple models.” In late January, some five months after those two teenagers happened upon the burst pipeline, the spill’s true scope was finally released in aComprehensive Site Assessment Report filed by the company with DEQ:1.2 million gallons. Instantaneously, it became one of the largest nontanker spills in modern American history. And even with the 1,600 pages of documentation, there was still a great deal of missing information. Last week, the DEQ sent Colonial a Notice of Continuing Violation, finding that the company had not adequately measured or reported the levels of vapor, soil, and air pollution from the site, ordering it to update its assessment by the end of April, and continue testing the private resident wells. The question that now hovers over this crisis is how Colonial managed to obscure, for this long, the scope of what happened in the backyard of North Carolina’s most populous city.
Between Oil And Water: The Issue With Enbridge’s Line 5 – The Organization for World Peace — Two pipelines have been lying at the bottom of the Great Lakes for six decades. Carrying more than half a million barrels of oil and natural gas liquids every day, Enbridge Inc.’s Line 5 runs from Superior, Wisconsin to Sarnia, Ontario. The pipeline passes under the environmentally sensitive Straits of Mackinac – a narrow waterway that connects Lakes Michigan to Lake Huron. The Strait has shallow water, strong currents, and extreme weather conditions (becoming frozen during winter). If a pipe were to rupture, the oil would reach shorelines, accumulate, and jeopardize Great Lakes Michigan and Huron’s ecology. Conscious of environmental concerns, on 13 November 2020, Michigan governor Gretchen Whitmer demanded that Enbridge halt oil flow through the pipeline within 180 days. A 2016 study by the University of Michigan found that more than 700 miles (or roughly 1,100 kilometres) of shoreline in Lakes Michigan and Huron would be compromised by a Line 5 rupture. The Graham Sustainability Institute used computer imaging to model how the oil potentially could spread. According to their findings, the most significant risk areas include the Bois Blanc Islands, places on the north shore of the Straits, and Mackinaw City. Communities at risk include Beaver Island, Cross Village, Harbor Springs, Cheboygan, and other areas of the shoreline. A pipeline rupture would quickly contaminate Lakes Michigan and Huron’s shorelines and would involve an extensive cleanup.Enbridge claims Line 5 is in good condition and has never leaked in the past. However, Enbridge has a checkered past when it comes to oil spills. In 2010 an Enbridge pipeline ruptured in the Kalamazoo River (also located in Michigan) and spilled roughly 1 million gallons of crude oil. The spill went undetected for 18 hours, and the United States Department of Transportation fined Enbridge USD 3.7 million. It is one of the largest land-based oil spills in American history. An investigation found the cause of the pipeline breach to be corrosion fatigue due to ageing pipelines. Alarmingly, the pipeline that runs through the Straits of Mackinac is 15 years older than the pipeline that burst in the Kalamazoo River. Additionally, this is not the only time an Enbridge pipeline has leaked oil. Between 1999 and 2013, there have been 1,068 Enbridge oil spills involving 7.4 million gallons of oil. Despite this history, Enbridge is refusing to comply with the demands of Michigan. On 24 November 2020, Enbridge took legal recourse and brought the case to the U.S. federal court. Enbridge argues that the state has overstepped its jurisdiction. The company also asserts that they not answerable to state overseers, only the U.S. Pipeline and Hazardous Material Safety Administration. Legal analysts point out that the courts are typically hesitant to shutdown operating pipelines and have not often done so in the past. Enbridge is likely to cite precedents in an appeal if the court rules in favour of the state.
Canada calls Michigan’s shutdown of Line 5 a threat to country’s energy security – Natural Resources Minister Seamus O’Regan is calling Michigan’s order to shut down the Enbridge ENB-Tpipeline Line 5, a major petroleum conduit for Central Canada, a threat to this country’s energy security. He said Canada considers the continued operation of Line 5 “non-negotiable” for this country. It is the strongest language the federal government has used to date for a bilateral dispute that is quickly becoming a test of the budding relationship between Prime Minister Justin Trudeau and new U.S. President Joe Biden. The Trudeau government’s minister also vowed Canada would do whatever it takes to stop Michigan from shutting down the pipeline, which passes through the state on its way to Sarnia, Ont. Earlier this week, a senior Global Affairs official said Ottawa would invoke a 1977 Canada-U.S. treaty, which forces binding arbitration on the matter, if necessary. Mr. O’Regan was speaking to MPs on a parliamentary committee Thursday. “We take threats to our energy security very seriously,” he told the special House of Commons Committee on the Economic Relationship between Canada and the United States. “A shutdown of Line 5 would have profound consequences, in Canada and in the United States.” He vowed Canada would intervene precisely when necessary. “The federal government is watching it like a hawk. … We are watching it on almost a minute-by-minute basis and we will be absolutely prepared to intervene at exactly the precise moment.” Michigan Governor Gretchen Whitmer has ordered the May, 2021, shutdown of the Line 5 pipeline, citing environmental risks. Calgary-based Enbridge Inc. has challenged her decision in court. The Enbridge Line 5 pipeline carries petroleum from Western Canada through Great Lakes states to Ontario, where much of the crude is turned into gasoline and other fuels before the remainder is shipped through the Line 9 pipeline to Quebec refineries.
