Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 07 November 2020. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.
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EIA reports largest October natural gas storage draw on record; October’s gas inventory build is smallest on record
US oil prices managed an increase for the first time in three weeks as iinventories fell and traders figured the coming Congress was unlikely to pass legislation limiting resource exploitation…after falling 10.2% to $35.79 a barrel last week on surging coronavirus cases, the contract price of US light sweet crude for December delivery opened lower on Monday and quickly fell more than 6% as European countries widened their anti-virus lockdowns, but then reversed those early losses to gain $1.02, or more than 2.8%, on strong manufacturing activity reports from Asia and the US, and as traders took positions ahead of the US presidential election…oil prices advanced with other financial markets ahead of the election on Tuesday and finished 85 cents higher at $37.66 a barrel, as traders positioned ahead of the weekly oil inventory reports… oil prices then rose overnight after the American Petroleum Institute reported an unexpected major draw from crude oil inventories and opened 48 cents higher on Wednesday, and held onto those gains after the EIA confirmed the big inventory draw, before soaring to a 4% gain after Trump claimed victory, even with millions of votes still to be counted, with December oil closing up $1.49 at $39.15 a barrel…but oil prices fell on Thursday as Democrat Joe Biden edged closer to taking the White House and ended down 36 cents at $38.79 a barrel as rising Covid-19 cases and European lockdowns became the focus…oil prices were then sharply lower on Friday after records were set for US and global virus cases, and as new restrictions threatened demand, with December oil settling $1.65 lower at $37.14 a barrel as drawn-out vote counting in the U.S. kept markets on edge, but still posting a 3.8% increase for the week as conflicting themes emerged over what the prospect of a divided government means for the oil market…
Natural gas prices, on the other hand, fell every day this past week to finish lower for the first time in five weeks…after rising 5% to a 21 month high of $3.354 per mmBTU last week on Hurricane Zeta’s impacts and an unexpectedly small addition to inventories, the contract price of natural gas for December delivery tumbled 11 cents or more than 3% on Monday on forecasts for warmer weather and weaker demand than had been expected, and then fell 18.5 cents or more than 5% to $3.059 per mmBTU on Tuesday as comfortable temperatures settled in across most of the US…natural gas prices slipped another 1.3 cents on Wednesday as record LNG exports offset forecasts for milder weather and a steady rise in natural gas output and then tumbled 10.4 cents to $2.942 per mmBTU on Thursday despite the largest October storage withdrawal on record as traders focused more on weather-induced demand weakness than on supplies…December gas prices then fell 5.4 cents to $2.888 per mmBTU on Friday and thus finished the week nearly 14% lower, as this week’s temperatures climbed rapidly from last week’s freezing territory into the 60s and 70s across much of the Midwest, cutting off heating demand and driving down cash prices….
The natural gas storage report from the EIA for the week ending October 30th indicated that the quantity of natural gas held in underground storage in the US decreased by 36 billion cubic feet to 3,919 billion cubic feet by the end of the week, which left our gas supplies 200 billion cubic feet, or 5.4% greater than the 3,718 billion cubic feet that were in storage on October 30th of last year, and 201 billion cubic feet, or also 5.4% above the five-year average of 3,718 billion cubic feet of natural gas that have been in storage as of the 30th of October in recent years….the 36 billion cubic feet that were pulled out of US natural gas storage this week was somewhat more than the average forecast for a 27 billion cubic foot decrease from analysts polled by Reuters, and it was a complete reversal of the average of 52 billion cubic feet of natural gas that are typically added to natural gas storage during the same week over the past 5 years, and it was also a reversal of the 49 billion cubic feet that were added to natural gas storage during the corresponding week of 2019…
This week’s withdrawal of 36 billion cubic feet of natural gas from storage was the first October withdrawal in the modern records going back to early 2010, and only the third withdrawal in the archived records, far eclipsing the 9 billion cubic feet that were pulled out of storage during the week ending October 27th 2006 and the 3 billion cubic feet that were pulled out of storage during the week ending October 31st 1997….other than those two times, all other October weeks on record have seen natural gas storage increases…but as a matter of fact, all the October gas storage reports of this year came in far below the norm for the given week, as the following graphic shows…
The graphic above is a screenshot of an interactive graphic that’s included on the EIA’s weekly natural gas storage dashboard, and as the heading indicates, it shows the weekly change, in billions of cubic feet, of natural gas in storage in the lower 48 states…the blue dots represent the weekly changes of natural gas in storage for each week this year up to & including the current report, while the dark diamonds represent the 5 year average change of natural gas in storage for each week of the year over the 2015 to 2019 period, with markers above the “0” line representing gas additions to storage, and markers below the zero line representing withdrawals of natural gas from storage…meanwhile, the shaded grey background to those markers represent the range of changes for each week of the year over that 5 year span….as you can see, each of this year’s blue dots, representing the recent storage reports, falls below the 5 year range, while this week’s withdrawal was the earliest in the 5 year record by two weeks, with the withdrawals in recent years typically not coming until the 2nd, 3rd or even the 4th week of November…only 88 billion cubic feet of natural gas were added to storage during those 4 weeks of October, and in scanning the historical spreadsheets, i found no other October with such a small addition; 200 billion cubic feet October builds are typical, with some years, such as 2019, seeing October storage additions approaching 400 billion cubic feet..
What happened this most recent week should be evident from the graphic below showing US temperature anomalies by region for the week ending October 29th…
The temperature anomaly map above also came from the EIA’s weekly interactive natural gas storage dashboard, and as you can gather, it shows how much the week’s temperature in each of several hundred regions of the country varied from the norm during the week, with the brown shading showing above normal temperatures for the week, and blue shading representing below normal temperatures over the period…as you can see, large parts of the country’s misection saw temperatures more than 10, 15 or even more than 20 degrees below normal for the week, thus indicating a demand for natural gas heating that is more indicate of mid-winter than mid-autumn…moreover, at the same time, a few states in the deep South were seeing temperatures that exceeded the norm by more than ten degrees, meaning that region was probably burning more gas for electrical generation than normal due to increased demand for air conditioning….put those aberrant demand elements together with Hurricane Zeta shutting down half of the Gulf of Mexico’s production at the same time resulted in the record October draw of natural gas from storage that we saw this week…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending October 30th indicated that because of a drop in our oil production and a decrease in our oil imports due to Hurricane Zeta in the Gulf of Mexico that week, we had to withdraw oil from out stored commercial supplies for the 11th time in the past fifteen weeks and for the 17th time in the past forty-two weeks…our imports of crude oil fell by an average of 634,000 barrels per day to an average of 5,029,000 barrels per day, after risng by an average of 546,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 1,195,000 barrels per day to an average of 2,265,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,764,000 barrels of per day during the week ending October 30th, 561,000 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 600,000 barrels per day lower at 10,500,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 13,264,000 barrels per day during this reporting week…
