Oil, Gas, And Fracking News Read 25April 2021 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 24 April 2021. Part 2 is available here.

This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.

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Gasoline demand at an 8 month high; imports of distillates at a 26 week low.

Oil prices moved lower this week on rising Covid cases globally and on a surprise increase in US crude supplies… after rising 6.1% to $63.13 a barrel last week on strong economic data and on upwardly revised demand forecasts, the contract price of US light sweet crude for May delivery opened lower on Monday on trader’s jitters over surging Covid cases coronavirus cases in Europe and India, but recovered to finish with a 25 cent gain at $63.38 a barrel as a weaker dollar supported prices by making oil cheaper for holders of other currencies…oil prices continued higher early Tuesday, hitting a one month high of $64.30, following reports of an outage in Libya, but pulled back on fears that India, the third-largest oil importer, would impose restrictions as coronavirus infections and deaths surged to record highs. and settled 94 cents lower at 62.44 a barrel, as trading in the May oil contract expired….with oil reports now referencing the contract price of US light sweet crude for June delivery, which had closed down 74 cents at 62.67 a barrel on Tuesday, oil prices opened lower on Wednesday after the American Petroleum Institute reported an unexpected increase in crude supplies, and then tumbled to close $1.32, or more than 2% lower at $61.35 per barrel after the EIA confirmed that crude oil stockpiles had unexpectedly edged higher last week…oil prices continued falling early Thursday on expectations that rising coronavirus cases in India and Japan would cause demand to decline, but recovered to close 8 cents higher at $61.43 per barrel as traders noted that overall oil demand remained robust in the two largest oil markets, the U.S. and China…oil prices moved higher again on Friday on strong economic reports from Europe and the US and settled with a gain of 71 cents at $62.14 a barrel but still finished with a loss of 1.6% on the week, as spreading coronavirus cases in countries such as India tempered positive signs out of the U.S. and Europe..

Natural gas prices finished higher this week on an outbreak of record cold that spread to most points east of the Rockies…after rising 6.1% to a five-week high of $2.680 per mmBTU last week on strong LNG exports and on an unexpected temperature drop, the contract price of natural gas for May delivery resumed its climb on Monday, buoyed by near-record export demand and the arrival of intensifying cold weather, and settled 6.9 cents, or 2.6%, higher at a six week high of $2.749 per mmBTU…but prices slipped on Tuesday on forecasts for milder weather and lower heating demand over the next two weeks than was previously expected and finished 2.2 cents, or 0.8%, lower at $2.727 per mmBTU….natural gas price continued to retreat on Wednesday as production ticked higher and export demand slipped, closing down another 3.5 cents to $2.692 per mmBTU…however, prices rallied on a bullish natural gas storage report on Thursday and recouped the losses from both days, closing 5.7 cents higher at $2.749 per mmBTU, now a seven week high…prices were off 1.9 cents to $2.730 per mmBTU on Friday on forecasts for the weather to moderate over the next two weeks, but still finished the week 1.9% higher than the prior Friday’s close..

The natural gas storage report from the EIA for the week ending April 16th indicated that the amount of natural gas held in underground storage in the US rose by 38 billion cubic feet to 1,883 billion cubic feet by the end of the week, which left our gas supplies 251 billion cubic feet, or 11.8% below the 2,134 billion cubic feet that were in storage on April 16th of last year, but 12 billion cubic feet, or 0.6% above the five-year average of 1,871 billion cubic feet of natural gas that have been in storage as of the 16th of April in recent years….the 38 billion cubic feet that were added to US natural gas storage this week was close to the average forecast of a 37 billion cubic foot addition from an S&P Global Platts survey of analysts, as well as to the average addition of 37 billion cubic feet of natural gas that have typically been injected into natural gas storage during the same week over the past 5 years, but it was less than the 47 billion cubic feet added to natural gas storage during the corresponding week of 2020…

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending April 16th indicated that despite a decrease in our oil imports, a big increase in crude oil that the EIA could not account for meant we had surplus oil to add to our stored commercial crude supplies for the sixth time in nine weeks and for the 14th time in the past thirty-nine weeks….our imports of crude oil fell by an average of 448,000 barrels per day to an average of 5,405,000 barrels per day, after falling by an average of 411,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 31,000 barrels per day to an average of 2,548,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,857,000 barrels of per day during the week ending April 16th, 417,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was reportedly unchanged at 11,000,000 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 13,857,000 barrels per day during this reporting week…

US oil refineries reported they were processing 14,765,000 barrels of crude per day during the week ending April 16th, 286,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net of 21,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was a rounded 887,000 barrels per day less than 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 (+887,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or errors of that magnitude in this week’s oil supply & demand figures that we have just transcribed…..furthermore, since last week’s fudge factor was at -222,000 barrels per day, there was a 1,109,000 barrel per day balance sheet difference in the unaccounted for crude oil figure from a week ago, which renders the week over week supply and demand changes we have just transcribed meaningless….however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as they’re published, just as they’re watched & believed to be 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 5,916,000 barrels per day last week, which was still 5.0% more than the 5,635,000 barrel per day average that we were importing over the same four-week Covid impacted period last year… the 21,000 barrel per day net withdrawal from our crude inventories included a 106,000 barrel per day withdrawal from our Strategic Petroleum Reserve, space in which has been leased for commerical purposes, which was mostly offset by a 85,000 barrel per day addition to our commercially available stocks of crude oil….this week’s crude oil production was reported to be unchanged at 11,000,000 barrels per day even though the rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day higher at 10,600,000 barrels per day, because an 11,000 barrel per day decrease in Alaska’s oil production to 446,000 barrels per day subtracted 100,000 barrels per day the rounded national total (EIA’s math)….our prepandemic record high US crude oil production during the week ending March 13th 2020 was at a rounded 13,100,000 barrels per day, so this reporting week’s reported oil production figure was 16.0% below that of our production peak, yet still 30.5% 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 85.0% of their capacity while using those 14,765,000 barrels of crude per day during the week ending April 16th, unchanged from the prior week, thus matching the highest refinery utilization rate in 56 weeks, reflecting the refinery utilization level during the last week before the Covid related slowdown…while the 14,765,000 barrels per day of oil that were refined this week were 18.5% higher than the 12,456,000 barrels of crude that were being processed daily during the week ending April 17th of last year, they were still 11.0% below the 16,583 ,000 barrels of crude that were being processed daily during the week ending April 19th, 2019, when US refineries were operating at a closer to normal 90.1% of capacity…

With this week’s sudden decrease in the amount of oil being refined, the gasoline output from our refineries decreased by 229,000 barrels per day to 9,386,000 barrels per day during the week ending April 16th, after our gasoline output had increased by 336,000 barrels per day to a fifty-six week high of 9,615,000 barrels per day over the prior week…while this week’s gasoline production was 51.3% higher than the 6,205,000 barrels of gasoline that were being produced daily over the same week of last year, it was still 5.9% lower than the March 13th 2020 pre-pandemic high of 9,974,000 barrels per day, and 4.0% below the gasoline production of 9,781,000 barrels per day during the week ending April 19th, 2019….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 88,000 barrels per day to 4,555,000 barrels per day, after our distillates output had increased by 4,000 barrels per day over the prior week… and since the onset of the pandemic didn’t appear to impact distillates’ production, this week’s distillates output was still 9.0% lower than the 5,007,000 barrels of distillates that were being produced daily during the week ending April 17th, 2020…

