Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 07 August 2021. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.
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Oil prices fall most in ten months; natural gas price hits 31 month high; gasoline supplies at 39 week low
Oil prices saw their greatest drop in 10 months this week, as US crude inventories rose unexpectedly and rising Covid cases prompted economic restrictions worldwide…. after rising 2.6% to $73.95 a barrel last week as crude, gasoline, and distillates supplies all fell more than had been expected, the contract price of US light sweet crude for September delivery fell early on Monday after a Chinese survey showed that growth in factory activity slipped sharply in the world’s largest oil importer, and continued to tumble more than 4% before recovering to settle $2.69 lower at $71.26 a barrel, as the fast-spreading delta variant posed a threat to demand and as higher crude output from OPEC producers stoked fears of oversupply…oil prices were down another 3% early Tuesday as the resurgence in Covid cases globally driven by the Delta variant fuelled concerns that restrictions on economic activity might be reimposed, but recovered from the worst levels after news of a “potential hijack” of a tanker in the Gulf of Oman to close down 70 cents or less than 1% lower at $ $70.56 a barrel, after sources said preliminary data suggested US crude stocks were lower for the week….however, oil prices dipped again after the API reported a disappointingly small crude inventory draw and then extended those losses after the EIA reported an unexpected crude inventory increase, and ultimately fell $2.41 or again more than 3% to $68.15 a barrel, as the spread of the coronavirus Delta variant outweighed the impact of new Mideast geopolitical tensions….oil prices were up Thursday morning in Asia, even as traders were surprised by the build in U.S. crude oil supply, as prices were still supported by ongoing tensions in the Middle East and then moved higher in New York trading, rising on the tailwind of strong equity markets to break the three day losing streak and close 94 cents higher at $69.09 a barrel, while gains were capped as fresh restrictions to counter a surge in COVID-19 cases threatened the global energy demand recovery.…prices continued to rise early Friday and were up more than 1% early on, gaining support from rising tensions between Israel and Iran, but reversed by the same percentage to settle Friday’s trade down 81 cents, or 1.2%, at $68.28 per barrel, tumbling as the dollar jumped on a strong U.S. jobs report, raising questions about the continuance of the Fed stimulus that had underpinned the markets and the economy…with that, oil prices ended the week 7.7% lower, capping the biggest weekly loss since October, as the spread of the delta coronavirus variant in China and elsewhere in the world cast doubts on demand growth…
Natural gas prices, on the other hand, rose on forecasts for hotter weather and on low supplies for this time of year….after falling 3.2% to $3.914 per mmBTU last week on signs that the long heat wave was finally breaking, the contract price of natural gas for September delivery rose 2.1 cents to $3.935 per mmBTU on Monday as forecasts predicted hotter weather and greater demand for cooling over the coming weeks than had been previously expected…a drop in production drove natural gas prices higher for a second day on Tuesday, with gains accelerating after the latest weather models turned even hotter for next week, as September gas settled 9.2 cents higher at $4.027 per mmBTU…natural gas prices then climbed over 3% to a 31-month high on Wednesday, rising 13.1 cents to $4.158 per mmBTU, as traders anticipated what was forecast to be the smallest addition to inventories of the summer…however, natural gas prices retreated 1.8 cents to $4.140 per mmBTU on Thursday, even though the government storage data was about as bullish as it could be, as weather models showed the upcoming heat would be a little less intense…although prices remained volatile on Friday, they finished unchanged at $4.140 per mmBTU as growing supply concerns offset a slightly cooler shift in the latest weather forecasts, but still ended 5.8% higher on the week…
The natural gas storage report from the EIA for the week ending July 30th indicated that the amount of natural gas held in underground storage in the US rose by 13 billion cubic feet to 2,727 billion cubic feet by the end of the week, which left our gas supplies 542 billion cubic feet, or 16.6% below the 3,269 billion cubic feet that were in storage on July 30th of last year, and 185 billion cubic feet, or 6.4% below the five-year average of 2,912 billion cubic feet of natural gas that have been in storage as of the 30th of July in recent years…the 13 billion cubic feet increase in US natural gas in storage this week was 4 billion cubic feet below the median forecast for a 17 billion cubic foot addition from a S&P Global Platts survey of analysts, and less than half of the average addition of 32 billion cubic feet of natural gas that have typically been injected into natural gas storage during the same week over the past 5 years, and also less than half of the 32 billion cubic feet that were added to natural gas storage during the corresponding week of 2020…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending July 30th indicated that after a sizable decrease in our oil exports and a modest decrease in our oil production, we had surplus oil to add to our stored commercial crude supplies for the second time in eleven weeks, and for the 13th time in the past thirty-eight weeks….our imports of crude oil fell by an average of 75,000 barrels per day to an average of 6,432,000 barrels per day, after fallng by an average of 590,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 585,000 barrels per day to an average of 1,904,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 4,528,000 barrels of per day during the week ending July 30th, 510,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was reportedly unchanged at 11,200,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to total an average of 15,728,000 barrels per day during this reporting week…
US oil refineries reported they were processing 15,920,000 barrels of crude per day during the week ending July 30th, 46,000 more 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 average of 518,000 barrels of oil per day were being added to the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports and from oilfield production was 711,000 barrels per day less than what was added to storage plus what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a (+711,000) 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 omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed….since last week’s EIA fudge factor was at (+73,000) barrels per day, that means there was a 638,000 barrel per day balance sheet difference in the crude oil fudge figure from a week ago, thus rendering the week over week supply and demand changes indicated by this report pretty useless….however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as they’re published, just as they’re watched & believed to be reasonably accurate by most everyone in the industry….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,564,000 barrels per day last week, which was 15.8% more than the 5,666,000 barrel per day average that we were importing over the same four-week period last year…the 518,000 barrel per day net increase in our crude inventories was all added to our commercially available stocks of crude oil, while the quantity of oil stored in our Strategic Petroleum Reserve remained unchanged….this week’s crude oil production was reported to be unchanged at 11,200,000 barrels per day because the EIA”s rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day lower at 10.800,000 barrels per day, while a 29,000 barrel per day increase in Alaska’s oil production to 342,000 barrels per day caused 100,000 barrels per day to be added to the rounded national production total (that’s the EIA’s math, not mine)….US crude oil production had hit a pre-pandemic record high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 14.5% below that of our production peak, but 32.9% above the interim low of 8,428,000 barrels per day that US oil production had fallen to during the last week of June of 2016…
Meanwhile, US oil refineries were operating at 91.3% of their capacity while using those 15,920,000 barrels of crude per day during the week ending July 30th, up from 91.1% of capacity the prior week, but still somewhat below normal for summertime operations…while the 15,920,000 barrels per day of oil that were refined this week were 8.8% higher than the 14,637,000 barrels of crude that were being processed daily during the pandemic impacted week ending July 31st of last year, they were still 10.4% below the 17,777,000 barrels of crude that were being processed daily during the week ending August 2nd, 2019, when US refineries were operating at what was then a seasonally normal 96.4% of capacity…
With this week’s increase in the amount of oil being refined, the gasoline output from our refineries was also higher, increasing by 372,000 barrels per day to 10,151,000 barrels per day during the week ending July 30th, after our gasoline output had increased by 649,000 barrels per day over the prior week…while this week’s gasoline production was 9.2% higher than the 9,300,000 barrels of gasoline that were being produced daily over the same week of last year, it was still 2.6% lower than the gasoline production of 10,421,000 barrels per day during the week ending August 2nd, 2019….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 138,000 barrels per day to 4,877,000 barrels per day, after our distillates output had decreased by 163,000 barrels per day over the prior week…but after 5 straight decreases before that increase, this week’s distillates output was 0.7% less than the 4,909,000 barrels of distillates that were being produced daily during the week ending July 31st, 2020, and 7.7% below the 5,286,000 barrels of distillates that were being produced daily during the week ending August 2nd, 2019..
Even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the seventh time in eighteen weeks, and for the 17th time in thirty-eight weeks, falling by 5,291,000 barrels to a nine month low of 228,870,000 barrels during the week ending July 30th, after our gasoline inventories had decreased by 2,253,000 barrels over the prior week...our gasoline supplies decreased by more this week because the amount of gasoline supplied to US users increased by 450,000 barrels per day to 9,775,000 barrels per day, and because our imports of gasoline fell by 64,000 barrels per day to 845,000 barrels per day while our exports of gasoline fell by 93,000 barrels per day to 716,000 barrels per day…after this week’s inventory decrease, our gasoline supplies were 7.6% lower than last July 31st’s gasoline inventories of 247,806,000 barrels, and about 3% below the five year average of our gasoline supplies for this time of the year…
Along with the increase in our distillates production, our supplies of distillate fuels increased for the sixth time in seventeen weeks and for the 18th time in 33 weeks, risng by 832,000 barrels to 138,744,000 barrels during the week ending July 30th, after our distillates supplies had decreased by 3,088,000 barrels during the prior week….our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 738,000 barrels per day to 3,618,000 barrels per day, even while our exports of distillates rose by 290,000 barrels per day to 1,302,000 barrels per day, and while our imports of distillates fell by 26,000 barrels per day to 162,000 barrels per day…but after eleven inventory decreases over the past seventeen weeks, our distillate supplies at the end of the week were still 22.9% below the 179,977,000 barrels of distillates that we had in storage on July 31st, 2020, and about 6% below the five year average of distillates stocks for this time of the year…
Finally, with the big decrease in our oil exports, our commercial supplies of crude oil in storage rose for tenth time in the past twenty-four weeks and for the 25th time in the past year, increasing by 3,627,000 barrels over the week, from 435,598,000 barrels on July 23rd to 439,225,000 barrels on July 30th, after our commercial crude supplies had decreased by 4,089,000 barrels the prior week….after this week’s increase, our commercial crude oil inventories were still about 6% below the most recent five-year average of crude oil supplies for this time of year, but were 30.2% above the average of our crude oil stocks as of the end of July over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories had jumped to record highs during the Covid lockdowns of last spring and remained elevated thereafter, our commercial crude oil supplies as of this July 30th were still 15.3% less than the 518,596,000 barrels of oil we had in commercial storage on July 31st of 2020, but are now a bit more than the 438,930,000 barrels of oil that we had in storage on August 2nd of 2019, and 7.8% more than the 407,389,000 barrels of oil we had in commercial storage on August 3rd of 2018…
This Week’s Rig Count
The number of drilling rigs active in the US increased for the 39th time out of the past 46 weeks during the week ending August 6th, but was still down by 38.1% from the pre-pandemic rig count….Baker Hughes reported that the total count of rotary rigs running in the US increased by three to 491 rigs this past week, which was also up by 244 rigs from the pandemic hit 247 rigs that were in use as of the August 7th report of 2020, but was still 1,438 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, a week before OPEC began to flood the global oil market in an attempt to put US shale out of business….