US oil refineries reported they were processing 13,552,000 barrels of crude per day during the week ending October 30th, 163,000 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 total of 1,164,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 877,000 barrels per day more than what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (-877,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting that there must have been an error or errors of that magnitude in the oil supply & demand figures we have just transcribed….moreover, since last week’s fudge factor was +608,000 barrels per day, indicating a week over week difference of 1,485,000 barrels per day in the line 13 balance sheet adjustment, the difference between those errors means any week over week comparisons of oil supply and demand figures reported here are complete nonsense…however, since most everyone treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as published, just as they’re watched & believed to be accurate by most everyone in the industry, in what is clearly a case where a common delusion has become reality…(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 5,274,000 barrels per day last week, which was 15.4% less than the 6,232,000 barrel per day average that we were importing over the same four-week period last year….the 1,164,000 barrel per day net withdrawal from our total crude inventories included 1,143,000 barrels per day that were withdrawn from our commercially available stocks of crude oil and 22,000 barrels per day were being withdrawn from the oil supplies in our Strategic Petroleum Reserve, space in which is now being leased for commercial use, and hence the recent SPR additions and withdrawals should really be included in our commercial supplies……this week’s crude oil production was reported to be 600,000 barrels per day lower at 10,500,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states fell by 600,000 barrels per day to 10,000,000 barrels per day, while a 2,000 barrels per day decrease to 467,000 barrels per day in Alaska’s oil production still added 500,000 more barrels per day to the rounded national total…last year’s US crude oil production for the week ending November 1st was rounded to 12,600,000 barrels per day, so this reporting week’s rounded oil production figure was 16.7% below that of a year ago, yet still 24.6% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…
Meanwhile, US oil refineries were operating at 75.3% of their capacity while using 13,552,000 barrels of crude per day during the week ending October 30th, up from 74.6% of capacity during the prior week, but excluding the 2005 and 2008 hurricane-related refinery interruptions, still one of the lowest refinery utilization rates of the past thirty years…hence, the 13,552,000 barrels per day of oil that were refined this week were 14.0% fewer barrels than the 15,761,000 barrels of crude that were being processed daily during the week ending November 1st of last year, when US refineries were operating at 86.0% of capacity…
Even with the increase in the amount of oil being refined, gasoline output from our refineries was a bit lower, decreasing by 23,000 barrels per day to 9,072,000 barrels per day during the week ending October 30th, after our refineries’ gasoline output had increased by 162,000 barrels per day over the prior week…and since our gasoline production is still recovering from a multi-year low in the wake of this Spring’s covid lockdown, this week’s gasoline output was still 9.6% less than the 10,036,000 barrels of gasoline that were being produced daily over the same week of last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 149,000 barrels per day to 4,275,000 barrels per day, after our distillates output had decreased by 5,000 barrels per day to a three year low over the prior week…hence, even after this week’s increase, our distillates’ production was still 12.3% less than the 4,875,000 barrels of distillates per day that were being produced during the week ending November 1st, 2019…
Despite the decrease in our gasoline production, our supply of gasoline in storage at the end of the week increased for the 5th time in 18 weeks and for the 12th time in 40 weeks, rising by 1,541,000 barrels to 227,665,000 barrels during the week ending October 30th, after our gasoline supplies had decreased by 892,000 barrels over the prior week…our gasoline supplies increased this week because the amount of gasoline supplied to US markets decreased by 209,000 barrels per day to 8,336,000 barrels per day, and because our imports of gasoline rose by 170,000 barrels per day to 630,000 barrels per day, while our exports of gasoline rose by 186,000 barrels per day to 716,000 barrels per day….so despite the gasoline inventory drawdowns of recent weeks, our gasoline supplies were 4.8% higher than last November 1st’s gasoline inventories of 217,229,000 barrels, and about 4% above the five year average of our gasoline supplies for this time of the year…
Meanwhile, with our distillates production remaining well below normal for this time of year, our supplies of distillate fuels decreased for the 7th week in a row, for the 13th time in 31 weeks and for the 31st time in 52 weeks, falling by 1,584,000 barrels to 160,719,000 barrels during the week ending October 30th, after our distillates supplies had decreased by 4,491,000 barrels during the prior week….our distillates supplies fell by less this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 478,000 barrels per day to 3,762,000 barrels per day, even as our exports of distillates rose by 200,000 barrels per day to 1,071,000 barrels per day, while our imports of distillates fell by 12,000 barrels per day to 332,000 barrels per day….but even after this week’s inventory decrease, our distillate supplies at the end of the week were still 29.8% above the 119,132,000 barrels of distillates that we had in storage on November 1st, 2019, and about 18% above the five year average of distillates stocks for this time of the year…
Finally, with decreases in our oil imports and in our oil production, our commercial supplies of crude oil in storage (not including commercial oil in the SPR) fell for the 13th time in the past twenty-one weeks and for the 19th time in the past year, decreasing by 7,998,000 barrels, from 492,427,000 barrels on October 23rd to 484,429,000 barrels on October 30th…even after that decrease, our commercial crude oil inventories were still around 7% above the five-year average of crude oil supplies for this time of year, and about 41.5% above the prior 5 year (2010 – 2014) average of our crude oil stocks for the last weekend of October, 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 generally been rising over the past two years, except for over the recent weeks and during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of October 30th were 8.4% above the 446,782,000 barrels of oil we had in commercial storage on November 1st of 2019, 12.2% more than the 431,787,000 barrels of oil that we had in storage on November 2nd of 2018, and 6.0% above the 457,143,000 barrels of oil we had in commercial storage on November 3rd of 2017…
This Week’s Rig Count
The US rig count rose for the 8th week in a row during the week ending November 6th, but for just the 10th time in the past 35 weeks, and hence it is still down by 62.2% over that thirty-five week period….Baker Hughes reported that the total count of rotary rigs running in the US rose by 4 to 300 rigs this past week, which was still down by 517 rigs from the 817 rigs that were in use as of the November 8th report of 2019, and was also 104 fewer rigs than the all time low prior to this year, and 1,629 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business….
The number of rigs drilling for oil increased by 5 rigs to 226 oil rigs this week, after increasing by 10 oil rigs the prior week, still leaving us with 458 fewer oil rigs than were running a year ago, and less than a sixth 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 decreased by one to 71 natural gas rigs, which was also down by 59 natural gas rigs from the 130 natural gas rigs that were drilling a year ago, and was also less than a twentieth of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to those rigs drilling for oil & gas, three rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, one in Sonoma County, California, and one in the Permian basin in Eddy County, New Mexico…a year ago, there were no such “miscellaneous” rigs deployed…
The Gulf of Mexico rig count was down by one to 12 rigs this week, with 11 of those rigs drilling for oil in Louisiana’s offshore waters and one drilling for oil offshore from Texas…that was 10 fewer Gulf rigs than the 22 rigs drilling in the Gulf a year ago, when all 22 Gulf rigs were drilling offshore from Louisiana…while there are no rigs operating off of other US shores at this time, a year ago there was also a rig deployed offshore from Alaska, so this week’s national offshore count is down by 11 from the national offshore rig count of 23 a year ago….in addition to those rigs offshore, there are now two rigs drilling through an inland bodies of water this week, one in in southern Louisiana and the other in Texas, while a year ago there was just one rig drilling on southern Louisiana inland waters..
The count of active horizontal drilling rigs was up by 5 to 259 horizontal rigs this week, which was still 451 fewer horizontal rigs than the 710 horizontal rigs that were in use in the US on November 8th of last year, and less than a fifth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….at the same time, the vertical rig count was was up by two to 22 vertical rigs this week, but those were still down by 29 from the 51 vertical rigs that were operating during the same week of last year….on the other hand, the directional rig count was down by three to 19 directional rigs this week, and those were also down by 37 from the 56 directional rigs that were in use on November 8th of 2019….