Even with the decrease in our gasoline production, our supply of gasoline in storage at the end of the week increased for the seventeenth time in twenty-three weeks, and for 21st time in 40 weeks, but only rose by 85,000 barrels to 234,982,000 barrels during the week ending April 16th, after our gasoline inventories had increased by 309,000 barrels over the prior week...our gasoline supplies managed to increase this week even though the amount of gasoline supplied to US users increased by 160,000 barrels per day to an eight month high of 9,104,000 barrels per day because our imports of gasoline rose by 280,000 barrels per day to 1,119,000 barrels per day while our exports of gasoline rose by 14,000 barrels per day to 677,000 barrels per day….but even after three inventory increases, our gasoline supplies still were 10.8% lower than last April 17th’s gasoline inventories of 263,234,000 barrels, and about 3% below the five year average of our gasoline supplies for this time of the year…

Along with the decrease in our distillates production, our supplies of distillate fuels decreased for the 8th time in 18 weeks and for the 22nd time in thirty-four weeks, falling by 1,073,000 barrels to 142,391,000 barrels during the week ending April 16th, after our distillates supplies had decreased by 2,083,000 barrels during the prior week….our distillates supplies fell by less this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 274,000 barrels per day to 3,854,000 barrels per day, while our imports of distillates fell by 99,000 barrels per day to a 26 week low of 162,000 barrels per day, and while our exports of distillates fell by 58,000 barrels per day to 1,016,000 barrels per day….even after this week’s inventory decrease, our distillate supplies at the end of the week were still 4.0% above the 136,880,000 barrels of distillates that we had in storage on April 17th, 2020, and about 2% above the five year average of distillates stocks for this time of the year…

Finally, with that big jump in unaccounted for crude, our commercial supplies of crude oil in storage rose for the 10th time in the past twenty-three weeks and for the 26th time in the past year, increasing by 594,000 barrels, from 492,423,000 barrels on April 9th to 493,017,000 barrels on April 16th…after this week’s increase, our commercial crude oil inventories remained at 1% above the most recent five-year average of crude oil supplies for this time of year, and at about 43% above the average of our crude oil stocks as of the third weekend of April over the 5 years at the beginning of this decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories had jumped to record highs during the spring lockdowns of last year, our commercial crude oil supplies as of April 16th are now 4.9% less than the 518,640,000 barrels of oil we had in commercial storage on April 17th of 2020, but still 7.0% more than the 460,633,000 barrels of oil that we had in storage on April 19th of 2019, and also 14.7% more than the 429,737,000 barrels of oil we had in commercial storage on April 20th of 2018…

This Week’s Rig Count

The US rig count fell for just the 3rd time over the past 32 weeks during the week ending April 23rd, but is still down by 44.7% from the pre-pandemic rig count….Baker Hughes reported that the total count of rotary rigs running in the US was down by 1 to 438 rigs this past week, which was also down by 27 rigs from the pandemic hit 465 rigs that were in use as of the April 24th report of 2020, and was 1,491 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 was down by 1 to 343 oil rigs this week, after rising by 7 the prior week, leaving us with 35 fewer oil rigs than were running a year ago, and less than 21% 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 94 natural gas rigs, which was up by 9 natural gas rigs from the 85 natural gas rigs that were drilling a year ago, but still just 5.9% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…meanwhile, a rig classified as ‘miscellaneous’ continued to drill in Lake County, California, while a year ago there were two such “miscellaneous” rigs deployed…

The Gulf of Mexico rig count was down by 1 to 11 rigs this week, with 10 of those rigs drilling for oil in Louisiana’s offshore waters and now 1 rig drilling for oil in Alaminos Canyon offshore from Texas…that was 6 fewer Gulf of Mexico rigs than the 17 rigs drilling in the Gulf a year ago, when 16 Gulf rigs were drilling for oil offshore from Louisiana and one rig was drilling for oil in Texas waters…since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week’s national offshore rig totals are equal to the Gulf rig counts…in addition to those offshore, a rig continued to drill through an inland lake in St Mary parish Louisiana, while a year ago there were no rigs deployed on inland waters…

The count of active horizontal drilling rigs was down by 1 to 397 horizontal rigs this week, which was still down by 29 rigs from the 426 horizontal rigs that were in use in the US on April 24th of last year, and less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….at the same time, the directional rig count was also down a rig to 19 directional rigs this week, and those were still down by 4 from the 24 directional rigs that were operating during the same week a year ago….on the other hand, the vertical rig count was up by one to 22 vertical rigs this week, and those were up by 6 from the 16 vertical rigs that were in use on April 24th of 2020….

The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of April 23rd, the second column shows the change in the number of working rigs between last week’s count (April 16th) and this week’s (April 23rd) count, the third column shows last week’s April 16th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 24th of April, 2020..

As you can see, there were just a few changes this week, with most of those in Texas….checking first for the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes, we find that that two rigs were pulled out of Texas Oil District 8, which is the core Permian Delaware, and that rigs in the other Permian basin districts in Texas were unchanged….since the Texas Permian was thus down by 2 this week, that means that the rig that was added in New Mexico must have been targeting the farthest west reaches of the Permian Delaware to accounting for the national loss of just one Permian rig…the only other rig change elsewhere in Texas was offshore platform that had been the state’s waters that was shut down this week, thus accounting for the three rig decrease in Texas…rig activity in other states and other basins was unchanged in one of the slowest week’s we’ve seen in tracking the US rig count..

Ohio anti-fracking activist joins Greta Thunberg to decry fossil fuel subsidies at Earth Day congressional hearing – cleveland.com –A self-described “fracking refugee” from Belmont County, Ohio on Thursday joined Swedish climate activist Greta Thunberg on Earth Day to urge a congressional subcommittee to abandon subsidies to the fossil fuel industry when Congress passes its next infrastructure bill.Jill Antares Hunkler told the House Committee on Oversight and Reform’s environment subcommittee that she was forced from her home at the headwaters of the historically pristine Captina Creek Watershed by oil and gas infrastructure and pollution from a compressor station, 78 fracking wells, a transfer station and an interstate pipeline with numerous gathering pipelines, all within a five-mile radius of her home.She said a 2018 fracking well blowout in Belmont County caused one of the largest methane leaks in U.S. history, forcing area residents to evacuate from their homes, and a brine truck accident contaminated Barnesville’s reservoir with radioactive materials.”The negative health impacts we experienced were too much to bear,” she testified. “First, we noticed the odors and had nose, eye, and throat irritation, as well as headaches. The symptoms worsened over time with nausea, vertigo, rashes, mental confusion, disorientation, numbness, and body aches and pains. True wealth is good health, and our health and happiness suffered as long as we stayed in the hollow.”Since the fracking boom began, she said Belmont and other eastern Ohio counties that produce natural gas have lost more than 6,500 jobs instead of gaining them, and the region’s population has declined. “That’s why there’s little reason to believe that cutting subsidies for the fossil fuel industry will result in lost jobs,” said Hunkler. “And the local oil and gas workers are often the least valued assets of the industry. They are exploited, given the worst, most dangerous, and most often are the least-paid contract jobs without health care and retirement benefits.”