The number of rigs drilling for oil was up by 2 to 385 oil rigs this week, after falling by 2 oil rigs the prior week, and it’s now 211 more oil rigs than were running a year ago, while it’s less than a quarter 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 103 natural gas rigs, which was still up by 34 natural gas rigs from the 69 natural gas rigs that were drilling during the same week a year ago, but still just 6.4% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….in addition to oil and gas rigs, a horizontal rig that Baker Hughes classifies as “miscellaneous’ began drilling in Kern county California, the site of 3 oil wells, this week…that’s the first “miscellaneous’ rig deployment since May 14th, while a year ago there were no such “miscellaneous’ rigs active…
The Gulf of Mexico rig count was unchanged at 14 rigs this week, with 13 of those rigs drilling for oil in Louisiana’s offshore waters and one drilling for oil offshore from Texas….that was still two more rigs than the 12 rigs that were drilling in the Gulf a year ago, when 9 Gulf rigs were drilling for oil offshore from Louisiana and three were deployed for oil in Texas waters….since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week’s national offshore rig totals are equal to the Gulf rig count… in addition to those rigs offshore, we continue to have a rig drilling through an inland body of water in Terrebonne Parish of southern Louisiana, whereas there were no such “inland waters” rigs running a year ago…
The count of active horizontal drilling rigs was up by 7 to 449 horizontal rigs this week, which was more than double the 211 horizontal rigs that were in use in the US on August 6th of last year, but was 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 to 27 directional rigs this week, but those were still up by 3 from the 24 directional rigs that were operating during the same week a year ago….in addition, the vertical rig count was also down by 2 to 15 vertical rigs this week, but those were also up by 3 from the 12 vertical rigs that were in use on August 7th 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 August 6th, the second column shows the change in the number of working rigs between last week’s count (July 30th) and this week’s (August 6th) count, the third column shows last week’s July 30th 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 7th of August, 2020..
It’s not obvious from those tables how 7 horizontal rigs could have been added this week, but the 3 rigs added in Wyoming might offer a clue…checking the North America Rotary Rig Count Pivot Table at Baker Hughes (xls) we find rigs drilling 15 oil wells and one natural gas well in the state, with just 3 vertical oil rigs and only 3 rigs in the Niobrara chalk…comparing that to the prior week, we find that 6 horizontal and single vertical rig that had been drilling in the Powder Rver basin in Converse county saw no change, but that there was a new horizontal oil well being drilled Sublette county, which would be in the Green River basin, that there was a horizontal rig added in the Niobrara chalk in Laramie county, and that there was also a shallow vertical oil rig start up in Natrona county, which would be in the Powder River basin….meanwhile, the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes shows that two rigs were pulled out of Texas Oil District 8, which is the core Permian Delaware, but that two oil rigs were added in Texas Oil District 8A, which encompasses the northern counties of the Permian Midland, while another oil rig was being pulled out from Texas Oil District 7B, which includes a far eastern county of the Permian Midland…hence,Texas saw a one rig decrease in the Permian this week, and since the national Permian count was unchanged, that means that the rig that was added in New Mexico must have been set up to drill in the far west reaches of the Permian Delaware in that state…elsewhere in Texas, was no change in the rig deployment in Texas Oil District 10, that means that the rig that was added in the Granite Wash basin almost had to have been added in nearby Oklahoma…note that all that activity we’ve just noted represents oil well drilling; there were no changes among natural gas rigs this week…
Radioactive, for 1600 years – – It might be that it’s just not something people want to think about. But the fact is radioactive waste from fracking getting shipped to loosely regulated landfills in Ohio has the potential to poison the environment for 1,600 years. Despite efforts from environmental organizations to educate the public about the radioactive risks created by the boom in shale gas fracking since the early 2000s, some Ohioans remain unaware that it is piling up, in many cases, in their own backyards. Sil Caggiano, senior battalion chief for the Youngstown Fire Department, blames the lack of awareness on the state’s protection of the industry. “It’s the third rail of politics here in Ohio,” Caggiano said. “You don’t screw with the fracking.” Caggiano contends his fellow first responders and civilians are not being given the knowledge owed to them by the Emergency Planning and Community Right-to-Know Act, also known as SARA Title III. The act requires that states “organize, analyze and disseminate information on hazardous chemicals to local governments and the public.” The lack of transparency, according to Caggiano, puts him and fellow first responders in danger. They have no way to navigate industry-related incidents, like spills and explosions, when they don’t know what to test for or what they might be getting exposed to during emergency calls. Cagginao is wary of the industry’s money and power to buy “experts” and politicians. When it comes to influencing public opinion, he thinks the industry is nearly impossible to compete with in a fair or responsible manner. “If you bring in some guy who tries to tell you that the radium in the brine tanks is no worse than the radioactive potassium of bananas, people believe it because some guy who got paid and has got a Ph.D. said it,” Caggiano said. Previous reporting from Public Herald has shown that health risks related to fracking waste exposure do in fact exist – it’s not bananas. The industry, though, with help from the state, has chosen to downplay or ignore risks to both workers in the fracking industry and locals who live near oil and gas sites, treatment plants and sewage systems. Radioactive elements, such as radium-226, emit alpha particles that can become airborne as dust, drift through the air or be blown about by the wind to be inhaled or ingested. Once inside the human body, an alpha particle’s explosive charge can shred DNA to pieces, causing mutations in genetic material that can potentially affect future generations and obliterate cellular structures, creating the possibility for the development of tumors that can lead to fatal cancers. Radium-226 is commonly found in oil and gas waste and equipment, especially in the Marcellus and Utica Shale regions of Ohio and Pennsylvania, and is known to cause cancer in humans. Research has found exposure to high levels of radium can cause malignant bone tumors, such as childhood bone cancer. .“Putting this radioactive material into municipal waste sites is a giant concern. That could be life-altering for a lot of people, people in the vicinity, people downwater of streams, all those things,” “This is a permanent reactor near your house, and it will always be a reactor because the waste got pooled together. And it will make as much radon and radium today as it will tomorrow and the next day and the next day and 30 years from now and 100 years from now and 500 years from now because the half life of this stuff is like, forever … So while it’s a naturally occurring material, when you concentrate it, you create a reactor.”
OSU study looks into impact pipeline installation has on crop yields -Preliminary results of an Ohio State University study show that pipeline installation on farmland negatively impacts crop yields. Researchers with the Ohio State University Extension Agronomics Crops Team collected soil and yield samples from 24 farms in seven counties that were impacted by natural gas pipeline installation in the last few years. They sampled the right-of-way over the pipeline and an adjacent, undisturbed area of the same field. Pipeline easements are typically 50 feet wide.They found corn grain yields decreased by an average of 23.8% in the pipeline installation area when compared with yields in the undisturbed area. Silage corn decreased an average of 28.8%; and soybean yield decreased an average of 7.4%. Soils within the right-of-way also had more rock fragments, lower soil moisture and a higher resistance to penetration, which indicates some amount of soil compaction. The results were similar to previous studies done on pipeline installation and crop yields.The farms were in Tuscarawas, Stark, Wayne, Medina, Lorain, Ashland and Wood counties. The Rover, Utopia and Nexus pipelines were targeted because they were each installed within the last three to four years.The team is collecting data again in the fall and looking for yield maps from other fields in Ohio where the Rover, Utopia or Nexus pipelines were installed.
Ohio Utica Shale Production 1Q21 – Northern Utica Oil Roars Back – Each quarter the Ohio Dept. of Natural Resources (ODNR) issues an update on Utica (and Marcellus) oil and natural gas production. ODNR no longer issues a summary press release as they once did, which means we don’t automatically notice when quarterly updates appear on their website. ODNR publishes a detailed spreadsheet of all active wells showing oil and gas production by well. We make a copy of that spreadsheet, enhance it to make it more usable, and link to it. We also do our own sorting to show you the top 25 shale gas wells and top 25 shale oil wells. An astute MDN reader inquired about the report for 1Q21, which is now available. We’ve created our own version of their report and have some exciting news to share about 1Q21 results. Oil is back, in a big way, in the northern Utica! First up is Ohio’s top producing gas wells. Note: 3,221,989 thousand cubic feet (Mcf) is roughly equivalent to 3.22 billion cubic feet (Bcf). table: Ohio’s Top 25 Producing Utica Shale Gas Wells for 1Q21 As promised, the good news about the northern Utica being back – at least for oil production. Seemingly out of nowhere, in 1Q21 wells drilled by PennEnergy Resources appeared and dominated the top 25 oil wells. And all of those wells are in Carroll County, OH – the northern Utica. When Aubrey McClendon (former CEO of Chesapeake Energy) “discovered” the Utica, he bought up leases in the northern part of the play, places like Carroll County. Ultimately the southern part of the Utica proved to have more prolific production. However, somehow PennEnergy has reopened the door to the northern part of the play. PennEnergy scored 14 of the top 25 wells in oil production for 1Q21 – by far the most of any company. Kudos! We run the numbers and calculated each well’s production by a daily average so we can rank all of the wells that way. Bear in mind a well online for just a few days will have higher daily production than a well online for a full 90 days. Finally, below is a link to view the spreadsheet online for 1Q21 Ohio Utica Production. You can sort the data any which way you want, or download it as a CSV file and keep your own copy. Enjoy!