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 November 6th, the second column shows the change in the number of working rigs between last week’s count (October 30th) and this week’s (November 6th) count, the third column shows last week’s October 30th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running during the count 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 8th of November, 2019…
As you can see, this week’s rig increases were again centered in Texas and New Mexico, while a handful of rigs were being pulled from other parts of the country…checking for the details on the Permian in Texas, we find that two rigs were added in Texas Oil District 7C, which corresponds to the southern Permian Midland, that another rig was added in Texas Oil District 7B, which includes a few counties in the far eastern Permian Midland, while a rig was pulled out of Texas Oil District 8A, which corresponds to the northern Permian Midland…together, those changes mean that the Texas Permian saw a net two rig increase…since the Permian basin rig count was up by five rigs nationally, that means that the three rigs that were added in New Mexico must have been added in the farthest west reaches of the Permian Delaware, to account for the national increase…elsewhere in Texas, we find that one rig was added in Texas Oil District 1, another rig was added in Texas Oil District 2, and another rig was added in Texas Oil District 4, two of which account for the Eagle Ford shale increase and also bring our Texas rig count increase to five…the state inccrease totals six rigs, however, because Baker Hughes includes the new inland water rig as being in a separate catagory, outside of the district counts, before adding the state totals…elsewhere, two oil rigs were added in the Cana Woodford in Oklahoma, a state which apparently had three oil rigs which had been drilling in basins not tracked separately by Baker Hughes removed at the same time…for natural gas rigs, we had one rig removed from Ohio’s Utica shale, another gas rg removed from the Marcellus in West Virgiinia, while a natural gas rig was added in a basin not tracked separately by Baker Hughes, most likely in Texas…we should also note that the only rig which had been drilling in Alabama recently was pulled out this week, while there was also no drilling in Alabama a year ago…
NE Ohio pipeline repair company to triple capacity with move – The Pipe Line Development Co. (PLIDCO) said it plans to move its headquarters and manufacturing facility from Westlake to Strongsville, Ohio. The pipeline repair company said it plans to move to a 248,200-square-foot facility at 11792 Alameda Dr. in Strongsville, which is much larger than its current 80,000-square-foot Westlake facility and 15 miles away. About 100 people work in the company’s production facility. PLIDCO began the multi-phased move on Nov. 1, and said it may take up to a year to fully complete the relocation. Both manufacturing facilities will operate during that time, the company said. “PLIDCO has grown considerably in recent years. We’re excited to move into a significantly larger manufacturing facility with an improved layout and greater capabilities that will allow our team to continue meeting customer demand and production, while providing new operational efficiencies and increased product availability for our customers,” said Ernie Lackner, director of sales and marketing at the company, in a statement. The company said the new production facility will offer a 233% increase in manufacturing and production capacity. According to PLIDCO, the Strongsville facility was formerly occupied by Sumitomo DeMag, a unit of Tokyo-based Sumitomo Heavy Industries Inc. Sumitomo DeMag had acquired the plant in its acquisition of DeMag Plastics Co. of Germany. The Strongsville operation was originally part of the Van Dorn Co. of Cleveland.
Range Resources cut back some production in third quarter – Range Resources Corp. this fall curtailed some of its natural gas production as it waits for higher prices the industry hopes will come with a colder winter and increased demand for the product. Range, which is based in Texas but whose regional headquarters and drilling are in southwestern Pennsylvania, said it curtailed 210 million cubic feet of natural gas per day through the last two weeks of September and most of October. Range joins other producers, including EQT Corp. and CNX Resources Corp, in curtailments that have all but returned to normal as gas prices start to climb. Range’s production returned to normal Oct. 28. CEO Jeff Ventura said that while natural gas prices are showing signs of improving for 2021 and 2022, the price isn’t enough to allow for any growth in production. “Range will seek to maintain production around current levels and optimize cash flow similar to our capital programs this year and use excess cash flow to reduce debt and ultimately return this free cash flow to shareholders,” Ventura said during the company’s third-quarter conference call. Nineteen new wells were put into service in the third quarter, and seven more are planned for the rest of the year. Gas prices have taken a hit in the quarter because storage levels remain high as well as some maintenance and delays on pipelines that would have taken natural gas produced here in the Marcellus and Utica out of the system. It expects natural gas liquids prices to increase, though. Range is also working to get the best prices for its products with its hedging policy, where it contracts natural gas at a certain price months in advance. About 75% of its production for the rest of the year is hedged and it has hedges for about 1 billion cubic feet per day of natural gas production in 2021. It has about 2.24 billion cubic feet per day of production.
Pennsylvania DEP official: Trusting Sunoco Pipeline ‘has come back to bite us’ again and again — A Pennsylvania official said Friday that environmental regulators were fed up with Sunoco Pipeline LP’s “history of poor compliance” in the construction of its Mariner East project, which led to its dramatic decision last month to halt construction in Chester County where Sunoco’s work polluted a popular state park lake.”It’s at a point where we have taken the company’s word countless times over and over and over again, and it has come back to bite us on numerous occasions,” Domenic Rocco, director of regional permit coordination for the Pennsylvania Department of Environmental Protection, testified Friday. Rocco’s testimony came on the fourth day of hearings before Environmental Hearing Board Judge Bernard A. Labuskes Jr., who is considering Sunoco’s emergency request to override DEP’s order last month to abandon a half-mile route along its Mariner East 2 pipeline, which would transport natural gas liquids like propane, and to take a costly detour. DEP ordered Sunoco to abandon its ongoing operation to horizontally drill the Mariner East 2 pipeline along Little Conestoga Road in Upper Uwchlan Township after about 8,000 gallons of drilling fluid leaked to the surface on Aug. 10 and polluted the lake at Marsh Creek State Park. Sunoco Pipeline, a unit of Energy Transfer LP of Texas, called the state’s order “arbitrary, capricious, and an abuse of its discretion” and asked the hearing board to overturn the decision. Sunoco said the new route would cause more environmental harm, make it abandon $17 million of work, and add up to $19 million in costs. It would also delay completion by two years. The hearing, conducted online, included a parade of expert witnesses who testified about the technical details of what went wrong with Sunoco’s project and what can be done going forward to reduce risks. DEP portrayed the continued use of the planned underground drill route near Marsh Creek as risky because of the unstable bedrock. And it said that although Sunoco knew of the risks, it did not take sufficient precautions to reduce chances that drilling fluids would leak through fractures to the surface and pollute Marsh Creek.The DEP’s Rocco also made clear that DEP had run out of patience with Sunoco and produced an elaborate spreadsheet documenting its violations – $15.9 million in fines over four years and numerous mishaps. These included 159 leaks of drilling mud during horizontal directional drilling (HDD), a process by which the company drills a cavity underground into which the pipeline is pulled, rather than burying the pipe in a trench near the surface. “It got to the point where we had to take an action,” Rocco said. “We basically said, `Enough is enough.’ ” Sunoco Pipeline says a state-ordered one-mile detour of its Mariner East 2 pipeline, shown in this diagram, would add two years and $12 million to $19 million in costs to the project. The new route would take the pipeline under the Pennsylvania Turnpike two times, and encroach on the properties of five homes. The spills – or “inadvertent returns” – of drilling fluid typically contain a mixture of bentonite clay and water, which is classified as an industrial waste. The Marsh Creek incident left a 15-foot wide sinkhole near the lake, and 33 acres of the lake remain closed to boating and other uses.
Energy Transfer Converting Portion of Mariner East, Expects DAPL to Continue Operating – – Energy Transfer LP (ET) is in the process of converting a portion of the Mariner East natural gas liquids (NGL) pipeline to refined products to capture price blowouts between Chicago and New York markets this winter. Newly named Co-CEO Mackie McCrea told investors during the third quarter earnings call last Wednesday the repurposed portion of the eight-inch diameter Mariner 1 line is expected to be in service by the end of the year. The conversion to refined products “should provide significant upside revenue for an asset that doesn’t limit us for what we can do with the remaining portions of the Mariner system.”Mariner East consists of three pipelines that move NGLs from processing facilities in Ohio, Pennsylvania and West Virginia to the Marcus Hook Industrial Complex near Philadelphia.ET expects to continue transporting all the liquefied petroleum gas and ethylene that is contracted on Mariner East. It’s also in the process of contracting additional volumes, McCrea said. The partnership experienced the highest average quarterly volumes through the pipeline system, with year-to-date NGL volumes up 40% over a year-to-date 2019. NGLs, particularly in West Texas and, “to a certain degree,” the Eagle Ford Shale in South Texas, are core areas for ET’s midstream assets. Management is “somewhat optimistic” that West Texas Intermediate oil prices remained near the $40/bbl mark since May, according to McCrea. In talking to producer customers, and taking into account the number of drilled but uncompleted wells in West Texas, management thinks producer customers may be “drilling around a lot of these areas.”ET expects to see 15-20% volumes growth “by the end of next year,” McCrea said. “I wouldn’t say we’re overly bullish, but we’re certainly optimistic that we’ll see volumes grow on our systems.” The midstreamer also remains confident that Dakota Access Pipeline (DAPL) should continue operating despite various appeals. An appeals process with respect to Lake Oahe litigation is ongoing; oral arguments took place last Wednesday.”We continue to believe that our legal positions in the case are strong, and we are confident that our pipeline will continue to operate as normal,” said CFO Tom Long. “The pipeline remains in service today and like all of our assets, we will continue to operate it safely and efficiently.” ET also is moving forward with the Bakken Shale pipeline’s capacity optimization. Last month, it received regulatory approval from the Illinois Commerce Commission, the last remaining state regulatory approval required to proceed. The initial phase of the optimization would accommodate the volume commitments made by shippers in open seasons.