Ohio Official: State Might Have 100,000 Abandoned Oil and Gas Wells – Ohio passed legislation in 2018 that increased funds dedicated to capping oil and natural gas wells with no identifiable owners or that are bankrupt. Under this legislation, the percentage of the oil and natural gas production severance tax for the Orphan Well Program rose from 14 to 30 percent, allowing for 200 wells to be capped each year.But an investigation by Checks and Balances Project (C&BP) shows this doesn’t begin to address the enormous scale of the problem in Ohio. Orphan wells can contaminate ground water and leak methane, a pollutant that remains in the earth’s atmosphere for up to 12 years, trapping heat at a rate 25 times greater than carbon dioxide.”The numbers are so big that it’s not going to be done in my lifetime, my kids’ lifetimes, maybe even my grandkids’ lifetimes,” says Gene Chini, Ohio’s Orphan Wells program manager, in an exclusive interview with C&BP. Chini estimates there could be 100,000 abandoned oil and gas wells in his state.The first well dug to produce oil in Ohio was in Trumbull County’s Mecca Township in 1859, giving the state a 35-year head start over Texas, where the first well struck oil in 1894. The first commercial natural gas well in Ohio began producing in 1884.According to a recent analysis, Texas’s Permian Basin could soon have 20,000 orphan oil and gas wells. But Texas isn’t ground zero for abandoned wells. The crown could belong to Ohio.”We may get more than 200 capped this year. I don’t know,” says Chini. But those 200 will be replaced with an equal number of newly found orphan wells this year.”We’re getting numerous calls weekly. We got 3 today” about previously unknown abandoned wells. “They tend to find us. We take the worst and do them first.”At the current rate, it could take Ohio 500 years to cap all of its orphan wells. And that’s not including the state’s share of the Marcellus and Utica shale gas and oil deposits, which are still in production. “The regulatory structure in Ohio has just not kept up with the industry, which has been developing at rocket speed,” Ted Auch, PhD. of FracTracker told C&BP. When it comes to capping the number of abandoned wells in the state, “the rate at which Ohio has been plugging wells has been declining at a rate of 5% per year since the 90s.”On April 18, benchmark price for a barrel of West Texas Intermediate crude oil was $62.85. The national average price for natural gaswas $9.52 per thousand cubic feet. But Ohio’s severance taxes provide funds to cap polluting orphan wells at a level far below what is needed. For oil, the production severance tax is 10 cents per barrel. For natural gas, the tax is 3 cents per thousand cubic feet. Ernst & Young produced an analysis for the Business Roundtable on Ohio’s severance taxes in 2014. It ranked the state’s taxes near the bottom of producing states, buttressing former Gov. John Kasich’s proposals for a modest increase. But the tax proposals failed in both 2015 and 2017.An Orphan Wells Program spokesperson told Together with Farmers that from 2013-2017, Ohio Dept. of Natural Resources spent just over $1 million, plugging a handful of abandoned wells each year mainly on an emergency basis. In 2017, the numbers rose to $6 million to cap 83 wells. Last year, Chini hired a Texas firm to conduct a magnetic survey using a drone of a property near Findlay in northwestern Ohio. The test found 83 abandoned wells. “We couldn’t see them,” said Chini.

Pennsylvania Operator Acquiring Three Small Appalachian Natural Gas Producers – American Energy Partners Inc. said this week that it would acquire three oil and natural gas producers in western Pennsylvania and West Virginia in a deal valued at nearly $11 million. The Allentown, PA-based company, traded over the counter, said it would acquire 100% of the stock and units of the three undisclosed companies. “This transaction furthers our commitment to acquiring steady cash flowing businesses while enhancing our ability to develop alternative green energy opportunities with the vast amount of acreage included in the package,” said CEO Brad Domitrovitsch. The deal includes 467 wells that are producing 1.25 Bcfe/d and midstream assets scattered across 695 acres of 100%-owned surface and mineral rights. There are no drilling commitments or obligations for the properties. American Energy is the parent company of Hydration Company of PA LLC, American Energy Solutions LLC, Gilbert Oil and Gas, Hickman Geological Consulting LLC and Oilfield Basics LLC. The subsidiaries are largely engaged in water treatment for the industrial and energy sectors. Gilbert is a producer with assets in western Pennsylvania, including more than 1,000 acres of shallow rights in an area of Marcellus and Utica shale development.The company expects to integrate its current upstream and midstream operations into the acquisition, which would boost net reserves by 19 Bcfe. Management also said the transaction is expected to increase annual revenue by $2 million beginning in 3Q2021. The deal is scheduled to close in July.

Energy firm pleads guilty, is fined $2 million in truck emissions tampering scheme – – An energy firm that services the natural gas fields in central and western Pennsylvania has been fined $2 million for 31 violations of the Clean Air Act.U.S. Middle District Judge Matthew W. Brann on Tuesday levied the fine after Rockwater Northeast admitted to the violations. He also imposed a special assessment of $12,500.In a related matter, the government and Select Energy Services Inc., which purchased Rockwater in 2017 in a stock deal, have entered a three-year non-prosecution agreement.Select, a Texas company with more than 2,000 employees that provides water solutions to the oil and gas industry, has paid $2.3 million to the government and agreed to three compliance audits.”We take matters like this very seriously,” said Adam R. Law, the corporate officer who represented Select and Rockwater at the court proceeding.The scheme that led to the Clean Air Act violations involved removing hardware that controlled emissions on 31 heavy-duty diesel trucks used to transport water and wastewater in the Marcellus Shale natural gas fields.Six individuals who worked for or did business with the Rockwater operation based in Canonsburg previously pleaded guilty to charges related to the tampering that occurred between Aug. 1, 2013, and June 30, 2014. They admitted:

• Replacing hardware control devices with exhaust tubing or “straight pipes” that do not limit emissions.
• Removing the hardware control devices from their compartments and then re-welding the entry point to create a false appearance they remained installed.

An estimated 26 tons of nitrous oxide plus particulate matter were released into the air from the trucks with tamper exhaust systems, assistant U.S. Attorney Philip J. Caraballo-Garrison said. The economic benefit to Rockwater through such things as fuel savings, reduced maintenance costs and less downtime was $250,000, he said. All 31 trucks have been taken out of service, Law said. The $250,000 was included in the $2 million fine that was part of a plea agreement. Rockwater was facing a maximum fine of $15.5 million.The company also admitted being responsible for arranging with third parties to issue certificates stating the trucks with disabled onboard diagnostic systems met state inspection standards.