Enbridge’s Line 5 pipeline ‘very different’ from Keystone XL and Canada will fight hard for it: O’Regan – The federal government won’t let Michigan shut down the Line 5 pipeline, Canada’s natural resources minister said Thursday as he dismissed opposition comparisons to the thwarted Keystone XL project. Seamus O’Regan sounded almost combative as he vowed to defend the 1,000-kilometre line, which bridges an environmentally sensitive part of the Great Lakes to link Wisconsin with refineries in Sarnia, Ont. “We are fighting for Line 5 on every front and we are confident in that fight,” O’Regan told a special House of Commons committee on the relationship between Canada and the United States. The Enbridge Inc. pipeline carries an estimated 540,000 daily barrels worth of oil and natural gas liquids, and is vital to the energy and employment needs of Ontario, Alberta and Quebec, as well as northern U.S. states, he added. “We are fighting on a diplomatic front, and we are preparing to invoke whatever measures we need to in order to make sure that Line 5 remains operational. The operation of Line 5 is non-negotiable.” In November, Michigan Gov. Gretchen Whitmer ordered Line 5 to be shut down by May, accusing Calgary-based Enbridge of violating the terms of the deal that allows the line to traverse the bottom of the Straits of Mackinac. The straits, which link Lake Michigan and Lake Huron, boast powerful, rapidly changing currents that experts have said make the area the worst possible place for an oil spill in the Great Lakes. Pipeline opponents in the U.S. – many of the same voices who helped make TC Energy’s proposed Keystone XL expansion an environmental rallying point over the last decade – have vowed to see it shut down. Kirsten Hillman, Canada’s ambassador to the U.S., said Michigan’s concerns over Line 5 predate Whitmer and have been a topic of frequent discussion for embassy officials since 2017. Diplomats and governments will play a role in finding a solution, but resolving the dispute will likely come down to the state government and Enbridge, she suggested. “Line 5 is a crucial piece of energy infrastructure for Canada, but also for the United States – that is a core and principal message that we’re giving,” Hillman told the committee. She echoed O’Regan’s points about the potential impact not only on Canada, but on Michigan and Ohio as well, noting that the pipeline has been operating safely for more than half a century.
Solving Line 5 pipeline spat will require Biden’s intervention, U.S.-Canada expert says U.S. President Joe Biden may be the key to settling the dispute over a Canadian-owned pipeline in Michigan, according to a long-time analyst of Canada-U.S. relations. Calgary-based Enbridge’s Line 5 transports oil and natural gas liquids from Western Canada through the United States to refineries in Ontario and Quebec. Enbridge is working to replace a segment of the 68-year-old pipe that runs 7.2 kilometres under the Straits of Mackinac, which connects Lake Huron and Lake Michigan. The 1,038-kilometre project, built in 1953, goes from northwestern Wisconsin, across the upper peninsula of Michigan, under the Strait of Mackinac and down through the lower peninsula before crossing back up into Canada, terminating in Sarnia, Ont. Last November, Michigan Gov. Gretchen Whitmer moved to revoke the 1953 permit that allows the crossing under the straits. She gave notice that Enbridge must shut down the pipeline by May 2021, arguing the project presents an “unreasonable risk” of environmental damage to the Great Lakes. Earlier this week, Michael Grant, assistant deputy minister for the Americas at Global Affairs Canada, said the federal government is prepared to invoke the rules of a decades-old bilateral treaty if necessary to prevent the state government from pulling the permit. “The federal government is working very closely with Enbridge, mostly through mobilizing our diplomatic network in the United States, to engage the state of Michigan, as well as other states that have a vested interest in Line 5. We are also looking at all of our options that are available, including the 1977 treaty,” Grant said. “Joe Biden is the key to this. And he’s the key to it because this is litigation by the state of Michigan. So the federal government can’t necessarily pre-empt the legislation, but they can weigh heavily in,” he said. “And that’s why I think Canada is talking about invoking this older treaty. They can intervene and say, ‘no,no, this is important – we should allow this.'” However, Sands says the Line 5 dispute so far doesn’t appear to be on Biden’s radar and he has doubts the president will actually get involved. “We may have to re-examine whether Biden and Trudeau really do have this special relationship that we’ve heard about, because so far it’s all talk, no action.”