Energy Transfer to finish Pa. Mariner East 2X NGL pipe by year end (Reuters) – U.S. energy company Energy Transfer LP said it plans to finish work on its Mariner East 2X natural gas liquids pipeline in Pennsylvania by the end of the year and the final phase of the Mariner East projects in the second quarter of 2021. Mariner East transports liquids from the Marcellus/Utica shale in western Pennsylvania to customers in the state and elsewhere, including international exports from Energy Transfer’s Marcus Hook complex near Philadelphia. Sunoco started work on the $2.5 billion Mariner East expansion in February 2017 and planned to finish the 350-mile (563-km) pipeline in the third quarter of 2017. Mariner East 2 did not enter service until December 2018 due primarily to several work stoppages by state agencies. Since May 2017, Pennsylvania has issued 118 notices of violation to Mariner East, mostly for drilling fluid spills, including one in October. Energy Transfer also said on its earnings call on Wednesday that it will use part of the eight-inch (20.3-centimeter) Mariner East 1 pipe for its new Pennsylvania Access project to bring refined products from the Midwest into Pennsylvania. “This project will require minimal capital … and will add significant revenue,” Energy Transfer CFO Thomas Long said, noting early volumes will likely flow in the fourth quarter. Mariner East 1 started service in the 1930s transporting refined products from the Philadelphia area to western Pennsylvania. It was repurposed and expanded to transport propane in 2014 and ethane in 2016. Mariner East 2, which uses mostly 20-inch pipe, boosted total capacity of the system from 70,000 barrels per day (bpd) to 345,000 bpd. Energy Transfer temporarily used sections of 16-inch and 12-inch pipe in Chester and Delaware counties to put Mariner East 2 into service where the 20-inch pipe was still under construction. The 16-inch Mariner East 2X will add another 250,000 bpd to the system.
Energy Transfer’s Claims Against Protesters Partially Dismissed – Energy Transfer Partners LP, Sunoco Pipeline LP, and Sunoco Logistics LP lost their attempt to pursue nuisance and interference counterclaims against a protester who was arrested at their Mariner East 2 Pipeline project in Pennsylvania, after a ruling by a federal court in the state. The U.S. District Court for the Middle District of Pennsylvania’s ruling came as a win for Ellen Gerhart, who was sentenced to a $2,000 fine and two to six months’ imprisonment for indirect criminal contempt by a state court. Gerhart allegedly baited bears to the site, set fires, and obstructed workers to stop pipeline construction,…
Banning Fracking Isn’t Bad Politics, It’s Good Science – In this year’s vice presidential debate, Senator Kamala Harris reiterated Democratic nominee Joe Biden‘s rejection of a fracking ban, despite her earlier call for one when she was a presidential candidate. “I will repeat, and the American people know, that Joe Biden will not ban fracking. That is a fact,” Harris said. Whenever there are discussions about banning fracking, media coverage seems to prioritize potential “risks” to Democrats’ electoral prospects, or potential economic downturns. Unfortunately, a lot of this coverage is quite sloppy. For instance, the New York Times quoted absurd claims that a fracking ban would mean “hundreds of thousands” of Pennsylvanians would be “unemployed overnight.” In reality, about 26,000 people work in all of Pennsylvania’s oil and gas sector. Still, the Times suggested that any presidential candidate who supports a national fracking ban would risk losing Pennsylvania, calling the issue “a political bet.” A fracking ban “could jeopardize any presidential candidate’s chances of winning this most critical of battleground states – and thus the presidency itself,” the paper wrote. NPR likewise made dubious pronouncements on the opinions of swing-state voters the focal point of the story, reporting that “aggressive” climate action “could push moderate voters in key swing states to reelect President Trump,” and even cited – without rebuttal – a claim from the U.S. Chamber of Commerce that a fracking ban would eliminate 17 percent of all U.S. jobs. Soon after the debate, Quartz explained that Biden and Harris don’t support a fracking ban because it “tempts political suicide in swing states like Pennsylvania and Ohio where fossil fuels still rule.” And the Los Angeles Timesdescribed Biden’s opposition to a fracking ban as a “nuanced position.” There are two big problems with these arguments. First, journalist David Sirota pointed out, “the idea that a fracking ban is political poison in Pennsylvania” simply “isn’t substantiated by empirical data.” Second, there’s simple climate science. In 2018, the UN announced that carbon pollution needs to be cut by 45 percentby 2030 to prevent irreversible planetary devastation. Unfortunately, fracking releases large amounts of methane into the atmosphere, which can warm the planet 80 times more than the same amount of carbon dioxide over a 20-year period. And recent reporting has suggestedthat fracking is an even bigger contributor to global warming than previously believed.
Oil and natural gas are our best bet for continued economic recovery – by Dan Brouillette US Secretary of Energy – No matter where you stand, the truth is that arbitrarily halting oil and natural gas development would do serious harm to our economy, jeopardize America’s post-pandemic recovery, and deny ourselves of a critical innovation engine for cleaner technologies.Businesses need reliable, low-cost energy to reopen and return to normal operations. With fossil fuels currently accounting for 80 percent of overall American energy production, including the vast majority of power supplied in the industrial and commercial sectors, removing those sources of power as an option would add uncertainty and higher costs to an already difficult business environment.At the start of this year, the oil and gas industry was responsible for 12.3 million American jobs. Some of those workers were laid off during the early days of the pandemic, but as demand returns, so, too, will job opportunities.However, crushing the industry with more regulations or cutting production, a clear goal of some policymakers, would cost even more oil and gas workers their jobs and destroy communities in energy producing states across our nation, like Alaska, Louisiana, New Mexico, North Dakota, Ohio, Oklahoma, Pennsylvania and Texas. We need to sustain employment in all sectors of the economy and get more people back to work.Between 2012 and 2025, the oil and gas industry is projected to support $1.6 trillion in federal and state tax revenue, supporting the maintenance of schools, hospitals and public infrastructure across the country. If the oil and gas revenue stream dries up, major public services will be reduced or even cut.The oil and gas industry are also a critical partner in developing clean and energy-efficient technology. The industry spends more than $4.5 billion annually on research and development, partnering with universities and research labs nationwide. This scientific pipeline and the innovations it brings will be shut off by proposals that over-regulate, tax and curb investment in the industry. Finally, we must keep more money in the pockets of American families, many of whom are now one-job households or are experiencing reduced hours. When families buy power from diverse energy suppliers, they are provided options, which lowers costs. Abundant oil and gas production help save American consumers an estimated $203 billion annually, or $2,500 for a family of four. That’s real money to many people who need it all across the country.
Biden’s fracking stance may cut 19M jobs, raise electric prices: Energy secretary | Fox Business – A Joe Biden presidency could undo the fracking executive order, which could come at astronomical costs to the U.S. The abolishment of hydraulic fracturing technology could lead to the loss of 19 million jobs, according to U.S. Secretary of Energy Dan Brouillette. “This technology, hydraulic fracturing, has produced the largest economic boom that we have known in our lifetimes,” Brouillette told Stuart Varney on FOX Business’ “Varney & Co.” “We are now a net energy exporter in the United States. The one thing that can’t be undone is the economic progress that’s occurred since this president took office in 2017. It has been enormous. Absolutely enormous.” Energy prices in the outlook of a Biden future would also hurt consumers, Brouillette pointed out. Prices on electricity and natural gas would skyrocket. Fracking also produces crude oil, and its elimination could potentially increase the price of gasoline throughout the country.