International analysis finds Marcellus best in carbon dioxide intensity –A new report by Rystad Energy, one of the world’s leading energy analysis firms, gives strong marks to the Marcellus and Utica shale producers when it comes to a measure of ESG, environmental, social and governance practices so important these days. Appalachia has the lowest carbon dioxide intensities of any shale basins in the United States with 7.1 kilograms of carbon dioxide per barrel of oil in 2020, according to an analysis by Rystad Energy. It’s slightly ahead of another shale basin, the Haynesville in Louisiana and Texas, which had 7.5 kilograms per barrel of oil. That puts further detail on an emphasis point by many in the local natural gas industry, that not only are the Marcellus shale producers cleaner in that respect than the coal industry but it’s also cleaner in CO2 emissions than any other basin in the United States. The Permian Basin, one of the competitors to the Marcellus, scores a 10.9 and the Bakken in North Dakota, twice that level. And it’s likely to get even better in the years ahead. “Such a level of CO2 intensity performance brings Appalachia to the top quartile among all oil and gas fields globally,” said Rystad Energy Senior Analyst Emily McCain in a prepared statement. “As the basin becomes more mature and modern ESG best practices are implemented, we anticipate Appalachia to improve further in its CO2 intensity dimension in the next three to four years.” Why does the Marcellus and Utica fare so well on this metric? One big reason is that, unlike other shale plays, Marcellus and Utica producers don’t flare natural gas into the open air, a practice that increases emissions. Another, pointed out by Rystad, is that it has built infrastructure and made improvements, like using electric frac fleets, that have reduced diesel and other emissions.

CLIMATE: Largest source of U.S. methane emissions: Appalachian Basin — Friday, April 23, 2021 —The Appalachian Basin is the largest U.S. source of methane, when factoring in the amount of the greenhouse gas released from coal mines, according to a data analysis firm.

Shale gas drillers to keep 2021 capex flat under investor focus, analysts say – Industry observers are expecting shale gas producers to stick to their promise to keep capital spending restrained as investors continue to keep an eye on the sector’s performance. Shale gas drillers have had a history of matching their capital spending to the strength of gas prices, but often when they exceeded guidance, their stock performance dropped as investors walked away, according to S&P Global Market Intelligence data. As the shale gas sector set a combined capital guidance of approximately $5.39 billion for 2021, a decrease from the $6.04 billion actually spent by producers in 2020, the shale gas space saw its stock performance slightly recover, but still remain below the levels achieved in 2016 to 2018. Moody’s in an April 14 research note projected that exploration and production companies will hold their total capital spending flat during the year as they aim to pay down debt, enhance free cash flow and boost shareholder returns – factors which have long since been in the center of investors’ focus, especially after the sweeping capex cuts that occurred in the first half of 2020 due to a sharp drop in oil prices and the impacts of COVID-19. Among the shale gas drillers, Pennsylvania dry gas producer Cabot Oil & Gas Corp. on its fourth-quarter earnings calls has already laid out plans to return more free cash to its shareholders during the year. Meanwhile, fellow Appalachian gas giant EQT Corp. has said that it will keep its 2021 spending flat but will prioritize paying off debt to regain its investment-grade credit rating before sending any cash to shareholders. “Sustained underinvestment together with a gradual recovery in operating cash flow and energy demand will keep oil and gas production volume growth low in 2021,” Moody’s analyst Jonathan Teitel said. Production is forecast to increase merely 3% and investment-grade companies are anticipated to see slightly higher growth compared with speculative-grade producers, Teitel said. “Rig and frac activity levels continue to remain stable as most [exploration and production companies] practice what they preach regarding capital discipline as completion activity for our coverage group is back to nearly 70 after reaching 100+ in early [February] versus as much as 150 early last year. Our data continues to also show fewer rigs now running for our group at 174 recently versus 188 rigs early this year,” Dingmann said. The Marcellus/Utica shale regions are expected to only see an additional one to two rigs, while the Haynesville Shale could see around two to three more rigs by year-end, Goldman Sachs analysts said in a separate April 8 note.

Mass. utilities: Gas plant would allow for more renewables – Massachusetts activists are worried that a natural gas power plant proposed for a largely residential suburb would create new carbon emissions and increase pollution in an already sensitive area. “This is not serving the ratepayers well,” said Sarah Dooling, executive director of the Massachusetts Climate Action Network, which opposes the project. “And it’s not serving the broader climate movement that really is focused on cleaning and greening the grid.” Project participants, however, argue that the new plant will help them meet their legal obligation to ensure enough power is available to the grid, a move that frees them up to add more renewable energy to their portfolios. The argument comes as Massachusetts is receiving widespread praise for the sweeping climate bill Gov. Charlie Baker recently signed into law. At a moment when the state is accelerating its efforts to go carbon neutral by 2050, the debate over this plant highlights broader questions about what role, if any, fossil fuels should play in Massachusetts’ clean energy future. The proposed new plant would be a so-called “peaker,” intended to operate only in times of highest demand, estimated at less than 250 hours per year. The plant would run mostly on natural gas, but would also be able to burn oil as a backup. The plans include a 90-foot smokestack and a natural gas compressor, and the design is described in public filings as “highly efficient.” It would serve a group of municipal power companies – small, local utilities that provide power and sometimes gas to no more than a few towns. Plans for the 55-megawatt facility are being spearheaded by the Massachusetts Municipal Wholesale Electric Company, a nonprofit that helps municipal utilities procure power supply and advocates for their interests. Fourteen of the state’s 41 municipal light departments have signed on to the new plant, though two have since filed requests to be released from their agreements. Opponents have several objections. The intended site for the plant, a parcel of city-owned land in the community of Peabody, is already home to a 60-megawatt power plant, so the new facility could essentially double the pollution potential on the land. The site is also adjacent to a river, close to a public school, and just a few blocks from a neighborhood defined as an environmental justice community. Even running rarely, opponents noted, the plant would add particulate matter to the air and likely increase ozone concentrations in an area that already receives failing grades for ozone pollution from the American Lung Association. The plant is expected to produce about 7,000 tons of carbon emissions each year, roughly equivalent to the pollution emitted by 1,400 average cars. “There’s just so many things that don’t feel right about it,” said Julie Smith-Galvin, a town councilor in Wakefield who is the municipal liaison to the town’s light and gas department. And, in the end, the idea of building a facility that would create any more carbon emissions at this point in the climate crisis just doesn’t sit well with many advocates.

Gas Is the New Coal With Risk of $100 Billion in Stranded Assets – – Natural gas is falling out of favor with emissions-wary investors and utilities at a quicker pace than coal did, catching some power generators unaware and potentially leaving them stuck with billions of dollars of assets they can’t sell. Citigroup Inc. and JPMorgan Chase & Co. are among the banks that strengthened their financing restrictions on thermal coal under pressure from shareholders wanting to avoid the fuel, and the expectation is that gas is next. Executives at some western European companies say they’re already struggling to sell gas-fired facilities. “If you find out somebody who is ready to offer a good price for our gas plants in Spain, then we are ready to sell,” said Jose Ignacio Sanchez Galan, chief executive officer at Iberdrola SA in Spain. “We are not finding people.” The cost of renewables has dropped dramatically during the past decade, making gas-fired stations less competitive. Phasing out gas in power generation is just a first step. Cutting back use of the fuel in heating, transport and industry would wreak more potential damage. Europe wants to reach net-zero emissions by 2050, which is at odds with plans to build numerous infrastructure projects, like pipelines and terminals. If these are built but no longer needed, there’s a potential 87 billion-euro ($104 billion) stranded-asset risk, according to calculations by Global Energy Monitor. In Italy there are plans to build 14 gigawatts of new gas capacity mostly to replace coal, according to Carbon Tracker Initiative Ltd. Europe’s biggest utility, Enel SpA, is a global renewables supermajor. Still, about 40% of the company’s 88 gigawatts of installed capacity is made up of coal, oil and gas, but the Italian company is planning to reduce coal generation by 74% in 2022. Although a gas phase-out is also coming down the track, it has plans to build more capacity. “The important thing is that the direction is clear, it will not change,” Salvatore Bernabei, head of global power generation at Enel said in an interview. “Everyone should understand that we cannot change the world in one day.”Coal has been slow and difficult to phase out in countries where mining provides thousands of jobs. Gas will be quicker because it doesn’t have the same tradition attached, and renewables are now a cost-effective alternative, according to Carbon Tracker. “Gas will be a repeat of coal but quicker,” said Catharina Hillenbrand von der Neyen, head of company research at the London-based firm. “When we look at power generation, you can see that going really, really quickly.” This is already happening in Britain, where it’s unlikely any further large-scale gas plants will be built without technologies that cut emissions – such as carbon capture. SSE Plc, which trades on the U.K.’s FTSE 100 Index, said it can’t see a future for new gas stations that don’t incorporate carbon capture or hydrogen. Electricite de France SA will no longer operate any fossil fuel-fired power generation in Britain after it announced the sale of its last gas-fired power station to private equity firm EIG Global Energy Partners LLC. Historically the involvement of private equity is to squeeze the asset to extract all remaining value.