Equitrans Mulling Requests by ‘Several’ Shippers to Boost Appalachia Natural Gas Takeaway Equitrans Midstream Corp. is making headway to increase natural gas connectivity in the Appalachian Basin, with management evaluating shipper interest received during a recent open season. The binding open season was related to Equitrans’ transmission system. It would increase shipper access to downstream markets in the Midwest and Gulf Coast, primarily through existing delivery interconnects with interstate pipelines in Clarington, OH. Management is evaluating the shipper requests, “and there were several,” according to Equitrans COO Diana Charletta. Also under evaluation are the costs to complete the expansion and the project economics. “There is still some back and forth with those shippers as far as where they want to come from and where they want to go,” Charletta said Tuesday during the second quarter earnings call with investors. “So, we’re working through all of that right now with shippers, and we should have final results in the next couple of months.” Meanwhile, construction continues on the long-delayed Mountain Valley Pipeline (MVP). Charletta said crews have been working since the spring on all approved upland areas for MVP and are on track to complete work in the fall. Once the upland work is done, the remaining work would include about 10 miles related to water crossings and eight miles in areas in and around the Jefferson National Forest. A recent notice of schedule published by FERC indicates that the environmental assessment for MVP would be published by the middle of August. Charletta said the permitting timelines for the Federal Energy Regulatory Commission and the U,S. Army Corps of Engineers remain consistent with summer 2022 service. The total project cost estimate also remains around $6.2 billion.
Pipeline’s plan to offset greenhouse gas emissions questioned by environmentalists – If natural gas begins to flow through the Mountain Valley Pipeline a year from now, as its developers expect, the operation will produce about 730,000 metric tons of greenhouse gases per year. Airborne emissions of carbon dioxide from three compressor stations along the 303-mile pipeline, along with methane expected to leak from the buried steel pipe, have long been a concern of opponents who say that delivering huge amounts of fossil fuel to markets will only worsen a climate change problem that is rapidly overheating the earth.On July 12, Mountain Valley announced a plan: The company will spend at least $150 million over the next 10 years on carbon offsets, which will be used to construct a massive methane abatement system at a coal mine in far Southwest Virginia.The mine is currently authorized by the federal government to release methane, generated by digging through rock formations, to prevent underground concentrations of the volatile gas from exploding and killing miners. A massive machine to be installed at the mine would convert the methane into water vapor and carbon dioxide before it is released into the air.Mountain Valley says the reduction of greenhouse gases will be roughly equivalent to what its pipeline will produce.The company will thus fight pollution from coal while meeting its goal of operating a carbon-neutral pipeline, said Diana Charletta, president and chief operations officer of Equitrans Midstream Corp., the lead partner in a joint venture building the controversial pipeline.The Sierra Club and Appalachian Voices, two organizations that have participated in legal challenges of the pipeline, called the $150 million plan a “green-washing” campaign to put a clean face on what is really a “pay-to-pollute” scheme.“Decision makers and the public should not be fooled: this offset scheme does nothing to change the fact that MVP is a dirty fossil fuel project that would pollute our communities and exacerbate the climate crisis,” Patrick Grenter, associate director of the Sierra Club’s Beyond Dirty Fuels Campaign, said in a statement released shortly after the July 12 announcement.
Chesapeake Energy’s future muddied by executive departures, strategy shifts (Reuters) – When U.S. oil and gas producer Chesapeake Energy emerged from bankruptcy in February, it touted to investors a clean balance sheet, a new board of directors and a promise to restrain spending.Since then, the company has endured a senior management shakeup and, according to two sources familiar with the matter, its interim CEO has told employees that the company is eyeing acquisitions that could help double its size.The mixed signals, say some investors, shed light on why Chesapeake’s stock rise has lagged that of rivals. One problem is that no one is exactly sure of the company’s real post-bankruptcy strategy.Chesapeake’s stock has gained about 21% since the company emerged from bankruptcy. But shares of rivals Antero Resources Corp AR.N and Range Resources Corp RRC.N have climbed about 67% and 53%, respectively, in the same period. Natural gas prices, meanwhile, have soared about 43% to $4.06 per million British thermal units.Investor confidence in Chesapeake’s reboot began to flag in April after then-director Michael Wichterich unexpectedly fired CEO Doug Lawler, who had headed Chesapeake for eight years, and took over his position on an interim basis.Lawler had been widely credited with whittling away the company’s $13 billion debt load with a conservative approach to spending and had shepherded the company through bankruptcy. In a town hall meeting shortly after the firing, Wichterich told employees that he had a knack for deal-making and recited a litany of deals he had closed on over the course of his career, according to two sources who attended the meeting. He then told them Chesapeake needed to grow or it would become an acquisition target, according to the sources, who added he has mentioned doubling the size of the company. “That freaked a lot of people out,”
Brooklyn Judge Freezes Plan to Truck Frigid Liquid Natural Gas to Brooklyn -Environmental activists protesting changes to National Grid’s Greenpoint hub for more than a year are claiming a legal victory – but the utility is pushing back.Following a court order, National Grid last week stopped construction work at the Brooklyn site that could be used to load and unload trucks containing liquefied natural gas, or LNG.LNG is predominantly methane gas cooled to liquid state and kept at minus-260 degrees – nearly as frigid as Saturn. The process reduces the gas’ volume, making for easier transportation. But trucking the combustible gas within the city has raised concerns around environmental and safety risks.A state Supreme Court judge on July 27 ordered National Grid to temporarily halt construction that would support possible LNG trucking to its North Brooklyn site, which is also at the center of a controversial pipeline plan.The move came after the Sane Energy Project and Cooper Park Resident Council sued the city, the Fire Department and National Grid to stop the work. The suit alleges required approvals haven’t been obtained and that an environmental review of the impact of trucking-related activities hasn’t been completed.“Any moment they’re not moving forward with this is more of a chance we can stop it for good,” said Lee Ziesche, community engagement coordinator for the Sane Energy Project.But in a legal filing submitted Thursday, National Grid argued against the restraining order and suggested environmental groups are misunderstanding its plan for the Greenpoint site.The work, National Grid spokesperson Karen Young said, has been “undertaken in compliance with all applicable laws, rules and regulations.”National Grid proposed bringing LNG to its Greenpoint facility by truck from outside the city through The Bronx and Queens.In November 2016, following up on a previous application, the company asked the FDNY for a “transport variance” to do so, since trucking LNG is illegal within city limits, but the request has not yet been granted or denied.Brooklyn Supreme Court Justice Karen Rothenberg found that construction related to National Grid’s variance petition must stop until the case is decided.In a legal filing, the company indicated the variance petition was old and related to a project that never came to fruition. National Grid sent a letter to the city Law Department and Fire Department on Tuesday saying it wanted to formally withdraw its application.If in an emergency the company would want to truck in LNG, it would have to apply to the city for an “event-specific” variance, rather than a general one.The company was building the “fully and lawfully permitted” truck unloading station, according to the filing, in order to be prepared for such an emergency event. The construction was about half complete.
Henderson gas pipeline opponents want environmental study of project – Environmental advocates are asking federal regulators to slow down and take time to assess the environmental impact and greenhouse gas emissions of a proposed natural gas pipeline expansion in Henderson County, Kentucky.The interstate pipeline would serve two proposed natural gas combustion turbines CenterPoint Energy wants to build across the Ohio River in Posey County, Indiana.CenterPoint Energy is seeking to speed development of the pipeline as it approaches the October 2023 retirement of its coal-burning A.B. Brown power plant near Evansville.Texas Gas Transmission, LLC, is the Houston-based company that will build and operate the pipeline by expanding its existing pipeline infrastructure. However, Texas Gas needs approval from the Federal Energy Regulatory Commission before it can go ahead with the 24-mile pipeline extension through western Henderson County. The project also includes upgrades to Texas Gas facilities near Slaughters, Ky., in Webster County, and in Johnson County, Indiana.Texas Gas has asked federal regulators to say the project won’t need an environmental impact statement because it “will cause a substantial net reduction” in greenhouse gas emissions.Those reductions would come both from Texas Gas’ own upgrades as well as from CenterPoint’s move to more renewable energy sources, including closing A.B. Brown.The expansion will be from near the Henderson-Webster county line northwest and then north across the Ohio River to Posey County to the A.B. Brown power plant near Evansville.Both the Citizens Action Coalition of Indiana, a consumer advocacy organization, and the environmental group Sierra Club have filed written protests. Citizens Action Coalition also is seeking a public hearing.CenterPoint has stated the natural gas turbines are important to help it transition from mostly coal-fueled power generation to a mix dominated by renewable energy sources while making sure it can reliably supply power at times renewable energy lags.In a 10-page filing to support the pipeline, Jason Stephenson, a CenterPoint vice president and general counsel, wrote that transitioning to renewable energy will be cheaper for customers than continuing to upgrade and operate the coal-burning power plant if the utility can make the transition quickly.
Letter: New pipelines? No thank you – The temperature in Portland, Oregon, a city that is further north than Toronto, Canada, recently hit 116 degrees Fahrenheit. Ice sheets are melting in line with the worst-case scenarios set out by the Intergovernmental Panel on Climate Change. Now is not the time to build new gas pipelines and plants. Texas Gas filed with FERC to build a new gas pipeline under the Ohio River to the CenterPoint A.B. Brown Plant. They are asking to build without doing the usual Environmental Impact Study. CenterPoint is asking the IURC to build two gas plants that are projected to run only 4-7% of the time. They claim these plants are needed to support renewable energy sources as needed. This is misleading. Battery storage can smooth the intermittency of renewables. Energy efficiency can reduce peak load much more cheaply than new gas plants. CenterPoint’s anemic distributed energy resource and demand managements programs show they haven’t really applied much effort at meeting demand except by building new plants on our dime. Neither the new pipeline under our drinking source nor the gas plants are needed or wanted. The U.S. Energy Information Administration (EIA) expects to see huge increases in battery storage deployments – from 1,600 MW installed in 2020 to 10,700 MW by 2023. That’s the technology we deserve. CenterPoint would have us pay for gas plants and pipelines then almost immediately turn around and say – oops – NOW we need to replace these with battery storage like everyone else. Let’s not be stupid. Get it right the first time.