Op-ed: A fact-based conversation about fracking – Randi Pokladnik – Fracking has contaminated water wells and a 2020 article in the Journal of Petroleum Technology stated “wellbore integrity cannot be taken for granted.” The XTO Energy well blowout in Belmont County in February 2018 was from a “failure of the gas well’s casing or internal lining.” This blowout released the equivalent of an entire year’s worth of methane by oil and gas industries in countries like France. Methane gas is much more potent than carbon dioxide as a heat-trapping gas and according to a study in Biogeosciences, a significant portion of the anthropocentric methane emission increases are due to the fracking boom in North America.The waste water left over after a well is fracked is known as “produced water.” In addition to brine, which is a result of the prehistoric conditions which formed the oil and gas reserves, the waste also contains radioactive materials (Radium -226 and Radium-228) and any chemicals initially injected with the fluid.In 1978, the EPA exempted oil and gas wastes from exploration and production activities from the hazardous waste management program Subtitle C of the Resource Conservation and Recovery Act. This includes produced water, drilling fluids and drill cuttings. Yet, in 2002 the EPA admitted that just because the wastes were exempt this did not mean that wastes could not present a hazard to human health and the environment.The oil and gas industries are also exempt or excluded from certain sections of these federal environmental laws: Clean Air Act, Clean Water Act, Safe Drinking Water Act, National Environmental Policy Act and Emergency Planning and Community Right-to Know Act.To claim that “millions of jobs” will go away if fracking is banned is misleading at best. The industry has been in decline for several years. An August 2020 article in OilPrice.com stated,”Driven by low prices not seen much in modern history, formerly high-flying shale drillers like Chesapeake Energy have gone bankrupt. The Service providers like Halliburton and Schlumberger have written off tens of billions worth of fracking-related equipment, closed facilities and laid off thousands of workers.”Unlike oil and gas, solar and wind “feedstock” is free and as pointed out in a recent CleanTechnica article, “it takes years to design, build and activate any coal or gas-powered facility.” A 50 MW wind farm can be built in six months. Residential solar can be installed in a few days. Internal reports show oil and gas industry scientists knew back in the 1980s about the negative effects their products would have on the earth’s climate. Yet, for nearly thirty years they spent millions of dollars promoting climate denial. They also realized clean renewable energy is quickly replacing dirty fossil fuels. In order to save their bottom line, they are now pushing plastics production as a use for fracked gas.
Officials begin evaluation of oil spill cleanup efforts along Del., Md. coastline – The Unified Command for the Delaware Bay and Atlantic coastal beaches oil response has begun the process of evaluating cleanup operations across sections of Delaware and Maryland coastline impacted by tar balls and oiled debris to determine how much of the beach cleanup has been completed. We’re told the evaluation process requires an assessment using stringent federal and state guidelines to determine whether cleanup crews have been successful in their efforts or whether more work is required. “We have good reason to believe from our on-scene monitoring that the clearance of oil and cleanup efforts of oily debris from the beaches are largely complete. I would like to emphasize that people may continue to see small bits of oil or oily debris coming ashore here and there,” said Delaware Department of Natural Resources and Environmental Control Secretary Shawn Garvin. “The Unified Command of DNREC and the U.S. Coast Guard is following the outgoing high tide today to get an accurate accounting on a decision to sign off the cleanup or continue it at respective locations.” Cleanup crews will continue to respond to beaches that have been cleared, should more impacts be spotted during shoreline assessments. As beaches are cleared, crews are positioned to shift resources to areas that may need further attention. To date, crews have collected and disposed of more than 75 tons of oiled debris and tar balls. The cleanup effort today was continuing from points north to Cape Henlopen to the Atlantic beaches to Fenwick Island. Officials say the cause of the spill remains unknown, but the investigation is continuing by the U.S. Coast Guard. If a source is identified, the responsible party would be required to reimburse the federal government for the cleanup operation. The public may still see small spots of oil or isolated bits of debris. Any large portions of oil or oily debris on the sand or in the water should be reported.
Tennessee Gas and contractor to pay $800,000 in penalties, repairs over controversial natural gas project in Otis State Forest – Tennessee Gas Pipeline Company and its contractor which installed a controversial natural gas line through Otis State Forest will pay a total of $800,000 in fines and to make repairs after damaging an ecologically-important vernal pool, failing to protect wetlands and damaging the roadway during the construction.Tennessee Gas Pipeline Company and its contractor Henkels & McCoy, Inc. will make about $300,000 in penalties and payments to the Massachusetts Natural Resource Damages Trust and will spend about $500,000 to repave part of Cold Spring Road, in Sandisfield, according to the agreement between the company and its contractor Henkels & McCoy Inc. and Massachusetts Attorney General Maura Healey.The damage was done in 2017 while the company was installing a four-mile line through Otis State Forest as part of a 14-mile pipe extension that cut through New York and Connecticut. The work drew multiple protests and led to more than a dozen arrests for civil disobedience.Under the claim, Tennessee Gas was accused of failing to maintain erosion and sediment controls causing soil and sediment to run into more than 630 square feet of wetlands. It was also accused of excavating and filling portions of a vernal pool and shutting down a required pump temporarily degrading water quality in Spectacle Pond Brook, the Attorney General’s office said in announcing the settlement.In a second location, the companies were also accused of dumping 15,000 gallons of contaminated pipeline test water directly onto the ground adjacent to Tennessee Gas’ pipeline compressor station in Agawam, the announcement said. “Tennessee Gas repeatedly assured the state and Sandisfield residents that water quality and wetlands would be protected during pipeline construction, but they failed to make that happen,” Healey said in writing. “My office will continue to hold accountable those who violate our critical environmental protection laws.”
Williams Reports Record Appalachian Natural Gas Volumes Amid Stronger Pricing – Midstream giant Williams reported record natural gas gathering and processing (G&P) volumes in the Appalachian region during the third quarter, driven by higher prices in the region. Gross gathering volumes for the Northeast G&P segment rose 8% year/year (y/y) to 9.4 Bcf/d, while gross processing plant inlet volumes swelled by 17% to 1.4 Bcf/d, management said during a third quarter earnings conference call. Natural gas liquids (NGL) production volumes from the segment rose 24% to 114 million b/d. The volumes were all-time highs across the board for the Tulsa-based operator. Recent highlights for Williams also include the partial in-service of the Southeastern Trail expansion of the flagship Transcontinental Gas Pipe Line Co. LLC (Transco) system. The company brought 150 MMcf/d of the 296 MMcf/d expansion online Nov. 1. Up to an additional 80 MMcf/d is expected online before the end of the year, with the balance of the expansion expected in-service in early 2021. Williams also filed a Federal Energy Regulatory Commission pre-filing application in June for the 760 MMcf/d Regional Energy Access expansion on Transco, which aims to connect Marcellus Shale gas supplies with growing Northeast demand in time for the 2023-2024 heating season. “This strong performance is evidence of the attractive position of our Northeast business as gas market fundamentals begin to call on U.S. dry gas supplies,” CEO Alan Armstrong told analysts. He highlighted that Williams is the largest gatherer in the Appalachian Basin, the country’s most prolific source of gas production, propelled by the Marcellus and Utica shales. “Our dedications include the most attractive acreage operated by resilient producers that continue to demonstrate their ability to continuously improve on their cost structures,” he said. “You can see this playing out as our Northeast gathering volumes grew faster than the total Northeast supplies … “So we really are not only in the right basin, but we’re also in the right parts of the basin in the Appalachian area. We expect this trend to continue in response to the very favorable forward strip pricing in ’21 and a very well-positioned group of customers in both the Marcellus and Utica.” Williams expects to meet its pre-Covid 2020 earnings guidance set last December. Armstrong attributed the company’s durability to “the premier positions of our natural gas infrastructure” and measures taken “to reduce leverage, increase stability and lower costs … Our gathering and processing business continues to benefit from our basin diversity, specifically in gas-directed areas where drilling remains active. “In addition, we continue to grow services to key producers in the Gulf of Mexico deepwater, where we have major dedications.”