PIPELINES: 62 groups urge Biden admin to scrap Mountain Valley permits — Thursday, April 22, 2021 — A coalition of 62 environmental and conservation groups are calling on the Biden administration to reverse federal approvals for the contentious Mountain Valley pipeline, claiming that the natural gas project is “inconsistent” with a January executive order signed by President Biden.

60-plus Groups Urge Biden Administration to Suspend Mountain Valley Pipeline Permits | NRDC – More than 60 conservation and environmental groups are calling on top Biden officials to suspend permits and approvals by the previous Trump administration for the controversial Mountain Valley Pipeline, contending it poses a grave threat to clean water, local communities, the environment and the climate. If the administration follows the groups’ recommendations, it could result in blocking construction of the pipeline. “MVP’s construction impacts to date have already caused irreparable harm to landscapes and clean water – West Virginia and Virginia have assessed MVP more than $2 million in penalties for more than 350 environmental violations, mostly related to improper erosion control and stormwater management, and there are allegations of even more,” the groups write in a letter sent today. “Yet there is much more high-risk construction still planned. “All this devastation is completely unnecessary,” they further write. “MVP is one of the last mega-gas pipelines promoted as part of the shale gas boom in our nation – a remnant of a dirty and destructive fossil fuel history that should be left in the past. There has never been any genuine documented need for this pipeline.” The groups urge Biden officials take “aggressive action” to implement an executive order President Biden signed on his first day in office to protect public health and the environment, restore science and tackle climate change. Because the Mountain Valley Pipeline project is inconsistent with the order’s goals, the groups argue, an environmental impact statement and other environmental approvals by the previous administration should be reversed and a pending application for a clean water permit should be closely reviewed. The groups note that the project still has to construct several hundred waterbody crossings; 74 percent of its proposed route would pass through more than 225 miles of high landslide risk terrain. That raises concern of more environmental damage. In addition, if completed and operated, the Mountain Valley Pipeline would add nearly 90 million metric tons of carbon pollution per year to the atmosphere – equivalent to the emissions from 23 U.S. coal plants, or more than 19 million passenger vehicles driven every year. A blog on the MVP by Amy Mall at NRDC (Natural Resources Defense Council) is here: https://www.nrdc.org/experts/amy-mall/biden-can-protect-communities-halt-mountain-valley-pipeline The full text of the letter follows:

Protester who blocked pipeline work in Giles County is charged, jailed -A pipeline protester again briefly blocked work on the Mountain Valley Pipeline early Tuesday, this time in Newport. Alice Elliott, 27, of Ypsilanti, Michigan, spent about four hours suspended from a construction crane that had been left parked overnight in the pipeline’s right of way, while a crowd of supporters gathered nearby. When authorities arrived shortly after 7 a.m., Elliott was positioned about 25 feet off the ground, said Corinne Geller, a spokeswoman for the Virginia State Police. She slipped her arms into a “sleeping dragon” device, which kept her secured to the boom, Geller said. A team of specially trained officers dismantled the lock-box and brought her safely to the ground. Elliott was charged with unauthorized use of the crane, damaging a vehicle, obstructing justice and interfering with the property rights of Mountain Valley. She was being held in lieu of a $1,000 bond Tuesday afternoon, according to Appalachians Against Pipelines. “By locking myself to this equipment, I’m stopping MVP from using it and costing them tons of money, but this is just one form of resistance,” Elliott said in a statement from the group that urged action at all levels. It was the latest in a series of human blockades of the natural gas pipeline since construction began in 2018. Protesters have sat in tree stands and chained themselves to heavy equipment and even a Mountain Valley helicopter in standoffs that usually lasted a day or less.Last month, two tree-sitters were removed from their perches in Montgomery County, ending after about two and a half years what was by far the longest continuing protest. Both are being held without bond pending hearings on criminal charges. They also are scheduled to appear in circuit court, where a judge in a civil case ordered them down last November. A preliminary injunction was sought by Mountain Valley, which says the protests are delaying a project that will deliver needed natural gas to markets along the East Coast.

Army Corps extends Mountain Valley Pipeline comment deadline — The U.S. Army Corps of Engineers has extended by 30 days a public comment period on the Mountain Valley Pipeline’s Clean Water Act permit. The comment period had been set to expire April 28, but environmentalists and others had asked the Army Corps to extend it even further. Now comments will be taken until May 28. MVP, a nearly $6 billion project of Canonsburg-based Equitrans Midstream Corp. (NYSE: ETRN), will connect Marcellus and Utica shale natural gas from the region down through West Virginia and Virginia to markets in the Southeast. It’s several years overdue from construction delays, lawsuits and regulatory review, but Equitrans said as recently as earlier this year that the pipeline will be operational by the end of 2021. The Army Corps water permit, which will allow MVP to do work amid wetlands and streams, is one of the final pieces that Equitrans needs before completing the pipeline. The Corps will look at the impact of the project on wetlands, fish and wildlife and other factors. “That decision will reflect the national concern for both the protection and the utilization of important resources,” the US Army Corps of Engineers Huntington District said in a public notice Friday. One of the groups against the pipeline, Wild Virginia, said 60 days wasn’t enough time. “The information MVP has submitted to the Corps is woefully inadequate, leaving the agency and the public without data and analyses that must inform such an important decision,” said Wild Virginia Conservation Director David Sligh. Sligh also said that the Army Corps should grant Virginia regulators’ request for a year’s extension for it to do its own Clean Water Act permit review. “Wild Virginia and numerous other groups have supported that request, because the Virginia Department of Environmental Quality and State Water Control Board must have necessary time to gather more information and complete a very complicated analysis,” Sligh said. There hasn’t been a ruling on that. The comment period will now be 60 days long, instead of the previous 45.