Hoosiers Concerned About ‘Pipeline to Nowhere’ That Could Be Built Under Ohio River -A Kentucky-based company is seeking approval from federal authorities to build a natural gas pipeline under the Ohio River to bring out-of-state fuel to non-existent power plants.Hoosiers and advocacy groups are concerned about the pipeline’s environmental effects and whether its approval could set back a transition to clean energy.Texas Gas Transmission LLC is project asking the Federal Energy Regulatory Commission for approval to build a 24-mile pipeline extension to connect two centerpointpetition proposed natural gas-fired power plants at CenterPoint Energy Inc.’s A.B. Brown Generating Station in Posey County to a network of interstate natural gas pipelines. The company is asking FERC to approve the project, which would extend from Robards, Kentucky to Evansville, Indiana via an underwater crossing under the Ohio River, without performing an environmental impact statement.Texas Gas said the project would facilitate a substantial net reduction in overall greenhouse gas emissions, the heat-trapping gases responsible for man-made climate change.“FERC should determine that an environmental impact statement is not necessary to evaluate whether the Project will result in adverse climate change impacts because the Project will cause a substantial net reduction in methane, NOx, and carbon monoxide emissions resulting from the retirement and transitioning to standby of existing reciprocating compressor units on Texas Gas’ system and a reduction of indirect, downstream GHG emissions from the replacement of coal-fired generating facilities at CenterPoint’s AB Brown Plant with new-gas fired turbines and renewable resources,” Texas Gas wrote in its application to FERC.The company’s assertion is based on the assumption that the Indiana Utility Regulatory Commission will approve CenterPoint Energy’s petition to build the two natural gas combustion turbines the pipeline would eventually fuel.
Nelson County Activists Say Atlantic Coast Pipeline Should Rescind “Zombie Easements” | WVTF – It’s been just over a year since Dominion and its utility partners announced they were scrapping plans for a pipeline to carry natural gas from the fracking fields of West Virginia through Virginia to North Carolina. Opponents were thrilled, but some say their fight isn’t over yet. In 2012, David and Nancy Schwiesow retired from jobs in Washington D.C. to a small community in the Blue Ridge. They built their dream house near Wintergreen – 5,000 square feet with a spectacular view of three mountain ridges. But one year after moving in, David got a call from a real estate agent. “The realtor said, ‘Dominion has just rerouted the pipeline past the entrance to Wintergreen, up through your neighborhood.’ And I said, ‘You’ve got to be kidding.’” As a corporate lawyer, he knew something about government, power and politics. “In Nelson County, Wintergreen is by far the most valuable set of properties,” he explains. “The people here tend to be more politically connected than other people, so we thought there was no chance they’ll do that.” But it was soon apparent that backers of the Atlantic Coast Pipeline or ACP intended to clear a 600-mile path 125 feet wide. David Schwiesow stands on his front porch, shaking his head at the memory. Armed with approval from the Federal Energy Regulatory Commission – FERC – the pipeline was able to take land from owners, even before agreeing on a price. Megan Gibson is a senior staff attorney with the Niskanen Center – a Washington-based think tank that has helped landowners across the country to fight pipelines. “They say to the court, ‘This is an emergency. We need to begin construction or tree felling or trench digging or whatever excuse that they’re giving to the court immediately, or we are going to lose thousands of dollars, and all of these terrible things are going to happen,” she says. “The court more often than not grants immediate possession to the pipeline company without having to pay the land owner a dime!” Owners could no longer build on that part of their property nor could they plant trees, although Schwiesow’s neighbors were assured they would have some control. “After we build the pipeline, you can select the grass seed to go across the easement,” Schwiesow says they were told. So with the help of the Southern Environmental Law Center and a half dozen other groups, residents of Nelson County filed several lawsuits and challenged federal construction permits.
Pembroke Black Farming Community Fighting Gas Pipeline – At one time Pembroke Township in Kankakee County, Illinois was the largest Black farming community in the northern United States. Over environmental concerns and opposition by local Black farmers, a natural gas pipeline with large political backing is moving closer to reality. Farmers and political supporters claim the pipeline “threatens to replace [Pembroke] the last community of African American farmers in Illinois.” Reset talk with a farmer married couple leading protests of Black farmers.
Looming Northeast supply shortage drives steady advance in winter gas prices | S&P Global Platts – Natural gas prices in the US Northeast market area could hit their highest in four years or more this winter as lagging storage volumes and flat production are stretched thin by strong seasonal demand. Forwards markets are already bracing for the increasingly likely scenario. Since the start of April, peak-winter-season prices have surged at downstream hubs across the Northeast Atlantic Seaboard. At Transco Zone 6 New York, the December-January-February calendar-month average has climbed to more than $7/MMBtu recently, up from levels around $5.50 in early April. At Boston-area Algonquin city-gates, the peak-winter calendar-month average has climbed to the mid-$12s/MMBtu recently, gaining about $5.50 or almost 80% since the start of April, S&P Global Platts data shows. At both locations, the winter forward contracts are priced at their highest for January and February which recently settled in the upper-$7 range at Transco Zone 6 and the $13 to $14 range at Algonquin. The runup in Northeast winter gas prices over the past several months comes as regional storage inventories appear increasingly ill prepared to handle the upcoming spike in seasonal heating demand. As of early August, gas storage in the Northeast is estimated at 690 Bcf – about 54 Bcf, or 7%, below the prior five-year average and 128 Bcf, or almost 16%, behind the region’s year-ago inventory level, data from S&P Global Platts Analytics shows. Since the start of May, storage injections in the Northeast have averaged about 3.2 Bcf/d – almost 300 MMcf/d below the prior five-year average. While a recent uptick in the pace of injections has narrowed the region’s inventory deficit from over 60 Bcf, the speed of this summer’s build will need to accelerate to about 3.4 Bcf/d through early November to reach typical pre-winter inventory levels at over 1 Tcf.
Natural gas prices soar as demand for cooling boosts – Natural gas prices peaked this Monday, as cooling demand is forecast to boost in coming weeks; forecasts have predicted that weather will get hotter around the U.S. Consequently, more natural gas is going to be needed in order to cool off departments and buildings. Front-month gas futures rose 2.1 cents, or 0.5%, to settle at $3.935 per million British thermal units; Reuters reported. “The market is looking ahead to what could be a very hot end to the summer; with the cooling degree days likely to go up a little bit.” “Today’s price advance, although contained below Friday’s highs; reinforced our bullish view as we still see achievement of the $4.18 level as a high probability before this week is out.” Moreover, data provider Refinitv also projected that U.S. demand, including exports, will rise from an average of 91.2 bcfd this week to 95.2 bcfd next week. “We believe that early gains were shaved by the plunge in petroleum values; and also, that today’s highs will see violation by mid-week at the latest.” Added Ritterbusch. In addition, as we reported previously, liquified natural gas prices also peaked. Flynn also said to Reuters that U.S. LNG will stay very strong; while U.S. supply will weaken; leading to a tight market this year, which should support prices. In fact, last week natural gas prices jumped to their highest since December 2018 at $4.187. On the other hand, U.S. LNG exports reached 10.8 bcfd in July, up from 10.1 bcfd in June but still below April’s record 11.5 bcfd. On the other hand, U.S. production will remain unchanged, according to Refinitiv, in 92.2 billion cubic feet per day next week. That number will still be below November’s all-time monthly high of 95.4 bcfd. Finally, according to experts, U.S. LNG exports will remain strong for the whole year; supported by European natural gas prices ar tecord levels; and also Asian gas trading nearly at $15 per mmBtu.
Production Drop, Hotter Forecast Propel Natural Gas Futures Prices a Second Day – A step down in production drove natural gas futures prices higher for a second day, with gains accelerating after the latest weather models turned even hotter for next week. The September Nymex gas futures contract settled Tuesday at $4.027, up 9.2 cents on the day. October climbed 9.4 cents to $4.032. Spot gas prices were mostly higher, but there were small decreases in the Midwest and part of the western United States. NGI’s Spot Gas National Avg. climbed 8.5 cents to $4.000. With summer heat nearing what traditionally is the peak period this month, weather forecasts have once again become a driving force for gas markets. Weather models early Tuesday changed only slightly, according to NatGasWeather. The American and European data each saw a difference of less than 2 cooling degree days (CDD) for the coming 15 days compared to Monday’s data. As important, the models remained “quite hot” with the U.S. pattern for Saturday through Aug. 15. The midday Global Forecast System model, however, trended even hotter for next week into the following week, gaining more than 5 CDDs, NatGasWeather said. The forecast showed widespread heat building across most of the United States beginning late this weekend, aided by highs of lower to mid-90s over the East Coast and mid-90s to 102 over Texas and the South. “This should increase power burns to 45 to 47-plus Bcf/d, an impressive amount, thereby resulting in a couple smaller-than-normal builds to finally push current deficits of 168 Bcf to near or over 200 Bcf,” NatGasWeather said. The forecaster expects the “very warm to hot pattern” from Sunday to Aug. 15 and possibly carrying over to Aug. 16-18. However, early indications showed conditions not quite as impressively hot by then, “as weather systems find flaws in the ridge to weaken it moderately.” Bespoke Weather Services said another factor to consider is that wind early next week is expected to be stronger than recently, but it then may back off by the end of the period. Wind penetration has been a key driver of natural gas demand for power generation, even in the current higher price environment. Energy Aspects noted that wind generation in July averaged around 30 GW, short of its pre-month expectations by 9 GW. The firm attributed most of the miss to low wind generation earlier in the month in the Midcontinent.
September Natural Gas Prices Hit $4.20 Ahead of Potentially Lowest Injection of Season – After two solid days in the black, natural gas futures prices reached new heights on Wednesday as production continued to decline, and hot weather remained firmly in next week’s forecast. The September Nymex gas futures contract hit a $4.205 intraday high before settling at $4.158, up 13.1 cents from Tuesday’s close. Spot gas prices also strengthened as the cool conditions experienced in much of the country this week started to fade. With warmer temperatures on the way, NGI’s Spot Gas National Avg. ticked up 12.0 cents to $4.120. The potential for intense heat next week already has cut short an emerging period of consolidation in the gas market, according to EBW Analytics Group LLC. A growing cooling demand outlook for the coming 15-day period could lift weekly cooling degree day (CDD) forecasts for the week ending Aug. 12 to 93, which is 25 CDDs hotter than this week. “Bullish momentum has reemerged faster than appeared likely just last week,” said EBW analysts. The supportive outlook comes as long-range weather forecasts remained stable again Wednesday morning. The outlook showed next week as the “hottest week of the summer,” said Bespoke Weather Services. Forecasters pointed to widespread temperatures in the 90s across the Midwest and East underneath a strong upper level ridge in the six- to 10-day period. A couple of days next week are forecast to reach near records in terms of national gas-weighted degree days.