Agency declines to stop work on Mountain Valley Pipeline, foes again turn to court – The U.S. Fish and Wildlife Service is standing by its opinion that tree cutting and stream fording for a massive pipeline will not imperil endangered or threatened species. One week after environmental groups asked the service to stay its biological opinion for the Mountain Valley Pipeline, pending a legal challenge, the agency declined the request on Monday. Within hours, the Sierra Club had filed a petition seeking a delay from the 4th U.S. Circuit Court of Appeals. The Richmond-based court has already temporarily stayed a second set of permits, in which the U.S. Army Corps of Engineers authorized the buried natural gas pipeline to cross nearly 1,000 streams and wetlands. What happens in the coming weeks will likely determine whether Mountain Valley can meet its goal of completing construction by early next year. In August 2019, a coalition of environmental groups challenged a 2017 biological opinion in which the Fish and Wildlife Service said pipeline construction is not likely to jeopardize two protected fish, the Roanoke logperch and the candy darter, or two species of bats, the Indiana and northern long-eared bat. After the 4th Circuit stayed the opinion in October 2019, the Fish and Wildlife Service spent a year reviewing its evidence before issuing a new opinion Sept. 4 that was essentially the same as the first. The Sierra Club and 10 other environmental and conservation groups sued a second time. “The record shows that the Fish and Wildlife Service has again cut corners, ignored or weakened technical standards, and excluded pertinent facts without justification in approving of damages to endangered fish species and bats,” read a statement from David Sligh with Wild Virginia, one of the groups involved in the lawsuit. According to the petition, resuming work on the often-delayed, $5.7 billion project would again clog streams with sediment, pushing the Roanoke logperch and the candy darter closer to extinction. And cutting trees for a 125-foot right of way has already destroyed the habitat of protected bats along the largely rural and mountainous route of the pipeline, the groups allege. The Fish and Wildlife Service conducted only a “cursory analysis” before concluding that no cumulative effects were expected in an area of more than a million acres and 1,163 miles of streams and rivers, the petition states. In asking for a stay before the case is decided, the Sierra Club said in court papers that heavy machinery and construction activity has been observed along the pipeline’s 303-mile path through West Virginia and Southwest Virginia. . Work is currently allowed in all areas except for stream crossings and a segment of the pipeline that passes through a national forest.
Environmental Groups Ask Federal Court To Once Again Stop Construction Of The Mountain Valley Pipeline — Environmental organizations, led by local advocacy group Appalachian Voices, have once again asked a federal court to halt construction of the Mountain Valley Pipeline. In a motion filed Monday in the U.S. Court of Appeals for the Fourth Circuit, the groups asked the court to stop construction of the 303-mile natural gas pipeline, which is more than 90 percent completed, while the federal bench sorts through the legality around two newly reissued federal permits. The permits, reissued by the U.S. Fish and Wildlife Service in early September, include the Biological Opinion and Incidental Take Statement for the Mountain Valley Pipeline. The permits address concerns around how the project could impact endangered species. In October 2019, the Fourth Circuit tossed the project’s Biological Opinion and halted the project following a similar lawsuit by environmental groups. In the new motion, Appalachian Voices argues the agency did not consider all of the appropriate information before reissuing the approvals. The project, from developer EQT, goes through northwestern West Virginia and southern Virginia. In the Mountain State it crosses Wetzel, Harrison, Doddridge, Lewis, Braxton, Webster, Nicholas, Greenbrier, Fayette, Summers, and Monroe Counties. The project has faced several court challenges in the past two years over state and federal permits on both sides of the border. The multi-billion dollar project would carry 2 billion cubic feet of natural gas from the Marcellus and Utica shale formations to markets on the East Coast. In a separate lawsuit, environmental groups are also challenging a permit that allows the pipeline to cross streams and wetlands. The Fourth Circuit hastemporarily blocked construction across waterways. Oral arguments are scheduled for Nov. 9.
Another delay, cost increase for the Mountain Valley Pipeline – The Mountain Valley Pipeline has once again pushed its completion date back and the project cost up. Equitrans Midstream Corp., the lead partner in a joint venture of five energy companies that has faced widespread environmental problems while building the natural gas pipeline, made the announcement Tuesday. Rather than completing construction early next year as planned, the company is now targeting a full in-service date “during the second half of 2021,” a news release stated. The cost, which was estimated to be $3.7 billion when construction started in 2018, now stands at between $5.8 billion and $6 billion. The latest increase was attributed largely to the more costly task of continuing construction through the winter, which Mountain Valley plans to do in order to make up time lost to legal challenges. Despite the latest setback, Equitrans chairman and CEO Thomas Karam remained bullish on the project during a conference call to discuss third quarter results with financial analysts. “Our confidence has not changed because of these expected challenges, at all,” he said. Environmentalists say the buried pipeline will sully the scenic landscape of Southwest Virginia, clog its streams and rivers with harmful sediment washed from construction sites, and jeopardize endangered species of fish and bats. The Sierra Club and similar groups have challenged about a half-dozen permits issued to Mountain Valley over the past three years. Last month, a federal appeals court temporarily stayed a set of steam-crossing permits while it considers the case, and approval for the pipeline to pass through the Jefferson National Forest is still pending. Another lawsuit was filed last week against the U.S. Fish and Wildlife Service over its conclusion that the pipeline would not jeopardize protected species. Nonetheless, the Federal Energy Regulatory Commission recently lifted a year-long stop work order, and construction crews are gearing up along the pipeline’s 303-mile path through West Virginia and Southwest Virginia.
Equitrans reports increased cost estimate, delayed in-service date for Mountain Valley Pipeline –Equitrans Midstream Corporation (ETRN) said this week that the cost estimate of the Mountain Valley Pipeline (MVP) is now between $5.8 billion and $6 billion and the project’s full in-service date is anticipated during the second half of 2021. MVP is a proposed underground, interstate natural gas pipeline system, expected to span roughly 303 miles from northwestern West Virginia to Southern Virginia and designed to transport clean-burning natural gas from the Marcellus and Utica shale regions. When construction started on the pipeline in 2018, the cost was estimated to be $3.7 billion. In its financial and operational report for the third quarter, ETRN attributes the latest increase to the more costly task of continuing construction through the winter following unanticipated legal delays during the prime 2020 construction season. A major breakthrough for the project was the recent lift of a year-long stop work order from the Federal Energy Regulatory Commission, allowing MVP to move forward with construction along the majority of the route. Environmental groups have long opposed the pipeline, however, arguing that it will mar the landscape of southwest Virginia, clog streams and rivers with harmful sediment washed from its construction, and jeopardize endangered species of fish and bats in the region. The activist groups have challenged several permits issued to MVP over the last three years, including a lawsuit filed last week against the U.S. Fish and Wildlife Service over its conclusion that the pipeline would not affect protected species. In September, MVP received the project’s new Biological Opinion. A challenge was filed against the Biological Opinion in late October. Additionally, shortly after receiving approval for the project’s Nationwide Permit 12 (NWP12) from the U.S. Army Corps of Engineers, the Fourth Circuit Court of Appeals issued a temporary administrative stay of the MWP12, preventing construction of waterbody crossings under the USACE’s MWP12 program until the Court rules on the full motion to stay. The Court scheduled oral arguments for Nov. 9.
Equitrans confident Mountain Valley Pipeline will be complete in 2021 – Equitrans Midstream Corp. executives expressed confidence the Mountain Valley Pipeline would be completed in 2021 despite the myriad of legal action and other challenges that have led it to miss completion deadlines and seen the cost jump to what is now expected to be nearly $6 billion. Equitrans earlier Tuesday had moved the full in-service date for the Mountain Valley Pipeline from early 2021 to the second half of 2021. Costs have gone from the estimated $5.4 billion most recently to what the company now says will be between $5.8 billion and $6 billion. “While we are disappointed with the setbacks that have led to cost increases and delays, we remain steadfast that MVP will reach completion and, more importantly, that the value of this critical infrastructure project will be realized,” said Equitrans President Diana Charletta during the company’s third-quarter earnings call. Between Tuesday’s announcement and the conference call there was some good news for Equitrans: The Federal Energy Regulatory Commission had approved variances requested by Equitrans and the U.S. Forest Service over some work in the Jefferson National Forest. FERC in October had removed its stop-work order to allow construction but a key U.S. Army Corps of Engineers permit that would allow waterbody crossings has been challenged in court and is the subject of a U.S. Fourth Circuit Court of Appeals temporary stay. Oral arguments in the stay are set for Nov. 9. “We’ve made progress on the regulatory front with MVP and are back to forward construction,” said CEO Tom Karam. Monday afternoon, opponents of the MVP filed a motion to stay the biological opinion of environmental impact that was given by the U.S. Fish and Wildlife Service. Karam said it wasn’t unexpected. “We remain confident in the strength of MVP’s revised biological opinion and we’re preparing a response to that motion,” Karam said. “Our confidence has not changed because of these expected challenges at all. We will continue to work with our partners, our federal and state agencies, to complete the pipeline in 2021.”