U.S. natgas rises to 6-wk high on near-record exports, cool weather (Reuters) – U.S. natural gas futures rose to a six-week high on Monday on forecasts for more heating demand this week than previously expected and near-record liquefied natural gas (LNG) and pipeline exports. Front-month gas futures NGc1 rose 6.9 cents, or 2.6%, to settle at $2.749 per million British thermal units, their highest close since March 3. That increase pushed the front-month into overbought territory with a Relative Strength Index (RSI) over 70 for the first time since mid-February. With the front-month up in seven of the past eight trading sessions, speculators last week boosted their net long futures and options positions on the New York Mercantile and Intercontinental Exchanges for the first time in eight weeks. Data provider Refinitiv said gas output in the Lower 48 U.S. states averaged 91.5 billion cubic feet per day (bcfd) so far in April, down from 91.6 bcfd in March. That compares with a record monthly high of 95.4 bcfd in November 2019. Refinitiv projected average gas demand, including exports, would fall from 97.7 bcfd this week to 89.2 bcfd next week as the weather turns seasonally milder. The demand forecast for this week was higher than Refinitiv projected on Friday.

U.S. natgas futures slip as milder weather cuts heating demand (Reuters) – U.S. natural gas futures slipped on Tuesday from a six-week high in the prior session on forecasts for milder weather and lower heating demand over the next two weeks than previously expected. The price decline came despite a dip in output in recent days and ongoing near-record liquefied natural gas (LNG) and pipeline exports. Front-month gas futures NGc1 fell 2.2 cents, or 0.8%, to settle at $2.727 per million British thermal units. On Monday, the contract closed at its highest since March 3. With stockpiles at normal levels and the weather expected to turn seasonally milder, traders said price spikes were unlikely in coming weeks. That helped drive futures at-the-money implied volatility NGATMIV down to 27.5%, its lowest since May 2019. Implied volatility, a determinant of an option’s premium, rose to 115.1% in February during the Texas freeze, its second highest on record. Implied volatility hit a record high of 117.5% in November 2018 due to big changes in winter weather forecasts that caused a rapid increase in prices and the failure and liquidation of commodity trading adviser OptionSellers.com. Volatility hit a record low of 18.6% in April 2019 on mild summer forecasts and a belief that record production at the time would meet any increase in demand and keep prices in check.

Natural Gas Futures Prices Slide Further Ahead of EIA Storage Data; Northeast Cash Rallies – Natural gas futures continued to peel back midweek as production ticked higher and export demand retreated. Staring down a softer storage injection week/week, traders sent the May Nymex futures contract down another 3.5 cents to $2.692. June slipped 2.7 cents to $2.7 Spot gas prices also declined across most of the country, but dollar-plus gains in the Northeast helped to lift NGI’s Spot Gas National Avg. up 4.0 cents to $2.690.Though the weather data has maintained a chilly outlook through April 27, the warm-up expected thereafter may be starting to pressure prices. NatGasWeather said the midday Global Forecast System weather model was a little chillier later this weekend and early next week as cool air is expected to linger across the northern United States slightly stronger and longer. However, the latest data held onto the “slightly bearish” pattern April 27-May 5.An uptick in the latest production data amid a slate of springtime pipeline maintenance, along with slightly lower liquefied natural gas (LNG) feed gas demand also influenced price behavior.On the production front, output took a dramatic decline last weekend, according to Wood Mackenzie. The firm said output fell from 92.1 Bcf/d on April 16 to 90.3 Bcf/d on Monday and then to a recent low of 89.4 Bcf/d on Tuesday.Most of the decline in output was attributed to the Northeast, where Southwest Pennsylvania (SWPA) production dropped by 0.8 Bcf/d to 7.1 Bcf/d on Tuesday. The receipt points responsible for the decreased receipts were gathering system interconnects in Greene County.

US natural gas storage volumes increase nearly in line with five-year average | S&P Global Platts -US natural gas storage fields added 38 Bcf, just above an S&P Global Platts survey calling for a 37 Bcf gain, for the week ended April 16 as the remaining Henry Hub summer strip continues its recent climb. Storage inventories increased 38 Bcf to 1.883 Tcf for the week-ended April 16, the US Energy Information Administration reported April 22. The build barely missed the 37 Bcf addition expected by an S&P Global Platts survey of analysts, as well as the five-year average build of 37 Bcf, according to EIA data. The injection measured well below the 61 Bcf build reported for the week prior, in part due to lower total US supply. The decline was mainly centered on an unexpected fall in production in the Southeast and Texas regions. Production in Texas alone fell by nearly 500 MMcf/d for the second week in a row, while Southeast output shed roughly 350 MMcf/d, according to Platts Analytics. Downstream demand lurched higher across all sectors, with residential and commercial, industrial and power burn rising by more than 2 Bcf/d, while exports to Mexico rose by 1 Bcf/d. Storage volumes now stand 251 Bcf, or 11.8%, less than the year-ago level of 2.134 Tcf and 12 Bcf, or 0.6%, more than the five-year average of 1.871 Tcf. The NYMEX Henry Hub May contract added 6 cents to $2.76/MMBtu in trading following the release of the weekly storage report. The bullishness extended across the balance of summer as prices through October 2021 have risen by an average 6 cents. S&P Global Platts Analytics’ supply and demand model currently forecasts a meager 1 Bcf injection for the week ending April 23, which would measure 66 Bcf less than the five-year average. Demand has seen large gains, particularly from the residential and commercial sector as colder weather is driving home heating demand, reversing seasonal declines in some areas. Meanwhile, power burn growth has continued, albeit at a slower pace than the week ended April 16, with demand from the power sector increasing by 700 MMcf/d week over week, or roughly half the rate from a week earlier. The shift was driven by a blast of colder-than-normal temperatures across most of the US, which pushed up residential and commercial demand estimates in the three largest demand regions of the East, South Central and Midwest.

Natural-gas prices turn higher; EIA reports a 38 billion cubic foot rise in U.S. natural-gas supplies -The U.S. Energy Information Administration reported on Thursday (link) that domestic supplies of natural gas rose by 38 billion cubic feet for the week ended April 16. That just about matched an average increase of 37 billion cubic feet forecast by analysts polled by S&P Global Platts. Total stocks now stand at 1.883 trillion cubic feet, down 251 billion cubic feet from a year ago but 12 billion cubic feet above the five-year average, the government said. Following the data, May natural gas was up 4.3 cents, or 1.6%, to $2.74 per million British thermal units. It traded at $2.69 shortly before the data (link).

U.S. natgas eases from 7-week high on milder weather forecasts (Reuters) – U.S. natural gas futures eased on Friday from a seven-week high in the previous session on forecasts for the weather to moderate over the next two weeks. That small decline came despite a smaller-than-expected storage build, record exports and small declines in production. Traders also noted that colder-than-normal weather this week boosted heating demand by so much that utilities could take the unusual step of pulling gas from storage. The last time utilities pulled gas from storage in April was in 2018. Front-month gas futures NGc1 fell 1.9 cents, or 0.7%, to settle at $2.730 per million British thermal units. On Thursday, the contract closed at its highest since March 3. For the week, the front-month was up about 2% after rising 6% last week. Data provider Refinitiv said gas output in the Lower 48 U.S. states averaged 91.4 billion cubic feet per day (bcfd) so far in April, down from 91.5 bcfd in March. That compares with a record monthly high of 95.4 bcfd in November 2019.