US working natural gas volumes in underground storage increase 13 Bcf: EIA | S&P Global Platts – US natural gas storage volumes increased by 13 Bcf in the week ended July 30, which was 4 Bcf less than a S&P Global Platts survey of analysts, but exactly in line with the Platts Analytics’ storage model.Working gas in storage increased to 2.727 Tcf, the US Energy Information Administration, or EIA, reported Aug. 5. The weekly injection was less than the 17 Bcf addition expected by a Platts’ survey of analysts. It also trailed the five-year average build of 30 Bcf and last year’s 32 Bcf injection in the corresponding week. The injection was less than half of the 36 Bcf build in the week ended July 23, with the decline being driven primarily by the South Central region. It posted a massive draw of 23 Bcf and measured as one of the largest withdrawals from storage in the region on record to take place during an injection season. The region has reported an average draw of 7 Bcf for the week over the past five years. Last year, it added 2 Bcf. Total US demand increased by more than 3 Bcf/d compared to the week before, while total US supplies were flat, according to Platts Analytics data. US storage volumes now stand at 542 Bcf, or 16.6% less than the year-ago level of 3.269 Tcf, and 185 Bcf, or 6.4% less than the five-year average of 2.912 Tcf. The NYMEX Henry Hub September contract remained at $4.16/MMBtu in trading following the release of the weekly storage report. The winter strip, November through March, averaged $4.23/MMBtu. An early end to a pipeline maintenance restricting flows from the US Northeast to the Southeast should boost supplies to the South Central region. Southeast inflows from the Northeast increased on Aug. 4 from 6.6 Bcf/d to over 7 Bcf/d as the capacity reductions along Texas Eastern Transmission were lifted. The outage, which began on June 2, cut southbound flows through the Danville compressor station by roughly 600 MMcf/d, lowering total Northeast to Southeast flows by 400 MMcf/d as other pipelines were able to make up some of the losses. The work was completed nearly two months earlier than expected, as the original end date was targeting the end of the third quarter. The increased supply reaching the Southeast will likely help to keep some pressure on regional prices. However, overall tighter balances throughout the region will likely outweigh any increases to inflows, according to Platts Analytics. Despite the elevated inflows to the Southeast, spot Henry Hub prices jumped 14 cents during trading on Aug. 4 to settle at $4.12/MMBtu. Platts Analytics’ supply and demand model currently forecasts a 47 Bcf injection for the week ending Aug. 6, which would measure 5 Bcf more than the five-year average.
September Natural Gas Prices Retreat in Face of Dangerously Low Storage The latest round of government storage data was about as bullish as it could be, but sellers came into the fold once weather models showed the upcoming heat being a little less intense. The September Nymex gas futures contract settled Thursday at $4.140, off 1.8 cents day/day. October slipped 1.5 cents to $4.148. Spot gas prices remained mostly in positive territory. However, there were a handful of locations, mostly in the West, that fell into the red. NGI’s Spot Gas National Avg. tacked on 2.5 cents to $4.145. [Mexico Natural Gas Market Spotlight: Gathering insight from active buyers and sellers, NGI breaks down what fundamentals are driving Mexico’s natural gas pricing in this weekly market analysis – READ NOW.] As it is every week, the Energy Information Administration’s (EIA) storage report was the primary focus of trading early in the session. Estimates ahead of the report were wide-ranging, from an injection as small as 14 Bcf to one as large as 34 Bcf. For comparison, the EIA recorded a 32 Bcf injection in the same week last year, and the five-year average stands at 30 Bcf. The Nymex September futures contract initially popped when the EIA reported a smaller-than-expected 13 Bcf build. The prompt month hit around $4.20, but with the latest weather models backing off from some of the heat forecast for next week, sellers swept in to drag prices back down. “The market appeared to already be pricing in risk of a bullish miss, and some cooler shift in the midday weather models brought some sellers into the fold,” said Bespoke Weather Services. “Dips likely will be bought, still, until production shows.” Given rampant export demand, and near triple-digit temperatures across the South Central region, inventories declined at both salt and nonsalt facilities. The EIA said salt stocks fell by 19 Bcf, and nonsalt dropped by 3 Bcf. A participant on The Desk’s online chat Enelyst noted that the 19 Bcf withdrawal in the South Central salt inventories was the largest third quarter salt draw of all time. The nonsalt draw also surprised. “I didn’t see that draw from nonsalt coming,” said Enelyst managing director Het Shah. Elsewhere across the country, Pacific stocks also slipped by 2 Bcf amid ongoing heat and low hydroelectric power in the region. East inventories climbed 21 Bcf, and the Midwest added 17 Bcf.
Bacteria Cleanup: Should we let nature clean up oil spills? – Natural populations of oil-degrading bacteria could help to clean up freshwater rivers and lakes after spills from pipelines and trains, researchers have found after experiments that simulated spills in a Canadian lake.Vince Palace, who led the work at the International Institute for Sustainable Development’s Experimental Lakes Area in western Ontario, said that the methods currently in use for cleaning up spills in rivers and lakes – mostly digging up and dumping contaminated soil – are not particularly effective. They only recover around 20 to 40% of the oil, and the physical damage done to shorelines and streambeds can be worse than the effects of the spill itself, taking as long as a decade to recover.Palace and his colleagues wanted to see if leaving the oil in place to be cleaned up by natural processes like bacteria might be a practical alternative.“We know that in the marine environment there are bacteria that can degrade oil,” said Palace. “We wanted to know if naïve freshwater systems have that same capacity.”The researchers created enclosures along the shore of one of the experimental lakes and dumped either conventional crude oil or the diluted bitumen that comes from Canada’s oil sands to simulate a spill. After 72 hours they cleaned it up as best they could, then examined what happened to the residual oil over the course of the summer and into the winter.The team found that after the spill, the composition of the bacterial community in the soil and water shifted dramatically. Rare types of bacteria, which had barely been present before, suddenly became the most common – and most of them had the capacity to degrade oil by using it as a source of food, suggesting a natural recovery could be a potential solution to spills in places like the Great Lakes, which are criss-crossed by pipelines and home to several refineries.
Council holds city-county pipeline ordinance, passes on second reading proposed permitting process law – MLK50 – Nearly six months since the first pipeline-regulating ordinance was placed before the Memphis City Council and one month since developers canceled the Byhalia Connection Pipeline, local governments have yet to pass any measures that would make similar pipeline projects tougher, if not impossible, to build.The council will consider Tuesday afternoon the third and final reading of a joint city-county ordinance that would require 1,500 feet between an oil pipeline and residential areas. Also on the council agenda is the second of three readings for a city-only ordinance that would create a new permitting process for such projects.Even though the project was halted, passing the two ordinances have been a priority of Justin J. Pearson, a co-founder of Memphis Community Against the Pipeline, which led the charge to stop the pipeline.“We are as vulnerable today against crude oil pipelines as we were in (before the project was announced),” Pearson said. “Without legislation and just regulation, our aquifer and our people will remain vulnerable.” The now-canceled project was a joint venture of Plains All American Pipeline and Valero Energy Corporation to expand their crude oil capacity with a pipeline through largely poor and Black neighborhoods in Southwest Memphis and atop the vulnerable Memphis Sand Aquifer, from which the city draws its drinking water.Plains voluntarily abandoned the project last month after facing opposition from Southwest Memphis residents, MCAP, elected officials, and national celebrities. However many pipeline opponents worry that without legal barriers to block it, the project could be revived later. In their cancellation announcement, Plains did not commit to abandoning the project permanently, nor did it signal that it wouldn’t pursue another pipeline in Memphis.The city’s ordinance would create a new permitting process for oil pipelines, establish an advisory board of experts and community members to evaluate proposals, require public notice and comment, and give the city council final approval. The council stalled the ordinance for months out of an abundance of caution after Plains threatened to sue. Some council members also wanted to address Memphis business leaders’ concerns that the ordinance would disrupt maintenance on existing pipelines. “It is being explained to us that delays are happening because of a ‘corporate constituency’ that is against the legislation without any mention of the community constituency that is for just legislation and regulation being passed,” Pearson said.
Oil leak from Golden Ray wreck could impact local beaches – – A pollution response team was been sent to the St. Simons Sound after oil leaked from the Golden Ray wreck.According to the Georgia Department of Natural Resources, there was a “significant” oil leak from the wreck.The department says it happened during “weight shedding” operations.Responders are trying to clean up the oil with current busters and oil skimmers. They ask anyone going to St. Simons Island and Jekyll Island who sees residual oil on the shoreline or in the water to call the National Response Center hotline at (800) 424-8802.
Days of cleanup after shipwreck oil leak fouls Georgia beach (AP) – Officials say cleanup efforts will take several days after oil leaking from the remains of an overturned cargo ship off the Georgia coast washed up on a beach popular with tourists.Coast Guard Petty Officer 2nd Class Michael Himes said Monday that bands of oil released into the water during demolition of the shipwreck are being cleaned up along 2.5 miles of beaches on St. Simons Island.The first spill happened Saturday as crews manning a giant crane tried to lift a newly severed section of the ship from the water. Himes said more oil gushed out during a second lift attempt Monday. About 70 workers have been working to remove the oiled sand since Sunday.
Louisiana needs sand to rebuild its coast. Old oil and gas pipelines are blocking the way. – A Houston-based energy company is asking a federal bankruptcy court for permission to walk away from its aging infrastructure in the Gulf of Mexico. Fieldwood Energy is attempting to shift responsibility for removing 1,715 wells, 276 platforms and 281 pipelines to oil and gas companies that previously held leases for the same area, according to court documents. Under existing federal regulations, companies remain liable for decommissioning infrastructure on areas of federally owned seafloor where they previously produced oil and gas. But the former holders of the Fieldwood leases – including Chevron, BP and Shell – are attempting to get out of that obligation because of the cost, estimated at $9 billion. It’s a familiar story. A recent U.S. Government Accountability Office report found that oil and gas companies have been allowed to abandon 97 percent of offshore pipelines in place without penalty. The abandoned infrastructure poses environmental concerns, but it has also created another problem: The pipelines are blocking access to the sand that Louisiana and other gulf states desperately need to rebuild their coastlines in the face of rising seas. The Gulf of Mexico swallows a football field of Louisiana coastline every 100 minutes on average. Barrier islands that have historically acted as speed bumps to hurricanes headed toward coastal communities are among the areas losing ground. Without them, the state is more vulnerable to climate change and severe weather. Geologists estimate that up to 11,000 million cubic meters of sediment are needed to restore the state’s coastline, but about 58 percent of the offshore sediment in the gulf that could be used to rebuild Louisiana’s coast is blocked by pipelines, said Syed Khalil, a geologist with the state’s Coastal Protection and Restoration Authority. While there is enough sand for the coastal restoration projects that Louisiana has planned in the short term, the state’s fight to fend off rising seas will require more. “We need every grain of sand for the restoration of coastal Louisiana,” Khalil said. Other Gulf Coast states are facing the same problem. But the issue has come to a head in Louisiana, where coastal land is disappearing faster than anywhere else in the nation. Flood control levees built along the Mississippi River are partly to blame for the Bayou State’s land loss. Levees block off the supply of sediment once carried by the river into coastal wetlands. Canals dug through the wetlands to build and service pipelines – which create pathways for saltwater to flow into the marsh – are also partly to blame for Louisiana’s coastal erosion. Now, those pipelines are hindering the solution. Federal regulations require the removal of offshore pipelines once they are decommissioned, but the rules are rarely enforced. The Bureau of Safety and Environmental Enforcement, the Interior Department agency that regulates offshore energy, has been mostly unsuccessful at getting companies to pay for the removal of pipelines decommissioned in place when they are later determined to be in the way.