Photos: Work resumes on the Mountain Valley Pipeline — As work gears up on the Mountain Valley Pipeline, construction crews in Roanoke and Franklin counties are confronting some of the steepest mountain slopes along its 303-mile path.In early October – before the Federal Energy Regulatory Commission allowed work to resume – Roanoke County sent a letter to the commission expressing concerns about Mountain Valley’s “continuing inability to manage erosion and sediment impacts for the project.”Assistant County Administrator Richard Caywood wrote that the problems could worsen as construction continues through the winter, when grass and other vegetation planted to control erosion is unlikely to take root.FERC did not respond to the county’s Oct. 6 letter. “It’s typically a one-way street with these types of things,” Caywood said Thursday.
Limpert: More volume in pipeline means more risk – Two recent announcements portend even more risk for citizens along the unneeded and unjust Mountain Valley Pipeline. The MVP announced it may increase volume from 2 to 2.5 billion cubic feet per day (bcf/d), and the EPA announced that it is eliminating pipeline leakage rules. More gas and more leaks is a recipe for disaster. A recent study found that natural gas transmission lines, like the MVP, average losses of 0.35% through leaks and intentional discharges, with 90% of the losses from leaks. A 0.35% loss at 2 bcf/d is 7 million cubic feet per day. At 2.5 bcf/d those losses increase to 8.75 million cubic feet per day. Relaxing leak standards will likely further increase these already high volume losses. Everything that would leak or be discharged from the MVP is a pollutant. This pollution would enter our environment, and could enter our bodies through inhalation or ingestion. The natural gas that would be lost from the MVP is around 95% methane. Methane is a very potent greenhouse gas. Over a 20-year period methane is 84 times a more potent greenhouse gas than carbon dioxide. Methane levels in our atmosphere are already 2.5 times higher than prior to the industrial revolution, and higher than they have been in at least the past 800,000 years. These levels are expected to continue to rise if natural gas use continues. This will further worsen climate change. Methane is also highly explosive. More pressure required to move the increased volume of gas in the MVP would result in an even more catastrophic explosion should the pipe fail. Leaks that continue as a result of the EPA rule elimination could result in pipe failure and explosion. The remaining 5% of the gas stream is a witch’s brew of carcinogens, mutagens, toxins and radioactive materials with significant health and environmental impacts. It includes ethane, propane, butane, pentane, hexane, heptane, octane, hydrogen sulfide, benzene, toluene, benzoic acid and naphthaline. All have negative health impacts, and many are extremely dangerous, even in small amounts. The gas stream also includes radioactive substances. These include, but may not be limited to radon-222, lead-210 and polonium-210. EPA has determined that radon-222 causes 21,000 lung cancer deaths per year in our country. Lead is an extremely toxic metal, and even in its nonradioactive state it is listed second on the Agency for Toxic Substances and Disease Registry priority list, only behind arsenic. One microgram of polonium-210 is more than enough to kill a person. All of these pollutants are likely to be discharged every day from the MVP. William Limpert is a retired environmental regulator who formerly lived in Bath County along the route of the Atlantic Coast Pipeline.
Putting a pipeline through a forest: a foregone conclusion? – When public agencies and boards made crucial decisions about the Mountain Valley Pipeline, the outcome was often influenced by a pro-industry panel called the Federal Energy Regulatory Commission. That, at least, has been the mantra of opponents to the natural gas pipeline being built through the New River and Roanoke valleys. But shortly after the U.S. Forest Service allowed Mountain Valley to pass through the Jefferson National Forest in 2017, one of the agency’s regional planning directors who was involved in the process reached the same conclusion. The Forest Service “was not in the driver’s seat” when it came to making a final decision, Peter Gaulke wrote in an email to colleagues. FERC was. “It is fair to say there were pains of adjustment as we tried to merge our USFS way of business with the FERC way of business,” Gaulke wrote in a Nov. 28, 2017, review of the process. “This was not easy and still has a level of discomfort for the Forest and the Regional Office,” the email stated. One of the key issues was whether building the 303-mile interstate pipeline – the largest such project ever proposed in the Jefferson National Forest – would produce more erosion and sedimentation than the public woodlands could bear. Gaulke’s email, provided to The Roanoke Times in response to a Freedom of Information Act request, is “shocking and eye-opening,” said Rupert Cutler of Roanoke, who oversaw the Forest Service as assistant secretary of agriculture from 1977 to 1980. “It proves that the Forest Service felt emasculated and victimized by the FERC-dominated MVP decision-making process,” Cutler said. Eight months after Gaulke raised his concerns, the 4th U.S. Circuit Court of Appeals threw out Mountain Valley’s permit to cross 3.5 miles of the national forest. Siding with the Sierra Club and other environmental groups, the court found that the Forest Service was too accepting of the company’s assurances that erosion would not be a major problem.
Dominion closes on sale of majority of natural gas assets -Richmond-based Dominion Energy Inc. announced Monday that it has closed on the sale of the majority of its gas transmission and storage assets to Berkshire Hathaway Energy (a Berkshire Hathaway Inc. affiliate) for approximately $2.7 billion in cash and the transfer of approximately $5.3 billion of related indebtedness.In July following the cancelation of the Atlantic Coast Pipeline project, Dominion announced that it had entered into a definitive agreement to sell off its gas transmission and storage segment assets for $9.7 billion, including the assumption of $5.7 billion in existing debt to abandon the pipeline project. The 600-mile, $8 billion-plus natural gas pipeline was supposed to run from West Virginia through Virginia to eastern North Carolina.The deal announced Monday includes more than 5,500 miles of interstate gas transmission pipelines, approximately 775 billion cubic feet (Bcf) of gas storage that the company operates and an operating 25% stake in the Cove Point gas liquefaction facility in Maryland. The sale is expected to be complete in early 2021 following a Hart-Scott-Rodino clearance, which provides the Federal Trade Commission and Department of Justice information about large acquisitions prior to completion. Dominion has also received an approximate $1.3 billion cash payment in anticipation of the sale of the interests. It will transfer approximately $430 million of related debt to Berkshire Hathaway Energy upon closing. Announced in 2014 and originally planned to begin transporting natural gas by late 2019, the Atlantic Coast Pipeline was delayed by legal proceedings and opposition from environmental groups and landowners in the pathway of the pipeline’s construction route. On June 15, the U.S. Supreme Court handed down a ruling that would have allowed the pipeline to cross under the Appalachian Trail, hailed by Dominion and Duke as a major victory toward completing the pipeline, which was identified by the Trump administration as a priority infrastructure project. Before announcing the project’s cancellation, Dominion and Duke Energy Corp. had hoped to put the pipeline into operation by 2022. The transaction is expected to reduce Dominion Energy’s debt by $6 billion. The company also expects total share repurchases its common stock to be at least $3 billion.
Dominion comes full circle as it works to offload remaining US gas pipeline assets – Dominion Energy is on the verge of returning to its utility roots as it nears offloading the remainder of its US natural gas pipeline assets to Berkshire Hathaway, CEO Thomas Farrell said Nov. 5. With electricity demand stable or growing in parts of its business and more revenue certainty from operating in regulated markets, Dominion sees its future much the way it started. That’s a reversal from the hybrid utility energy infrastructure company that Farrell and other executives sought to build in recent years with the acquisition of Questar Pipeline, the construction of the Cove Point LNG export facility in Maryland, and the proposal to build the Atlantic Coast Pipeline to deliver more Appalachian Basin gas to downstream utility customers. In July, Berkshire Hathaway agreed to buy substantially all of Dominion’s gas pipeline and storage assets for $4 billion in cash and the assumption of $5.7 billion in debt. Berkshire Hathaway completed the purchase of the bulk of the assets earlier in November. The sale of the remaining 20%, including Questar and related infrastructure, is on track to lose in early 2021, Farrell said during a conference call to discuss Dominion’s third-quarter financial results.With the transaction, Berkshire Hathaway is now the operator of Cove Point, an important outlet for US gas to Europe and beyond with a capacity of about 5.25 million mt/year, and holds a 25% stake. Dominion retains a 50% passive ownership. When it announced the midstream assets sale, Dominion also scrapped the $8 billion Atlantic Coast Pipeline, amid ballooning costs and fierce legal opposition from environmental groups.”We believe that the investment proposition created through Dominion Energy’s strategic repositioning is compelling,” Farrell said. “We have a strong balance sheet and a significantly improved business risk profile.” While Dominion is shifting its focus back to its core regulated utility businesses, Berkshire Hathaway is making a bigger bet on gas midstream and LNG. Farrell said the strategy reversal is the right one for Dominion in an uncertain commodity market and US political environment.