Al Gore: Stop the reckless, racist pipeline in Southwest Memphis – On Tuesday, when the Memphis City Council votes on an ordinance to protect the city’s pristine water supply, it will be choosing between the future health and well-being of Memphis and the future profits of two Texas oil companies trying to seize the property of Black citizens in Southwest Memphis to transport $9 billion of crude oil per year from the fracking fields in Texas to tankers in Louisiana for export.There are three reasons why the Council should vote to protect Memphis’s people and drinking water, despite the objections of the pipeline companies: (1) it is reckless; (2) it is racist; and (3) it is a rip-off.First, it is reckless to bury a huge high-pressure oil pipeline directly over the crown jewel of the city: the Memphis Sand Aquifer, one of the purest aquifers in the world and the sole source of drinking water for all of Memphis. Incredibly, they also want to tunnel directly through a vulnerable “wellfield zone” – one of several places where the protective clay layer above the aquifer is breached and the aquifer especially vulnerable to contamination. A spill there would be utterly catastrophic. Moreover, the region stretching from Memphis to New Madrid, Missouri, is the most dangerous earthquake zone east of the Rocky Mountains. Three of the largest earthquakes in U.S. history hit here early in the 19th Century – ringing church bells in Boston. As a Senator representing Memphis 30 years ago, I held hearings on the risk of another big quake here. The seismologists said it’s a matter of when, not if. Meanwhile, Valero’s large refinery is already the worst source of toxic air pollution in Shelby County, with most of the pollution carried into Southwest Memphis. Last year, Valero spilled 800 gallons of crude oil near the planned route of the Byhalia pipeline.These companies’ assurances of safety would be laughable if their records were not so dangerous. Second, it is racist because the proposed route intentionally snakes through the 97% Black communities of Southwest Memphis, where residents are already suffering a horribly disproportionate and dangerous level of pollution and a cancer rate four times the national average. It is a textbook example of environmental injustice. When the companies were asked why they chose this route, they said Southwest Memphis was “the point of least resistance.”The two oil companies pushing this reckless project – Valero and Plains All-American – have both been charged for their reckless negligence. In 2015, a Plains pipeline ruptured in California, spreading oil over nine miles of the Santa Barbara coast. Plains has also been prosecuted for 10 other pipeline spills in four states and in Canada for one of the largest ground-based oil spills in the history of North America.

Memphis holds back Byhalia Pipeline, water protection ordinance – The Memphis City Council pressed pause on its legislative opposition to the Byhalia Connection Pipeline.The council held off voting on an ordinance that would create expanded regulations for any sort of development that could affect Memphis’ drinking water supply and cross a Memphis, Light, Gas, and Water wellfield, including, potentially, the pipeline. The ordinance was due for a third and final reading Tuesday before the delay. The ordinance would require the Memphis City Council’s public works committee to approve any piece of infrastructure that handles materials that are deemed hazardous and could affect the city’s drinking water supply. Memphis draws its water from the Memphis Sand aquifer and there has been broad concern over whether the pipeline, if it ruptured, would harm the aquifer. Local and national advocates against the pipeline, including former Vice President Al Gore, have described the pipeline’s route through historically Black neighborhoods within Memphis city limits as environmental racism. Councilman Jeff Warren and Councilman Edmund Ford Sr., the sponsors of the ordinance, asked for at least a two-week delay to further fine-tune the measure. The council agreed to delay the vote.Warren said he wanted the delay after Memphis Chief Legal Officer Jennifer Sink, the city’s top lawyer, asked him for one. Ford expressed concern about potential lawsuits.

Memphis Mayor Jim Strickland opposes Byhalia pipeline in Tennessee, Mississippi – As an “unacceptable risk” to the Memphis Sand aquifer, Mayor Jim Strickland said Tuesday he will support local efforts to regulate the proposed Byhalia pipeline, “after careful review and detailed conversations with environmental scientists” by his administration. The statement also urges state and federal agencies to thoroughly evaluate the Byhalia Pipeline proposal with more scrutiny. “I have great concerns that the Byhalia Pipeline would pose an unacceptable risk to our Aquifer. The risk of a leak in the pipeline is real, and any leak is likely to cause harm to the Aquifer. It’s a risk we should not take,” Strickland wrote in a statement a city official said Memphis City Council received Tuesday. The Public Works committee delayed voting for two weeks Tuesday on an ordinance that aims to address the risk of contamination opponents of the crude oil project say it poses to the Memphis Sand aquifer, which supplies drinking water to residents throughout Shelby County. Regarding several permits under consideration for the proposed pipeline to cross city streets, Strickland wrote, “We are not proceeding with those until we have a handle on our legal authority over the pipeline; therefore, a stay can be enforced, in part, by our holding those permits in abeyance.” “Memphians deserve to have their drinking water protected,” Strickland said. Legality of ordinance to protect public health, environment challenged The ordinance would require new underground infrastructure projects to meet three criteria, according to attorney George Nolan of the Southern Environmental Law Center. “Number one, it’s not going to hurt the aquifer. Number two, it’s not going to disproportionately penalize neighborhoods that have been treated unfairly in the past. And three, it’s not going to risk bankrupting the city,” Nolan said. Plains All American Pipeline, which seeks to build the 49-mile pipeline in partnership with the Valero Energy Corp., has not addressed three inquiries from The Commercial Appeal regarding whether the company has full remediation liability insurance coverage in the event of a spill requiring groundwater clean-up. “Protecting the aquifer and the drinking water supply, which is so important to this community, is something we take very seriously,” Plains spokesperson Katie Martin said Friday. Introducing lawyer Robert Spence Tuesday, she told council members members Plains wanted “to have a frank conversation about what we think this ordinance means for Memphis.”

Company asks for pause in Memphis oil pipeline dispute (AP) – A company facing resistance to its plans to build an oil pipeline over an aquifer that provides drinking water to 1 million people has asked for a “mutual pause” in its dispute with city officials in Memphis, Tennessee. Plains All American Pipeline sent a letter to the Memphis City Council about a proposed city law that could make it harder to construct an underground oil pipeline through wetlands and neighborhoods in south Memphis and north Mississippi. Plains is part of a joint venture with Valero Energy to build the Byhalia Connection, which would link the Valero refinery in Memphis with another larger pipeline in north Mississippi. The council’s ordinance would establish a board to approve or deny construction of underground pipelines that transport oil or other potentially hazardous liquids near wells that pump millions of gallons of water daily from the Memphis Sand Aquifer. The ordinance is backed by pipeline opponents who fear an oil spill would endanger the aquifer. The council made no mention of the Plains letter during a vote Tuesday to delay a vote on the ordinance for two weeks. Councilors said they decided to postpone a decision so they could address questions they themselves had and allow input from the mayor’s office and the local water company. In the letter, Plains said Byhalia Connection is willing to suspend development activities and address city council and community concerns “if the City is willing to suspend consideration, adoption, or final reading of the existing or any new ordinance that could affect the pipeline or refinery.” “We very much appreciate your willingness to talk with us and receive our feedback and work to resolve any differences,” the letter said. “It’s in this light that we would like to propose a ‘mutual pause.'” Byhalia has threatened to sue if the ordinance passes. In a statement, project spokeswoman Katie Martin called the proposed law “an example of ill-conceived local government overreach that is preempted by state and federal law.”