Lawsuits over Louisiana oil drilling damage subject to new round of federal court hearings – Lawsuits filed in state court by Plaquemines and Cameron parishes to force oil and gas companies to clean up millions of dollars of environmental damage caused by their drilling activities were ordered Thursday to undergo a new set of hearings in federal court.The petitions are among 42 suits in state courts in six Louisiana parishes against oil and gas companies, some filed as early as 2013, over damage dating from decades ago. They allege the companies violated Louisiana’s coastal resources management act by failing to obtain permits or by violating the terms of the permits they did obtain. They do not allege violations of federal laws.Take a close look at this abandoned Plaquemines oil field, why it’s source of major legal battle The companies have repeatedly tried to transfer the suits to federal courts in search of a judicial audience that might be more friendly to their arguments against paying for the cleanups. Federal courts have often returned the suits to state courts.But a document filed in support of Plaquemines Parish’s arguments triggered the latest challenge. The companies contend the document for the first time showed that some of their drilling operations were conducted during World War II at the request of the federal Petroleum Administration for War. That could put the drilling under federal regulatory law, making the suits eligible for federal courts.The companies also argued that their actions were conducted under the direct jurisdiction of federal agents, another reason they should be heard in federal courts.Thursday’s ruling from the 5th U.S. Circuit Court of Appeals in New Orleans was written by Judge James Ho of Dallas and joined by judges Kurt Engelhardt of Metairie and Andrew Oldham of Austin, Texas. President Donald Trump nominated all three to that court.They agreed with earlier decisions, by district judges in New Orleans and Lake Charles, that the oil companies are incorrect in saying regulatory questions involving the environmental damage fall under federal legal jurisdiction. But they also ruled that the lower courts must determine whether the companies’ work was overseen by federal agents, so-called “federal officer jurisdiction,” which would allow the cases to stay in federal court.
Proposed oil terminal in Plaquemines Parish could disrupt Louisiana’s $2B wetlands project wA massive oil export terminal proposed in Plaquemines Parish would likely undermine Louisiana’s $2 billion bid to restore the degraded wetlands of Barataria Bay, according to a draft study commissioned by the Midwestern company leading the project. Modeling completed in February 2020 suggested the construction of the $2.5 billion terminal’s dock could reduce the amount of sand entering the mouth of the state’s planned Mid-Barataria Sediment Diversion by up to 15%. Add a ship parked in front of the terminal, and nearly half of the sediment that could be used to rebuild land off the parish’s west bank might be blocked. Consisting of a 2-mile long gated, concrete channel, the Mid-Barataria Sediment Diversion would transport silt- and clay-laden water from a sand bar in the Mississippi River to the Barataria Basin. It’s the one of the cornerstones of the state’s 50-year, $50 billion plan to sustain a portion of Louisiana’s lower third amid severe coastal erosion, subsidence and rising seas. Located on the former St. Rosalie Plantation site, the crude oil terminal would store up to 20 million barrels on site and load them onto huge ocean-going “Panamax” ships and barges for export. It’s a joint project of Tallgrass Energy LP, headquartered in Leawood, Kansas; Drexel Hamilton Infrastructure Partners, LP, a New York-based investment firm; and the Plaquemines Port, Harbor and Terminal District, which is governed by the Parish Council. Interfering with the state’s restoration project is just one of the terminal’s challenges. Developers are also facing opposition from residents of nearby Ironton, who fear increased air pollution and oppose plans to excavate and build on top of gravesites of people formerly enslaved on the plantation. The study became public after the environmental group Healthy Gulf filed a public records request for it in May. Now, the nonprofit, joined by the Sierra Club, National Wildlife Federation, Environmental Defense Fund and Coalition to Restore Coastal Louisiana, have renewed calls for the Louisiana Coastal Protection and Restoration Authority to kill the proposed terminal by finding it inconsistent with the Coastal Master Plan.
Tellurian and Shell Finalize 10-Year LNG Deal — Tellurian Inc. has announced that it has finalized liquefied natural gas (LNG) sale and purchase agreements (SPAs) with Shell NA LNG. The company outlined that the SPAs are on a free on board basis at Driftwood LNG for a combination of three million tons per annum (Mtpa) for a ten year period, indexed to a combination of two indices – the Japan Korea Marker (JKM) and the Dutch Title Transfer Facility (TTF), each netted back for transportation charges. The agreements mark the third deal Tellurian has finalized in ten weeks, totaling nine Mtpa and nearly all of the capacity of Driftwood LNG’s first two plants, Tellurian noted. In June, Tellurian announced that it had finalized LNG SPAs with Vitol Inc. for three Mtpa over a ten year period. In May, Tellurian and Gunvor Singapore Pte Ltd announced an LNG SPA for three Mtpa for a ten year period. “Tellurian welcomes Shell to the Driftwood project,” Tellurian President and Chief Executive Officer, Octflvio Simões, said in a company statement. “Shell manages one of the largest and most diverse portfolios of LNG in the world and is leading the industry in delivering CO2e neutral LNG cargoes. Owing to Driftwood’s integrated project, our ability to accurately measure well to loading arm emissions and reduce emissions where operationally possible, further enables Shell’s CO2e neutral LNG offering,” the Tellurian head added. “With these SPAs, we have now completed the sales to support the launching of the first two plants. Tellurian will now focus on financing Driftwood, in order to give Bechtel notice to proceed with construction in early 2022,” he went on to say. Steve Hill, the executive vice president of Shell Energy, said, “this deal secures additional competitive volumes for our portfolio by the mid-2020s, enabling us to continue providing diverse and flexible LNG supply to our customers”. Driftwood LNG, which is Tellurian’s first project, is a 27.6 Mtpa LNG facility near Lake Charles, Louisiana. The project has all the required permitting to begin construction and has achieved “significant commercial momentum”, Tellurian notes on its website. The management team at Tellurian has collectively delivered over 79 million tons of LNG through over the past 50 years, Tellurian’s website notes.
Buyer for Port Arthur LNG switches to other Sempra projects – Sempra’s proposed Port Arthur LNG export facility has lost an investor. Citing delays on the project, Poland’s state-run energy firm, PGNiG, decided to end its proposed 20-year contract for liquid natural gas. Instead, PGNiG has opted to sign a contract with Sempra to receive the 2 million tons per year of LNG from the company’s other North American projects, it announced on Tuesday. “We highly value our relationship with Sempra LNG, and we are keen to continue it,” Paweł Majewski, CEO of PGNiG SA, said in a statement. “The (memorandum of understanding) allows for shifting the volumes originally contracted at Port Arthur LNG to other facilities from Sempra LNG’s projects portfolio.” Sempra LNG owns a 50.2% interest in Cameron LNG, a 12-Mtpa export facility operating in Hackberry, Louisiana, and already is working on an expansion at that facility. The company also is working with IEnova and TotalEnergies on a project in Baja California, Mexico. The first phase of that project is expected to start production by the end of 2024. There are plans for an expansion at that facility as well, which are in the early phases of development. Meanwhile, Sempra in May, for the second time delayed its final investment decision on moving forward with the Port Arthur LNG, shifting the timeline sometime into 2022. In a statement from the company, Sempra LNG’s top executive was positive about the changes, marking it as a reflection of growing demand from energy buyers for reduced carbon emissions attached to the products they purchase. Sempra executives told investors and analysts in a May investor’s call that impacts to the natural gas industry during the pandemic and demand for more environmentally-friendly projects from global customers would require it to delay for another year while it continued to refine plans. Although work on an actual LNG facility for Sempra in Sabine Pass may be tentative, the company’s ongoing work on Texas 87 is nearing the finish line.
FERC Ordered to Revisit South Texas LNG Authorizations as Court Finds Environmental Analyses Lacking –A federal court on Tuesday ordered FERC to review its approvals of two planned liquefied natural gas (LNG) export projects in South Texas, saying the agency had not adequately explained its approach in evaluating the potential impacts on climate change and environmental justice (EJ) communities. The decision handed down from the U.S. Court of Appeals for the District of Columbia (DC) Circuit remands the Federal Energy Regulatory Commission’s authorizations, clearing the facilities for construction and operation, but it does not vacate them. That leaves the authorizations in place, allowing the developers to continue work on the facilities while the review proceeds.“We find it reasonably likely that on remand, the Commission can redress its failure of explanation with regard to its analyses of the projects’ impacts on climate change and environmental justice communities, and its determinations of public interest and convenience” under the Natural Gas Act (NGA) “while reaching the same result,” Circuit Judge Robert Wilkins wrote in an opinion on behalf of the court.The facilities in question, NextDecade Corp.’s Rio Grande LNG and an associated pipeline, and the privately owned Texas LNG development, received FERC authorization in 2019. Neither has reached a final investment decision. A coalition of environmentalists and local activists has long opposed the projects and challenged FERC’s authorizations in court.In the Tuesday decision, the court agreed with project opponents that the FERC assessment of the projects’ impacts on climate change were deficient. The opponents, which include environmental groups and local activists, argued that FERC should have used a “social cost of carbon” protocol to calculate impacts.While commissioners had said the projects would contribute “incrementally” to climate change, FERC also said it could not calculate the actual impacts because the means of making those calculations were unknown. The court determined that the law required FERC to evaluate climate change impacts based on “theoretical approaches or research methods generally accepted in the scientific community.