Deepwater Horizon’s long-lasting legacy for dolphins The Deepwater Horizon disaster began on April 20, 2010 with an explosion on a BP-operated oil drilling rig in the Gulf of Mexico that killed 11 workers. Almost immediately, oil began spilling into the waters of the gulf, an environmental calamity that took months to bring under control, but not before it became the largest oil spill in the history of the petroleum industry. Nearly 10 years have passed since then, and the oil slick has long since dispersed. Yet, despite early predictions, area wildlife are still feeling the effects of that oil, and research published in Environmental Toxicology and Chemistry has shown that negative health impacts have befallen not only dolphins alive at the time of the spill, but also in their young, born years later. A team of researchers, including UConn Department of Pathobiology Professor and Director of the Connecticut Sea Grant College Program Sylvain De Guise, is part of a network conducting a long-term study on the health of bottlenose dolphins living in Louisiana’s Barataria Bay, in the vicinity of the disaster. This population of dolphins includes individuals who lived through the disaster and some born afterwards. “We were on the ready and as soon as we could, and in 2011 we initiated a comprehensive health assessment where 60 to 80 people in the field worked together to find and safely pursue a multi-disciplinary, multi-expertise sample collection and study effort to assess the dolphins’ health,” says De Guise. De Guise explains that after collection, samples were processed in 60 to 80 different specialized labs, and the researchers then regrouped to put the information together. De Guise’s research group specializes in studying the immune system, and from the very first set of samples they started to see consistent and abnormal immune responses in the Barataria Bay dolphins, compared with a similar control group of dolphins from Sarasota Bay who were not exposed to oil. For the Barataria Bay dolphins, the researchers observed immune cells called T-cells that were overly responsive to stimulation. The body uses T-cells to respond to a stimulus, or something recognized as foreign. In particular, there were increased numbers of cells called regulatory T cells, or Tregs, which De Guise describes as the cells that help put the brakes on during an immune response to prevent the body from over-responding and doing more harm than good. Despite the elevated numbers, De Guise says they were surprised to find the Barataria Bay dolphin Tregs appear to be functionally defective.
US LOOP reports 855,000 barrels of sour crude deliveries for February –Over 855,000 barrels of sour crude oil was delivered from the Louisiana Offshore Oil Port in February, an increase of 205,00 barrels on the month, LOOP reported. Monthly LOOP Sour deliveries have increased steadily since October, and February represented the most deliveries reported since August last year when 790,000 barrels were taken out of storage at the facility. Before pandemic lockdowns took hold last year, LOOP deliveries reached 810,000 barrels in February 2020. Deliveries of the grade, which consists of a blend of Poseidon, Mars and Basrah, Kuwaiti and Arab Medium crudes, have increased as market conditions have steadily shifted into backwardation. That often can disincentivize market participants from storing crude and gives more incentive to taking crude out of storage. Refinery usage also has been growing, although winter storms in February took a bite out of consumption as some Gulf Coast refineries were forced to close. Power outages impacted Texas’ refinery capacity, with as much as 4.4 million b/d offline during the week of Feb. 18. Most refineries have begun restarting, but effects may linger until mid-March. The average API gravity for LOOP Sour in February was 29.91 degrees – lighter than January’s average of 29.67 degrees; and sulfur content averaged 2.04%, which was more sour than the month prior’s average of 1.92%. LOOP and Matrix Markets sold 150 of the 9,300 capacity allocations contracts that were offered during its monthly crude storage auction on March 2.
Louisiana AG Landry authorizes settlement between oil company, state – Louisiana Attorney General Jeff Landry announced Thursday he signed off on a deal to resolve litigation involving an oil-and-gas company and coastal parishes alleging environmental damage. The Louisiana Legislature would have to create the framework to implement the deal between Freeport-McMoRan and the state, with the proceeds going to projects consistent with Louisiana’s coastal restoration plan, Landry said. Oil-and-gas leaders, and at least one of their top legislative allies, denounced the deal, calling it secretive and counterproductive for the state’s economy and coastal restoration. “Our actions on these suits are designed to bring finality and resolution and allow everyone a seat at the table,” Landry said. Landry, a Republican, said the settlement releases Freeport from liability for any current claims, triggering its dismissal from the coastal parish lawsuits. In exchange, Freeport would deposit an initial $15 million payment into an escrow account. The company would make additional annual payments, contingent on legislative action, of $4.25 million over 20 years, he said. Payments would not be distributed until the Legislature creates a special fund and oversight board to manage the money. The board would award money toward projects consistent with the state’s Coastal Master Plan, with 60% dedicated to state projects and 40% dedicated to local projects, according to Landry’s office. Landry said the agreement balances environmental protection with a healthy oil-and-gas industry. It does not apply to other similar lawsuits involving dozens of other companies, and Landry said he respects those companies’ right to continue to litigate if they chose to do so. “This litigation has been going on for over eight years now and continues to have a chilling effect [on the industry],” Landry said. “I continue to share, along with the industry, ways to be able to resolve these matters or to take these things off of the table.” Landry said coastal parishes involved in the litigation don’t need to approve the agreement, which he said involve state claims. Gov. John Bel Edwards already has affirmed the settlement. “These long-standing lawsuits by Louisiana’s coastal parishes are focused on coastal restoration and protection,” Shauna Sanford, a spokeswoman for Edwards, said by email. “This agreement ensures that settlement funds stay in the impacted coastal communities for restoration projects and the Governor is hopeful that this settlement can act as a framework for how other similar actions might be handled.”