Pavilion Energy Imports Carbon Neutral LNG Cargo –Pavilion Energy Singapore Pte. Ltd. has announced that it has imported a carbon neutral LNG cargo into Singapore, a first for the company and the country, Pavilion Energy highlighted.Carbon emissions associated with the LNG cargo from well to tank – including the extraction, production, transportation, and regasification – will be offset by retiring a corresponding amount of carbon credits sourced from the company’s portfolio of carbon offset projects, Pavilion Energy revealed.The carbon credits used for the offset are from Natural Climate Solutions projects certified under the Verified Carbon Standard (VCS) and Climate, Community and Biodiversity Standard (CCB), Pavilion Energy noted. The projects – Evio Kuinaji Ese’Eja Cuana in Peru and Liangdu Afforestation in China – focus on the protection and restoration of forests and promote co-benefits through supporting local communities and protecting biodiversity, the company outlined. “This carbon neutral cargo is another important milestone for Pavilion Energy in our ambition to provide cleaner energy and develop our carbon trading activities,” Frederic H. Barnaud, the group chief executive officer of Pavilion Energy, said in a company statement.

Lt. Gen. Honore on Seacor Power capsize – The Seacor Power remains capsized off the coast of Louisiana, more than a week after the commercial lift boat turned over in rough seas. Of the 19 crew members, six were rescued and the rest are dead or still missing. It’s the worst marine disaster in the Gulf of Mexico since the explosion on the Deepwater Horizon oil rig 11 years ago to the day on Tuesday. That explosion resulted in 11 deaths and an oil spill which lasted 87 days. Retired Army General Russel Honore says the Seacorp Power accident gives him a sense of deja vu. “Let me get to the bottom line, we have a problem in Louisiana with safety when it comes to the oil and gas business,” Honore said. “Anything is okay. Here we have in 11 years, two of the biggest accidents in the gulf off the coast of Louisiana.” Honore helped restore order in New Orleans following Hurricane Katrina in 2005. He was back in the city to speak at a BP oil spill anniversary event. “Here we are, we’ve got these dangerous pieces of equipment, working oil and gas that operate at the will of the company,” Honore said. Monday, Seacor Marine CEO John Gellert said the “go/no-go decision” for the vessel to depart Port Fourchon in bad weather was “entirely the captain’s.” “The captain has full control of the vessel,” Gellert said. “The vessel is owned by Seacor Marine, under the control of Seacor Marine. He had our support for his decision to sail.” Honore suspects the crew may have been pressured to get underway. “Let’s look at how it looked to that captain with the CEO sitting in his air-conditioned building in Texas,” Honore said. “We need to get this boat out there. You all do what you all can.” Honore, an environmental crusader since leaving the Army, is once again calling for better government oversight of vessels and drilling platforms operating in the gulf. He is also urging the National Transportation Safety Board to recommend a Captain of the Port be appointed at Port Fourchon. That official would have the power to tell boat captains when it’s too dangerous to set sail.

GAO raises concerns about government inspections of offshore pipelines –A report from the Government Accountability Office (GAO) says that the federal government lacks “robust” processes to both ensure the integrity of active offshore pipelines and to deal with inactive ones that have been left on the seafloor. The nonpartisan congressional watchdog found that the Bureau of Safety and Environmental Enforcement (BSEE) does not generally conduct or require inspections for active undersea pipelines, and also said that safety devices are not always reliable. It said that the agency has worked with industry on new technology, but that there are limits on its use. On inactive pipelines, the watchdog also found that BSEE doesn’t adequately account for safety and environmental risks for applications to decommission the vessels and has allowed 97 percent of all pipeline mileage to be left on the seafloor. Specifically, the bureau doesn’t fully weigh whether pipelines are “hazards to navigation and commercial fishing operations, unduly interfere with other uses of the [outer continental shelf] or have adverse environmental effects,” the report said. It also said that the agency doesn’t ensure that companies that operate the pipelines meet standards for decommissioning them and that it also doesn’t monitor their condition or location. “The business model of drilling our oceans for a quick buck and sticking the public with the cleanup bill is coming to an end,” House Natural Resources Committee Chairman Raul Grijalva (D-Ariz.) said in a statement on the report. “Our oceans are there for all of us, not just oil and gas companies, and if they can’t behave responsibly on their own, this Congress will be happy to step in and set some overdue boundaries,” Grijalva added.

U.S. Needs to Better Monitor Oil, Gas Pipelines in Gulf of Mexico, Report Says – WSJ – Federal officials aren’t adequately monitoring the integrity of 8,600 miles of active oil-and-gas pipelines on the Gulf of Mexico’s seafloor, and for decades have allowed the industry to abandon old pipelines with little oversight, a new report to Congress shows. The Government Accountability Office report faults the Interior Department’s offshore oil-safety regulator’s reliance on surface observations and pressure sensors, rather than subsea inspection, to monitor for leaks. The agency’s own staff acknowledges those techniques could fail to detect a slow discharge from a pipeline over a long period, particularly in deep water where most oil production occurs, the report says. The report urges the regulator, the Bureau of Safety and Environmental Enforcement, to resume work on a long-stalled update to pipeline rules. BSEE currently requires monthly inspections of pipeline routes in the Gulf by helicopter or marine vessel, to look for oil sheens or gas bubbles on the surface to determine whether a pipeline is leaking. By comparison, the bureau’s Pacific office requires subsea pipeline inspections, in part because of seismic concerns, on its much smaller network of 200 miles of active pipelines. In interviews with the GAO, BSEE officials acknowledged that “surface observations are not generally reliable indicators of pipeline leakage,” because diffused leaking oil and gas can move far from the source, especially in deep water. “BSEE officials told us that industry has been largely receptive to improving leak detection but noted that the bureau cannot compel industry to take any action to detect leaks that is not described in its regulations,” the report said. An Interior Department official, responding in the GAO report, said the department “generally agrees with the report findings” and that it is following the GAO’s urging to draft new rules governing offshore pipelines. The GAO also found that BSEE and its predecessors allowed the oil industry to leave thousands of miles of decommissioned pipelines on the seafloor rather than incur the cost of raising them back to the surface. Federal regulations allow BSEE to permit operators to decommission pipelines in place, cleaning and burying them in the seabed. The GAO found that the agency doesn’t ensure standards are followed, even as it allowed 97% of the miles of decommissioned pipelines taken out of active use in the Gulf since the 1960s – nearly 18,000 miles – to remain in place. BSEE also has failed to fully consider whether decommissioned pipelines represent a hazard to navigation and commercial fishing, like trawlers that can be damaged by snagging equipment on undersea pipelines, the report said. Eighty-nine trawlers reported damage from snagging on oil-and-gas equipment between 2015 and 2019, the report found. BSEE’s failure to inspect decommissioned pipelines also means officials don’t have a complete record of which equipment has been properly cleaned and buried, or whether hurricanes and underwater landslides have moved buried pipelines, potentially creating navigation hazards and environmental damage. A buried 9-mile pipeline segment was swept 4,000 feet out of place by Hurricane Katrina, the report said. ‘The business model of drilling our oceans for a quick buck and sticking the public with the cleanup bill is coming to an end.’ BSEE also allowed oil producers to leave in place some 250 decommissioned “umbilical lines” that carry electricity and hydraulic power to subsea equipment, the report said, over objections of some Interior officials who were concerned that these lines often contain hazardous chemicals that could leak over time as the equipment degrades. BSEE officials told the GAO they authorized those placements based on guidance from the Environmental Protection Agency during the Trump administration, which championed the oil industry.

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