Gas projects reveal FERC’s environmental justice conundrum – Two liquefied natural gas terminals under development at the tip of Texas’ Gulf Coast could either lift low-income residents out of poverty or destroy local fishing and tourism economies, depending on whom you ask.The disparate views on the planned LNG projects – Rio Grande LNG from Houston-based NextDecade and the independently owned Texas LNG – underscore a tension for the Federal Energy Regulatory Commission and Chair Richard Glick’s recent pivot to address environmental justice: How should FERC determine whether the costs of a proposed project outweigh its benefits? Under what circumstances should projects in disadvantaged communities be approved or denied? And will FERC’s decisions survive legal scrutiny?FERC greenlighted the two LNG projects, which are slated to be built in the majority Latino region of Cameron County, Texas, in the fall of 2019. At the time, then-Chair Neil Chatterjee, a Republican, touted the projects as a win for the climate and U.S. foreign policy.“The Commission has now completed its work on applications for 11 LNG export projects in the past nine months, helping the United States expand the availability of natural gas for our global allies who need access to an efficient, affordable and environmentally friendly fuel for power generation,” he said in a statement at the time.To some legal experts and environmental activists, however, FERC’s analysis of the potential health and economic impacts of the projects on nearby communities was a textbook example of the agency’s inadequate consideration of environmental justice issues. Currently, the agency considers environmental justice within broader environmental impact statements, but there have been complaints that those analyses are insufficient and don’t fully assess impacts to low-income areas and communities of color.Glick, a Democrat who became chairman in January, vowed to make environmental justice a greater priority for the commission throughout its decisionmaking processes. At the same time, industry has questioned whether the agency has the legal authority to do so.The developers of Texas LNG and Rio Grande LNG each estimates that the terminals could bring thousands of new jobs to the region. Many elected officials – from Sen. John Cornyn (R-Texas) to the Cameron County Commissioners Court – have also touted the projects’ economic benefits, including the tax revenue they could bring in.The facility will also be powered by “electric drives” rather than gas turbines to lower its carbon emissions, Texas LNG added. Rio Grande LNG, meanwhile, is incorporating carbon capture and storage into its design to cut “permitted emissions” at its facility by over 90% (Energywire, March 19). Developer NextDecade did not respond to requests for comment.
Tribes, enviros sue Corps over Texas oil terminal expansion permit –(Reuters) – Indigenous tribes and environmental groups sued the Army Corps of Engineers in Corpus Christi, Texas, in federal court for issuing a permit to Moda Midstream, alleging it issued the permit for the expansion of the marine oil export terminal without studying the effects of the project on seagrass and wetlands. In a lawsuit filed Tuesday, Indigenous Peoples of the Coast Bend and others accused the Corps of violating the National Environmental Policy Act (NEPA) and the Clean Water Act (CWA) with a CWA permit that would allow Moda to dredge about 3.9 million cubic meters. of material out of Corpus Christi Bay. “One of my main concerns as a fisherman and bird watcher is that MODA’s expansion will destroy many acres of vital seagrass,” said Patrick Nye, chairman of the plaintiff group Ingleside on the Bay Coastal Watch Association in a statement. if green comment then The Corps did not immediately respond to a request for comment. Steven Davidson, a spokesperson for Moda, said: “We are satisfied that the nearly one-and-a-half-year application review process has been complete and that the U.S. Army Corps of Engineers permit has been properly delivered. “ The Houston-based company had planned to expand its Ingleside oil terminal, which connects Permian and Eagle Ford’s crude oil production to international markets, as early as 2017. Construction on the project has not started, Davidson said. The complaint says the expansion of the “largest export terminal in the United States by volume” would add five berths for tankers and barges, effectively doubling the capacity of its vessels. The plaintiffs, represented by Lauren Ice of Perales, Allmon & Ice, argue that the Corps violated NEPA because, although its environmental review of the project notes that seagrass and wetlands will be affected, it does not study this impact with the type of detailed reporting on NEPA’s mandates for major federal actions, known as environmental impact statements.
John Kerry questions long-term future of natural gas – Climate envoy John Kerry says natural gas is not “anything near a long-term solution” to help address climate change even while it can help replace coal in certain countries in the near-term.Kerry’s stance, declared in an interviewwith the New Yorker published last night, is notable because the Biden administration has struggled to articulate a consistent position on the role of natural gas.Here is the entire quote: “Russia has an option of quickly closing coal plants that are more than forty years old, not working that effectively, and not needed, in favor of transitioning to gas for the moment. I emphasize ‘for the moment’ because gas is still a fossil fuel, and gas is mostly methane, so it leaks and also produces CO2. It’s not, in our judgment, anything near a long-term solution, unless somebody discovers one-hundred-percent abatement.” Energy Secretary Jennifer Granholm has repeatedly said that shipping U.S. liquified natural gas abroad can play an important role in replacing dirtier coal, especially in Asia. She has also pressed the oil and gas industry to do a better job of reducing methane emissions associated with LNG in order to make that case credible. But she has not definitively said how long gas can continue playing a useful role in the clean energy transition.Still, liberal climate activists who have been pushing the administration to reject natural gas, even as a replacement for dirtier coal abroad, are interpreting Kerry’s comments as being closer to their position.”Special Envoy Kerry’s comments were definitely encouraging,” Collin Rees, senior campaigner with Oil Change U.S., told me. “It’s good to see a recognition from Kerry that ‘slightly less dirty’ won’t cut it – and that zero emissions means no gas or other fossil fuels.”
Exxon Lobbyist Caught on Tape Is an Advisor to Congressional Black Caucus Foundation – ExxonMobil senior lobbyist Keith McCoy was caught on video more than a month ago saying that he and his employer fight congressional climate action by using “shadow groups” and centrist think tanks. But the Congressional Black Caucus Foundation has so far decided to keep McCoy on as an advisor. McCoy is a member of the Congressional Black Caucus Foundation’s (CBCF) corporate advisory council, which “[advises] the CBCF’s Board of Directors on policy, special initiatives, and leadership development.” The CBCF’s Board of Directors currently includes six members of the House of Representatives, some of whom hold positions on the House committee with jurisdiction over legislation related to environmental protections and climate change. The CBCF is a nonprofit affiliate of the Congressional Black Caucus that researches how policies affect Black communities, publishes legislative reports, and hosts an annual legislative conference that it describes as “the leading policy conference on issues impacting African Americans and the global Black community.” On June 30, a Greenpeace-affiliated outlet released video of McCoy, a senior director of federal relations for Exxon, telling an undercover reporter that his company works behind the scenes to stall action on climate change even as it claims publicly to support the Paris Agreement and policies like a carbon tax. McCoy, who believed he was giving advice to someone who was looking to hire a lobbyist, said that the company backs a carbon tax because it believes it will never happen but gives it a good talking point.Sludge asked the CBCF if it would keep McCoy on its advisory board and if it would continue to take donations from Exxon, but did not receive a response.The Congressional Black Caucus has 57 members, all Democrats, including both representatives and senators.
CenterPoint customers will pay price for pipeline company profits during Texas freeze – Texans are on the hook for $3.6 billion in natural gas costs incurred by utilities during one freezing week in February – a burden consumers will bear for a decade or longer.During that same winter week, several natural gas pipeline companies and traders made billions of dollars as they transported and sold natural gas at sky-high prices when supplies were short. Pipeline companies Energy Transfer of Dallas and Kinder Morgan of Houston made $2.4 billion and $1.1 billion, respectively, while British oil major BP made more than $1 billion from its natural-gas trading business during the deadly, historic storm, according to company filings and analyst estimates. Houston pipeline company Enterprise Products Partners said it made $250 million for transporting and selling natural gas at high prices to utilities, industrial customers and power generators during the storm.Ultimately, Texans will fund these companies’ profits, “It’s pretty clear this is a wealth transfer from the public to investors and traders who could capitalize on the high prices,” Krane said. “The frustrating thing is, even though people were shivering in their homes, their (natural gas) bills are going up anyway. They’re still going to have to pay for this. It’s really a slap in the face.”More than 1.8 million CenterPoint Energy customers in the Houston area are responsible for the $1.14 billion natural gas bill incurred by the Houston utility when it had to quickly buy natural gas at sky-high prices after demand soared and supplies plunged during the storm.Natural gas wells and pipelines, many of which weren’t weatherized to handle prolonged freezing temperatures, froze and lost pressure during the storm. Weather-related problems and power outages at distant oil wells, caused natural gas production to plunge by almost half just as Texans were trying to stay warm during days of below-freezing temperatures.
Phillips 66 sees wider crude quality differentials going forward | S&P Global Platts Phillips 66’s record second-quarter chemical results were countered by poor refining segment results, due in part to high RINs costs, weak market capture and narrow light-heavy crude differentials, company executives said Aug. 3. Phillips 66 ran its refineries at 88% of capacity in the second quarter, up from first quarter’s 74%, but posted lower margin capture quarter on quarter on its distillate-focused refinery configuration, CFO Kevin Mitchell said during a call to discuss Q2 results.. “Realized margin was $2.92/b and resulted in an overall market capture of 22%,” Mitchell said. During the third quarter, the company will run at rates dictated by market conditions, he added. First quarter refinery margin capture was 33%, Mitchell said. “Market capture is driven by the configuration of our refineries,” he said. “Our refineries are more heavily weighted to distillate production than the [3:2:1 crack] market indicator.” During the quarter, the gasoline crack improved $5.68/b, while the distillate crack increased only improved by $2.20/b. Also, Phillips 66 had “quite a bit of planned FCC downtime this year,” CEO Greg Garland said, putting downtime at about 2% of the company’s gasoline-making fluid catalytic cracking capacity, further reducing gasoline output and lowering margin capture However, Garland said that the RIN-adjusted crack – which does not include the cost of compliance credits for the Environmental Protection Agency’s Renewable Fuel Standard – needs to get back to the $12/b to increase market capture to take advantage of rising demand as the coronavirus pandemic lockdowns ease. The increase in heavier crude supply, due in part to higher production quotas agreed by OPEC+ members, will benefit distillate-heavy Phillips 66. The company, which runs a lot of heavy crude, will benefit from the widening of light-heavy crude differentials. “For the second quarter, it was a gasoline-driven market without much differential on heavy crude,” said Robert Herman, Phillips 66’s head of refining. “We’ve seen those widen out here now in July to a much more respectable level.” So far in the third quarter, US light sweet Gulf of Mexico benchmark Light Louisiana Sweet is holding a $2.59/b premium to US Gulf of Mexico medium-sour Mars, according to S&P Global Platts assessments. This compares with the $2.04/b and $1.58/b premium held in the second and first quarters, respectively.