Gas utilities face unprecedented test in digesting ‘astronomical’ storm costs | S&P Global Market Intelligence – As U.S. gas utilities report billions of dollars in natural gas purchase costs during February’s deep freeze, analysts and executives say the industry has never faced a cost recovery challenge quite like this. The initial gas cost estimates are “astronomical and unprecedented” enough to complicate the funding and timing of any type of cost recovery, Mizuho Securities USA LLC analyst Gabriel Moreen said in a recent research note. While Mizuho was initially confident the impact on gas distributors would be limited, Moreen said the firm now sees potential for longer-term impacts. The cost recovery mechanism that policymakers ultimately approve will play a major role in determining the magnitude of those impacts, the analyst said. Consensus is emerging among gas utility leaders and equity analysts that securitizing the costs would be the simplest and best solution for companies and ratepayers alike. Under this model, companies would issue bonds to finance storm-related gas purchase costs. Some state commissions have already authorized utilities to record those costs in a regulatory asset. They will later determine whether those recorded costs were reasonably incurred and accurate, before setting a schedule for recovering them. [see embedded table] One Gas Inc., which reported $2.2 billion in gas costs, is working with state policymakers and regulators to develop legislation allowing gas utilities to securitize the regulatory assets, Senior Vice President and Chief Commercial Officer Curtis Dinan said on a Feb. 26 conference call. He characterized the conversations as “very positive” but cautioned that the situation is unprecedented. “Historically, you’ve seen [securitization] in different parts of the country primarily related to electric utilities that have dealt with different storm costs,” Dinan said. “There hasn’t been, that I’m aware of, situations that would apply to a gas utility similar to that until this most recent event.”
Six hurt in Saturday afternoon fire at Delek refinery in El Dorado -Delek US said six of its employees are being treated for injuries after a fire broke out Saturday afternoon in the Penex unit of its refinery in El Dorado. The fire was put out by the refinery’s on-site emergency response team with assistance from the El Dorado Fire Department. The fire was reported about 4 p.m. El Dorado resident Rochell Lee Thompson shot Facebook video of the fire. CLICK HERE to see it. Thompson, who lives about two blocks from the refinery, told magnoliareporter.com that his house shook about 4 p.m. He went outside and saw the fire. The refinery was evacuated. Delek US said in a statement issued Saturday night that after the fire broke out, the company began to monitor the air quality within the refinery and the community and have detected no adverse impacts. “We have accounted for all personnel, and we are deeply saddened that six Delek employees are receiving medical treatment this evening. Four of the injured were transferred from the Medical Center of South Arkansas to the burn unit at Arkansas Children’s Hospital in Little Rock. Delek US said that the facility was in the process of undergoing turnaround activity, so there are no operational impacts to Delek US or Delek Logistics
Delek: Investigation into fire at El Dorado refinery to be launched – A fire broke out at the Delek: El Dorado Refinery, formerly known as Lion Oil, Saturday afternoon, injuring six people. It will be investigated “as soon as possible,” a statement released by Delek US Holdings late Saturday night said. “Earlier today, a fire occurred at the Penex unit of our refinery in El Dorado, Arkansas. Our on-site emergency response team, with the assistance of the El Dorado Fire Department, extinguished the fire,” the statement says. “We immediately began to monitor the air quality within the refinery and the community and have detected no adverse impacts.” Delek reported that six people were “receiving medical treatment.” Alex Bennett, executive director of business development at Medical Center of South Arkansas, said on Saturday that six patients were brought to the hospital and four were subsequently transferred to the Arkansas Children’s Hospital (ACH) Burn Unit, explaining that almost all burn patients in the state are transferred there. She said Sunday that the remaining two patients had also been transferred to ACH. The statement goes on to say that the refinery was in the process of turnaround activity, so there were no operational impacts to Delek Logistics or Delek US. “All of our facilities have rigorous, well documented safety controls. Safety is one of our Core Values. A full investigation will be launched as soon as possible,” the statement concludes. Along with the company fire brigade on-site at the refinery, the EFD, Union County Sheriff’s Office and Arkansas State Police responded to the fire.
Cold weather led to refinery shutdowns in U.S. Gulf Coast region — U.S. Energy Information Administration (EIA) The cold snap that affected much of the central part of the country in mid-February disrupted energy systems,particularly in and around Texas. In the U.S. Gulf Coast, where the petroleum infrastructure has rarely operated in sub-zero temperatures, several refineries fully or partially shut down, leading to the largest reduction in Gulf Coast refinery operations in several years.Based on the U.S. Energy Information Administration’s (EIA) Weekly Petroleum Status Report (WPSR), gross inputs of crude oil and other feedstock to U.S. refineries declined 2.7 million barrels per day (b/d) (18%) to 12.6 million b/d for the week ending February 19, 2021. Most of the reduction in gross inputs (also known as refinery runs) was in the Gulf Coast region, which includes Texas.Gulf Coast refinery runs decreased by 2.4 million b/d (28%) to 6.3 million b/d, the largest weekly decline since the impact of Hurricane Harvey in September 2017. The refinery closures will likely continue to affect petroleum markets in the coming weeks, reducing refinery demand for crude oil and production of refined products such as motor gasoline and distillate fuel oil.The Gulf Coast accounts for more than half of total U.S. refinery capacity, and Texas alone accounts for about 32% of total U.S. capacity. By the peak of the weather’s impact on February 17, several refineries had announced either substantial or complete shutdowns as a result of external power outages, constrained natural gas supplies, logistical disruptions, or damage to process units. In total, an estimated 3.7 million b/d, or 20% of total U.S. refining capacity, was shut in as a result of the weather, according to U.S. Department of Energy estimates. Most of the disruptions and shutdowns were among refiners in the Beaumont/Port Arthur, Houston, and Corpus Christi regions of Texas. A more detailed analysis of how the cold weather affected Gulf Coast refineries is available in EIA’s This Week in Petroleum.
European Gasoline Diverted to Texas to Ease Supply Crunch (Bloomberg) — Five gasoline tankers that were enroute to the U.S. East Coast diverted to the Port of Houston to help ease a supply crunch after last month’s freeze crippled the region’s refineries. Major refineries along Gulf Coast, the nation’s refining hub, shut gasoline units during the February deep freeze and power failures. Operators have gradually begun resuming production since the weather warmed, but some plants could take weeks to get back to normal. Texas retailers were also forced to truck in gasoline from other states last week for the first time since Hurricane Harvey. U.S. gasoline stockpiles fell by a record 13 million barrels last week, with most of that in Gulf Coast region, according to government data. The five ships are carrying nearly 1.5 million barrels in total. Texas remains “very low” on gasoline, said Paul Hardin, president of the Texas Food & Fuel Association trade group. “If we don’t have a public panic buy, we’ll make it through the next three or four days.” Friday afternoon 12.2% of Texas gasoline stations — roughly one in every eight — were unavailable because of lack of fuel, Patrick DeHaan, head of petroleum analysis for GasBuddy, said in an email. The figure was at 14% Monday. The New York area, which is supplied with fuel by pipeline from Houston to augment its local refineries, is not yet facing Texas’ pinch. The region’s inventories increased last week. But the country’s largest fuel artery, the Colonial Pipeline, said earlier this week major lines toward New York were experiencing reduced throughput. Fewer barrels of gasoline will be available in the Northeast. “Gasoline is definitely migrating south. There’s room in the tanks so I would expect to see greater flows” toward Houston in coming weeks,
Record U.S. crude stockbuild as refining plummets after Texas freeze (Reuters) – U.S. crude oil stockpiles surged by a record of more than 21 million barrels last week as refining plunged to an all-time low due to the Texas freeze that knocked out power for millions. With refiners unable to process crude, gasoline and distillate inventories also dropped dramatically, especially in the Gulf Coast region where their declines set records, the U.S. Energy Information Administration said Wednesday. Crude inventories rose by 21.6 million barrels, the largest one-week increase ever, in the week to Feb. 26 to 484.6 million barrels. Analysts had anticipated a 932,000-barrel drop. “This drop is 100% based upon the storm in Texas,” said John Kilduff, partner at Again Capital Markets in New York. “It was very bullish for refineries and very bearish for oil, it was the crack spread siege.” The storm shut U.S. refining capacity along the Gulf Coast, while demand remained in other parts of the country. Refinery crude runs fell by 2.3 million barrels per day in the last week, and the overall refinery utilization rate plunged 12.6 percentage points to an all-time low at 56%, EIA said. U.S. Gulf Coast refining use dropped to just over 40% of its overall capacity, a record low. Several major refiners along the Gulf shut outright during the storm and had to deal with frozen components as they restarted slowly. “I’m not surprised, I’m surprised it took an extra week to all kick in. It was a giant storm and it shut down every refinery in refinery row, basically,” said Bob Yawger, director of energy futures at Mizuho. Oil prices jumped after the data, with U.S. crude futures climbing to $61.38 a barrel, a 2.7% increase as of 11:35 a.m. ET (1635 GMT). Brent rose 2.3% to $64.15 a barrel. The increase in stocks was also driven by a big jump in U.S. crude imports, which rose by a net 1.66 million barrels per day, EIA said. U.S. gasoline stocks fell by 13.6 million barrels in the week, the most ever, to 243.5 million barrels, compared with expectations for a 2.3 million-barrel drop. Distillate stockpiles, which include diesel and heating oil, fell by 9.7 million barrels in the week to 143 million barrels, versus expectations for a 3 million-barrel drop.