Devon and Conoco Study $10B Shell Permian Assets— Devon Energy Corp. and ConocoPhillips are among potential suitors studying Royal Dutch Shell Plc’s portfolio of Permian Basin oil fields, which could be worth as much as $10 billion in a sale, people familiar with the matter said. Chevron Corp. is also among companies considering bids for the assets, which are largely located in West Texas, the people said. Suitors have been invited to Shell’s data room to examine information on the business, the people said, asking not to be identified discussing confidential information. The Permian Basin of West Texas and New Mexico is the world’s busiest shale patch and accounts for roughly half the activity in U.S. oil fields today. Deliberations are ongoing, and there’s no certainty any of the suitors will decide to proceed with formal proposals, according to the people. Representatives for Chevron, ConocoPhillips, Devon and Shell declined to comment. The sale comes amid shifting strategies at oil and gas majors looking to less carbon intensive operations. BP Plc last year completed the sale of its business in Alaska to Hilcorp Energy Co., while in early 2021 Equinor ASA agreed to sell its interests in the Bakken field in Montana and North Dakota to Grayson Mill Energy for $900 million. In May, Shell was ordered by a Dutch court to slash its emissions harder and faster than planned after losing a court case against Milieudefensie, an arm of Friends of the Earth. Shell said it will appeal the verdict, while asserting a willingness to accelerate its transition to a net-zero emissions business. Meanwhile, investors in the U.S. have been pushing for more company tie-ups within each of the shale basins as a way to cut costs and get more bang for their drilling buck. Bonanza Creek Energy Inc. bought its Colorado rival Extraction Oil & Gas Inc. for about $1 billion, while Midland, Texas-based Diamondback Energy Inc. announced a pair of deals late last year to bulk up in the Permian.
US oil, gas drilling rig count up four at 603 on stronger Permian activity – The US oil and gas rig count climbed four to 603 in the week ended Aug. 4 amid an uptick in Permian basin drilling activity, rig data provider Enverus said Aug. 5. The number of oil-focused rigs was up six at 463, while the number primarily chasing gas fell two to 140. The rig count climb was centered in the Permian Basin, where operators added five rigs for a total 258, leaving the plays rig count just one shy of the 15-month high of 259 seen during the week ended July 21. But rig counts in the other major named oil-focused basins were flat to lower. The SCOOP-STACK and Denver-Julesburg play rig counts were steady at 29 and 15, respectively. The South Texas Eagle Ford Basin shed two rigs, putting the total active there down to 40, a six-week low. Meanwhile, the Bakken rig count fell one to 22. Among the major named gas plays, the Utica shale saw an increase in drilling rig count, which climbed one to 13. The nearby Marcellus basin shed one rig for a total 32, while in the Haynesville, operators idled one rig, leaving a total 55 active. The lower overall gas rig count snapped three consecutive weekly builds that had seen gas-focused drilling activity reach the highest level since March 2020. Even after pullback in the week ended Aug. 4, the gas rig count is just 5% below pre-pandemic levels. Oil-focused rigs, in contrast, despite holding near April 2020 levels are still down around 33% from pre-pandemic levels. Permian growth eyed Notably, Permian Basin rig count is down nearly 40% from pre-pandemic levels, significantly lagging the broader oil and gas rig count, which is down just 28% over the same period. But despite laggard drilling activity, improved efficiencies have pushed Permian production to near pre-COVID levels. The basin’s crude output exceeded 4.8 million b/d before the pandemic, falling to a low of about 4.15 million b/d last August, before rebounding back up to about 4.7 million b/d this August, according to the US Energy Information Administration.
New Mexico’s Oil Output Rises Signaling a Modest Shale Recovery — New Mexico’s oil production surged to a record in May highlighting the Permian Basin’s role as the shale industry sees some recovery from the pandemic.The southwestern state produced about 4% more crude in the month to reach a record 1.22 million barrels a day, according to U.S. government data released Friday. It also topped North Dakota, to become America’s second-biggest onshore oil supplier. New Mexico has churned out more than North Dakota for three straight months, the longest stretch since 2008.New Mexico’s rising status as a key supplier reflects its cost advantage. U.S. oil and gas companies have been judicious in raising output after many producers pledged to cap spending and focus on returning more capital to shareholders. To that end, the Permian’s New Mexico is being favored over North Dakota, where higher production costs have historically curbed profits.The promises on capital restraint are likely to hold further production gains in check, even with higher oil prices providing an incentive to expand. In its latest earnings report, Chevron Corp. which has sizable acreage in the New Mexico, expects its Permian output in 2021 to be comparable to 2020 despite announcing that it would be adding more rigs and completion crews through the rest of this year. U.S. oil production stood at 11.2 million barrels a day in May, nearly a million barrels a day less than the same month in 2019.
Comment period extended for listing lesser prairie chicken as endangered —The public will have a month longer to weigh in on the proposed listing of the lesser prairie chicken under the Endangered Species Act. The U.S. Fish and Wildlife Service is extending the deadline for public comment to Sept. 1 for the grouse, which has seen its populations dwindle from 2 million in the 1800s to about 38,000 across five states because of climate change, industrial development and agriculture. In late May, federal wildlife managers proposed relisting the bird – known for its colorful spring mating display – to comply with a court order spurred by conservation groups suing the agency. A 60-day comment period that began June 1 will increase to 90 days. The proposal calls for listing the bird’s southern population, including in Eastern New Mexico, as endangered and those occupying the northern rangelands as threatened. Its habitat can be found in parts of New Mexico, Colorado, Kansas, Oklahoma and Texas. An abrupt 50 percent drop in the bird’s numbers in 2014 prompted the agency to list the bird as threatened that year. But two years later, a brief 25 percent surge in population led to a federal judge removing protections in response to a lawsuit by a petroleum company. Environmentalists have pushed for renewed federal protections while the oil and gas industry has staunchly opposed relisting the grouse, saying the voluntary programs to protect and grow the birds’ habitat are working. Wildlife officials say the lesser prairie chicken faces a number of external threats, including from climate change prolonging droughts, especially in the southern region where the bird could become extinct.
Shale Drillers Leave $12B on Table— Shale explorers are facing almost $12 billion in losses this year from bad bets on oil after a global rally, according to BloombergNEF. Of the 50 U.S. drillers surveyed by BNEF, Devon Energy Corp., Pioneer Natural Resources Co. and Diamondback Energy Inc. are on track to rack up the steepest losses, with more than $1 billion in underwater hedges apiece. The sector as a whole hedged almost one-third of estimated 2021 output and the practical impact is that they are locked in to reap about $5 less than the American benchmark crude, West Texas Intermediate. “One of the negatives of this quarter has been some horrible hedging; guys locked in at $42 a barrel,” Paul Sankey, the veteran oil-industry analyst and founder of Sankey Research LLC, said during an interview on Bloomberg TV. Hedging helps producers of raw materials mitigate the risk of major price fluctuations and lock in relatively stable cash flows. But the practice carries the risk of leaving money on the table during bull markets. The losses haven’t been limited to crude drillers. EQT Corp., America’s biggest natural-gas producer, irritated investors last week by boosting hedges at a time when the commodity also is surging. The company already has booked a $1.3 billion non-cash second-quarter loss on swaps and options contracts.
Environmental Groups Want Agency To Review Climate Impacts Of Superior Gas Plant -Environmental and indigenous groups want a federal agency to take another look at the environmental and climate impacts of a proposed $700 million natural gas plant in Superior. Four organizations, including the Sierra Club and Clean Wisconsin, are petitioning the Rural Utilities Service to conduct a supplemental environmental assessment of the project proposed by La Crosse-based Dairyland Power Cooperative and Duluth-based Minnesota Power. Dairyland Power plans to seek a loan from the agency for its share of the project.The agency previously found that construction and operation of the 625-megawatt plant would have no significant environmental impact. But the groups argue the agency didn’t evaluate cumulative climate impacts of the plant in its environmental assessment“This facility would emit 3 million tons of carbon every year for at least 30 years if it’s built, and there’s just no way to get to zero carbon if we keep building things that emit carbon,” said Katie Nekola, general counsel for Clean Wisconsin. Clean Wisconsin and the Sierra Club are also suing the Wisconsin Public Service Commissionover its approval of the project, noting regulators didn’t review the climate impacts of the proposal. They say the U.S. Department of Agriculture Rural Utilities Service must respond to their petition before making a decision on financing for the project.Gov. Tony Evers has set a goal for Wisconsin to go carbon-neutral by 2050. At the federal level, President Joe Biden has set a goal for the power sector to go carbon-neutral by 2035 and reach net-zero emissions by 2050.The two power providers are seeking to build the plant as part of plans to transition away from coal to renewable energy.
Minnesota regulators scold natural gas providers for cost run-up during February storm – Minnesota utility regulators Thursday approved a plan that would give consumers extra time to pay a colossal $660 million natural gas tab stemming from a historic February storm – while ripping the gas industry’s role in the fiasco. In fact, the Minnesota Public Utilities Commission (PUC) indicated that some of that $660 million could eventually be recouped by consumers as an investigation continues into how the state’s utilities might have mishandled the February gas-supply crisis. Several PUC commissioners Thursday questioned the functionality of a market that allowed Midwest wholesale prices to spike at least 4,500% – and saddle some Minnesota consumers with extra charges amounting to 50% of their annual gas bill. “This kind of behavior in the marketplace is inappropriate in a regulated industry,” said Commissioner John Tuma, pointing out reports of price gouging by gas industry middlemen during the storm. “We need to figure out what happened and figure it out quickly.” Then, talking specifically about Minnesota’s utilities, Tuma said: “I don’t think you realize how significant this was and how it will move us away from gas. … It has changed my worldview as to how natural gas fits into our energy [system] in Minnesota.” Commissioner Joe Sullivan concurred, saying the gas system “is extremely vulnerable.”
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