US oil, gas rig count leaps 30 to 491 on week, as oil prices climb further: Enverus – The US oil and gas rig count leaped 30 in the week ending March 3 to 491, rig data provider Enverus said, reaching the highest total since late-April 2020, as WTI oil prices climbed near the mid-$60s/b amid buoyant outlooks at major energy conferences.Oil-directed rigs accounted for the vast majority of the week’s gain, rising 27 to 366, while rigs chasing natural gas grew three to 125.The Permian Basin, sited in West Texas and Southeast New Mexico, was the clear focus area for growth, with a weekly increase of 12 for a total 222. Rig totals in the Permian are now at the most since late-April 2020.”While on paper this looks like a massive week-on-week gain, generally speaking, it was a large recovery that was needed after two straight weeks of flat rigs for US shale,” S&P Global Platts Analytics analyst Andrew Cooper said.The week’s large jump may have been an “accumulation” from slowdowns the past few weeks because of the winter freeze that struck the US in mid-February, with rigs finally mobilized to the field after delays, Platts’ Analytics analyst Parker Fawcett said.The freeze hit the Permian and Eagle Ford Shale in South Texas particularly hard. At peak, up to 4 million b/d of the US’ total 11 million b/d of oil production was offline, although most of it was quickly restored within a few days. “At the annual CERAWeek by IHS Markit energy conference this week, enthusiasm for the future of upstream oil and gas in the next two decades was evident, despite what many believe will be a steadily growing use of renewable and alternative energy sources by mid-century; a move even oil and gas producers have begun to embrace.For the time being, upstream players have repeatedly renewed their vows not to contribute to supply-demand imbalances. At CERAWeek, they repeated they will stick to austere capital budgets and growth targets of 5% or less per year and return sizeable amounts of cash to shareholders, while continuing to cut costs, improve efficiencies and seek ways to reduce their carbon footprints.Oil prices that have topped $60 WTI in recent weeks served as backdrop for talk at the conference, with chatter that a year of under-activity in 2020 could push prices even higher in the next 18 months or so.LeBlanc said producers will almost certainly continue with austere programs in 2021, but suggested next year, if prices climb further, their appetite might overcome their will power.WTI averaged $61.35/b in the week ending March 3, up 13 cents week on week, according to S&P Global. WTI Midland averaged $62.28/b, down 8 cents, and Bakken Composite averaged $60.40/b, up $1.04.Natural gas settled lower as prices continued to stabilize following the impact of the US freeze. Henry Hub prices averaged $2.74/MMBtu, down $1.43 on week, and Dominion South averaged $2.32/MMBtu, down 58 cents.
Oil production could fall in Permian Basin due to Biden proposal – Dallas Fed report (Reuters) – Possible changes to oil leasing and permitting requirements governing federal lands could lower oil production in the Permian Basin, a report from the U.S. Federal Reserve Bank of Dallas, said on Thursday. In late January, U.S. President Joe Biden signed a raft of executive orders that paused new leasing for drilling on public lands and waters that account for about a quarter of U.S. oil and gas production. “We estimate that by the end of 2025, the Permian will produce between 230,000 and 490,000 barrels per day less than if drilling activity continued at its current pace,” report bit.ly/30aL3kn said. Texas produces 41% of U.S. crude oil and 25% of natural gas, according to the Energy Information Administration. New Mexico, is the biggest beneficiary of revenues from drilling on federal lands.
Pioneer CEO sees ‘very little growth’ in U.S. oil production (Reuters) – U.S. oil production will likely see “very little growth” in the future after remaining largely flat in 2021 at around 11 million barrels a day, Scott Sheffield, Pioneer Natural Resources Co chief executive officer, said at a conference on Tuesday. The coronavirus health crisis slashed global fuel demand and sent oil prices plummeting last year before economic stimulus measures and COVID-19 vaccine rollouts helped the industry regain footing in recent months. Still, U.S. shale oil production is lower than pre-pandemic levels and Sheffield and other industry experts said during CERAWeek by IHS Markit that it was unlikely to recover to its peak more than 13 million barrels per day. “I see U.S. production flattish this year at around 11 million barrels a day with very little growth in the future,” Sheffield said. The decline in oil comes as public policy, investors and energy companies increasingly focus on producing clean energy to fight the effects of climate change. Sheffield said Irving, Texas-based Pioneer was working to electrify its fracking fleet to help reduce emissions in its oil production.
U.S. oil production won’t return to pre-pandemic levels, says Occidental CEO – Occidental CEO Vicki Hollub said Thursday that she doesn’t envision U.S. oil production returning to pre-pandemic highs. “I do believe that most companies have committed to value growth, rather than production growth,” she said during a CNBC Evolve conversation with Brian Sullivan. “And so I do believe that that’s going to be part of the reason that oil production in the United States does not get back to 13 million barrels a day.” She believes companies will focus on optimizing current operations and facilities, rather than seeking growth at all costs. But she added that oil demand is recovering faster-than-expected, driven primarily by China, India and the United States. “The recovery looks more V-shaped than we had originally thought it would be,” she said. The company’s initial forecast had demand returning to pre-pandemic levels by the middle of 2022. Now, Hollub believes demand will return by the end of this year or the first few months of 2022. “I do believe we’re headed for a much healthier supply and demand environment” she said. Her comments came after West Texas International crude futures, the U.S. oil benchmark, jumped more than 4% on Thursday to trade as high as $64.86 per barrel, a level last seen in January 2020. She expects crude prices will be “a little better than where they are today” if her demand forecast for next year is correct, but she does not expect prices to go up “excessively” other than the short spikes that can occur from time to time. OPEC and its oil-producing allies on Thursday decided to keep production levels largely steady into April, with Saudi Arabia also announcing that it would extend its voluntary one million barrels per day production cut. The group first implemented unprecedented supply cuts in 2020 in an effort to provide a floor as oil prices tumbled to historic lows. The energy sector has rebounded this year and is the top-performing S&P group by a long shot, but stock prices continue to hover well below prior highs as the focus on ESG investing, among other things, weighs. Hollub reiterated Thursday that the company is working toward net zero carbon oil production through its heavy investments into carbon capture. “We need to change the narrative .. it’s not fossil fuels that’s really the problem, it’s the emissions,” she said. “What we have to do is we need to get everybody focused on instead of trying to kill fossil fuels, we need to get everybody’s attention on how do we use oil and gas reservoirs to our advantage.” “How do we use that to lower emissions all around the world, and that’s exactly our goal. Our goal is to be the company that provides the solution,” she said.
Dying Oil Companies’ Parting Gift: Millions in Clean Up Costs -When Weatherly Oil and Gas filed for bankruptcy in February 2019, the company was walking away from several hundred Texas wells. Many hadn’t produced a drop of oil in years. Companies are legally required to “plug” wells that they’re no longer using to extract oil and gas by pouring concrete into all their openings and cracks; this prevents them from leaking fossil fuels or harmful pollutants into the air and water sources nearby. But many companies that abandon wells say they no longer have the financial means to do so, leaving government regulators on the hook for the cost. The problem is massive: There are approximately 2.1 million unplugged abandoned wellsacross the country. The Texas Railroad Commission, or RRC, which oversees the state’s oil and gas industry, tried to make sure Weatherly would pay up, objecting to the state’s bankruptcy plan because it didn’t include sufficient information about the amount of money that would be set aside for well cleanup and for the company’s various creditors. Ultimately, Weatherly struck a deal with the agency: The company would pay the Commission $3.5 million to cover the plugging costs of the abandoned wells that it couldn’t find buyers for. The agency agreed, and the bankruptcy court approved the deal. When Weatherly handed over 173 abandoned wells to the state, it officially became the company responsible for the most orphan wells in Texas. Unfortunately, the $3.5 million that the RRC was able to squeeze out of Weatherly doesn’t even cover a third of the $13.3 million estimated cleanup cost. Effectively, the state is now responsible for coming up with almost all of the $10 million shortfall.Though Weatherly insisted it couldn’t find the money to fulfill its plugging obligations, the company’s top executives were paid a combined $8.6 million in the year preceding bankruptcy. Weatherly’s former CEO later became a paid bankruptcy expert for FTI Consulting, a public-relations firm with a record of launching duplicitous front groups for oil companies. (The company’s former executives did not immediately respond to requests for comment.) It’s a stark example of the way that environmental liabilities are going unaddressed when companies go belly up, according to a report released Tuesday by the new nonprofit group Commission Shift, which advocates for reform of oil and gas regulation in Texas. The Lone Star State currently has more than 6,000 orphan wells on government rolls, and the RRC estimates they will cost more than $300 million to clean up.
Oil trade group is poised to endorse carbon pricing – – The oil industry’s top lobbying group is preparing to endorse setting a price on carbon emissions in what would be the strongest signal yet that oil and gas producers are ready to accept government efforts to confront climate change. The American Petroleum Institute, one of the most powerful trade associations in Washington, is poised to embrace putting a price on carbon emissions as a policy that would “lead to the most economic paths to achieve the ambitions of the Paris Agreement,” according to a draft statement reviewed by The Wall Street Journal. “API supports economy-wide carbon pricing as the primary government climate policy instrument to reduce CO2 emissions while helping keep energy affordable, instead of mandates or prescriptive regulatory action,” the draft statement says. API’s executive committee was slated to discuss the proposed statement this week. In a statement to the Journal, API’s senior vice president of communications, Megan Bloomgren, said the group’s efforts “are focused on supporting a new U.S. contribution to the global Paris agreement.” Carbon pricing aims to discourage the production of harmful greenhouse gases by setting a price on emissions. The API draft statement would endorse the concept in principle, without backing a specific pricing scheme such as a carbon tax.
American Petroleum Institute move would recognize climate change, but undercut other measures – The American Petroleum Institute, the oil and gas industry’s top lobbying arm, is edging closer to endorsing a carbon tax, a tool that would make fossil fuels more expensive, boost prospects for renewable and nuclear energy, and curb pollution that is driving climate change. But a paper being weighed by an API policy committee would back a carbon tax as an alternative to federal regulation and policies aimed at slowing climate change. And many analysts and lawmakers doubted the sincerity of any such API move because it is highly unlikely Congress would adopt a carbon tax – allowing the trade group to appear to support climate action while risking little. The draft statement, first reported by The Wall Street Journal, says that “API supports economy-wide carbon pricing as the primary government climate policy instrument to reduce CO2 emissions while helping keep energy affordable, instead of mandates or prescriptive regulatory action.” Coming up with the right language is key for API’s nearly 600 members at a time when President Biden wants urgent action in the fight against climate change. His administration is looking at measures that would slash fuel consumption, clamp down on methane emissions, make buildings more efficient, and limit drilling on federal lands. As Biden pledges monumental action on climate change, the fight with the fossil fuel industry has just begun API’s president Mike Sommers is eager to be part of those discussions, especially to prevent limits on drilling, moderate regulations on methane emissions and influence the terms of the climate plans required by all signatories to the Paris climate accord, which the United States just rejoined. Environment and climate groups doubt that the draft endorsement was significant. Maya Golden-Krasner, deputy director of the Center for Biological Diversity’s Climate Law Institute, said “the API’s move would be little more than a public relations ploy, and the Biden administration shouldn’t be taking policy cues from the standard polluters’ playbook.”
Nebraska commission to intervene on natural gas prices after extreme cold in February –Nebraska regulators said Tuesday that they will intervene – for now – in the February price hikes expected on the bills of customers served by privately operated natural gas companies. Extreme cold in mid-February, from the Canadian border to Texas, caused natural gas prices on the open market to skyrocket, driving up the price that utilities pass on to customers. In portions of Nebraska it was one of the coldest mid-Februarys on record. The Nebraska Public Service Commission has regulatory authority over Black Hill Energy and NorthWestern Energy, but not municipal utilities such as Metropolitan Utilities District. Tom Glanzer, a spokesman for NorthWestern, said that the utility didn’t yet have an estimate on how the February price spikes would affect bills, but that the utility will work with the PSC to ease stress on customers. In South Dakota, for example, the increased cost will be spread over 12 months. A representative of Black Hills couldn’t be reached. MUD has estimated that the average residential customer could see an additional $17.21 on their February bill, a cost that could have been $200 higher if not for cost-saving moves made by the district. Requiring an additional 30-day grace period for paying off delinquent bills. Extending the moratorium on shutting off delinquent low-income households. Opening an investigation into price spikes that occurred as a result of the February Arctic outbreak and then assessing options. Directing the two utilities to withhold from bills, for now, the extraordinary price spikes related to the Arctic outbreak until further findings have been made.
The Fight Over The Future Of Natural Gas : Short Wave : NPR podcast – A growing number of cities are looking at restricting the use of gas in new buildings to reduce climate emissions. But some states are considering laws to block those efforts, with backing from the natural gas industry. Today, NPR science correspondent Dan Charles takes us on a tour of three cities where this is playing out:
- Lawrence, KS – Last year, the city commission adopted a goal of moving to 100 percent renewable energy. Now, the state legislature in Kansas is considering a bill that says no city in Kansas can prevent or discourage people from using natural gas from their local gas utility to heat their homes. That bill is likely to become law.
- Salt Lake City, UT – City officials here are not considering a ban. Instead, they’re hoping to provide incentives to consumers that will encourage them to switch from natural gas.
- Flagstaff, AZ – Last year, the city council passed a climate emergency declaration and set in place the goal of reaching carbon neutrality by 2030. As part of this, officials were considering limiting new construction if plans included natural gas. But, Arizona’s state legislature signed a bill into law making it illegal for cities in the state to limit these gas hookups.
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