Natural-Gas Drillers Outshine Oil Peers as Covid-19 Surges – The Wall Street Journal – A split reality is emerging for U.S. shale drillers: Those that primarily pump oil are still struggling to survive, while those that produce natural gas are slowly seeing signs of recovery.Oil-focused fracking companies are under extreme financial strain, as renewed concerns about the coronavirus pandemic are weighing down crude prices. But gas-focused drillers are getting a long-awaited reprieve. Natural-gas prices are climbing ahead of winter, and are less sensitive to lockdowns that erode demand for transportation fuels.U.S. benchmark oil prices tumbled about 11% last month to their lowest level since early June, before edging up to $36.81 a barrel on Monday, as some European countries imposed new lockdowns amid a resurgence in cases of Covid-19, the illness caused by the new coronavirus. Meanwhile, U.S. benchmark natural-gas prices soared 33% last month to their highest level in nearly two years, before settling slightly lower on Monday at $3.24 per million British thermal units.The result is a reversal of fortunes in the U.S. shale patch, where oil companies have long overshadowed their gas-focused peers. The market value of the six largest public Appalachian gas companies, including EQT Corp. and Range Resources Corp., has climbed about 18% since the start of 2020. That compares with a 53% drop in the combined market capitalization of the 25 largest U.S. oil companies, according to data from S&P Global Market Intelligence.”Being in natural gas, we think, is an important thing right now,” Marathon Petroleum Corp.MPC 1.95% Chief Executive Michael Hennigan said during the company’s third-quarter earnings call Monday.The Ohio-based refiner reported a $1 billion quarterly loss as its fuel-making business posted a $1.6 billion loss from operations, compared with $989 million in operating income during the same period last year. The company’s pipeline business, which includes natural-gas processing and transportation, helped to offset those losses, generating $960 million in operating income, up from $919 million a year earlier.U.S. shale-oil producers likely will struggle to hold production flat over the next two years, compared with December 2020 levels, ConocoPhillips COP -3.04% Chief Operating Officer Matt Fox said last week. The company expects U.S. shale drillers to pump 6.5 million to seven million barrels a day of oil in December, down from 8.2 million a year earlier.”If you compare that to the trajectory we were on, that’s at least four million barrels a day less than the pre-Covid trend,” Mr. Fox told analysts, explaining that production would likely have been up, not down, from a year earlier without the pandemic. ConocoPhillips, one of the largest independent U.S. oil producers, reported a $450 million loss for the third quarter, compared with a $3.1 billion profit a year earlier.
US natural gas futures fall on milder weather – US natural gas futures fell on Monday as forecasts indicated milder weather in the coming days, but prices stayed near a 21-month high hit in the last session on surging liquefied natural gas (LNG) exports. Front-month gas futures fell 11.0 cents, or 3.3%, to settle at $3.244 per million British thermal units. On Friday, the contract rose to its highest since January 2019 at $3.396. “Traders are focused on the short term weather outlook for mid-to-late November and with the heating degree days running warmer than normal, we are seeing selling this morning,” said Robert DiDona of Energy Ventures Analysis. However, demand is strong right now amid record LNG feedgas estimates from this past weekend, DiDona added. The amount of gas flowing to LNG export plants was near record peak as rising global prices over the past couple of months prompted buyers in Europe and Asia to purchase more US gas. Analysts said US utilities withdrew 18 billion cubic feet (bcf) of gas from storage in the week ended Oct. 30. That compares with an increase of 49 bcf during the same week last year and a five-year (2015-19) average build of 52 bcf. “With the arrival of November, HDD accumulation will exert more impact as far as weekly storage shifts are concerned,” advisory firm Ritterbusch and Associates said in a note. “We still see the dynamic of surplus contraction across this month as a powerful force that will be limiting downside price possibilities.” Data provider Refinitiv predicted 215 heating degree days (HDDs) over the next two weeks in the Lower 48 US states, compared with 213 forecast on Friday. HDDs measure the number of degrees a day’s average temperature is below 65 degrees Fahrenheit (18 degrees Celsius) and are used to estimate demand to heat homes and businesses.
US natural gas futures little changed on mild weather – – US natural gas futures were little changed on Wednesday as record liquefied natural gas (LNG) exports offset forecasts for milder weather and lower heating demand in mid-November and a steady rise in output. Front-month gas futures for December delivery slipped 1.3 cents to settle at $3.046 per million British thermal units. That put the contract down about 9% since hitting a 21-month high of $3.396 on Oct. 30 and lower for a third day in a row for the first time since early September. Those front-month declines caused the premium of the December 2021 contract over December 2020 to rise to its highest since April 2011. Data provider Refinitiv said output in the Lower 48 US states rose to an 11-week high of 90.3 billion cubic feet per day (bcfd) on Tuesday, up 4.8 bcfd since Hurricane Zeta hit the Gulf Coast on Oct. 28 as energy firms restored output from Gulf of Mexico wells shut ahead of the storm. Output averaged 89.6 bcfd so far in November, up from a five-month low of 87.4 bcfd in October. That, however, was still well below the all-time high of 95.4 bcfd in November 2019. Production declined earlier this year as low prices due to coronavirus demand destruction caused energy firms to shut oil and gas wells and cut drilling by so much that output from new wells no longer offsets existing well declines. With milder weather coming, Refinitiv projected demand, including exports, would drop from an average of 96.7 bcfd this week to 93.2 bcfd next week. That forecast is lower than Refinitiv expected on Tuesday. The amount of gas flowing to LNG export plants hit a record 10.2 bcfd on Tuesday as rising global prices over the past couple of months prompted buyers in Europe and Asia to purchase more US gas.
Early Storage Withdrawal Not Enough to Fuel December Natural Gas Futures – Natural gas futures gave up more ground Thursday – a fourth consecutive daily decline – as traders focused more on weather-induced demand weakness than the first storage withdrawal of the season, a bullish print that pointed to balances tightening ahead of winter. EIA storage Oct 30 The December Nymex contract fell 10.4 cents day/day and settled at $2.942/MMBtu. The front month had lost more than 9% over the three previous days. January shed 9.3 cents to $3.084. Spot gas prices declined, as well, amid mild fall temperatures across most of the Lower 48 that did little to spur either heating or cooling demand. NGI’s Spot Gas National Avg. dropped 17.5 cents to $2.170. As market observers anticipated, the U.S. Energy Information Administration (EIA) on Thursday reported a pull from natural gas storage for the week ending Oct 30. But the withdrawal of 36 Bcf exceeded expectations. Ahead of the report, a Bloomberg survey found a median estimate of a 31 Bcf decrease, while a Reuters poll landed at a median decrease of 27 Bcf. NGI forecast a 28 Bcf pull. Futures climbed ahead and immediately after the report in morning trading, but reversed course within a few minutes of EIA’s 10:30 ET release and hovered deep in the red through the rest of the day. The withdrawal, spurred by production shut-ins in the Gulf of Mexico ahead of Hurricane Zeta’s arrival last Wednesday and a cold blast that boosted heating demand as far south as Texas during the covered week, not only marked the first pull of the season but it arrived two weeks early when compared to historical norms. The result compared to a 49 Bcf injection a year earlier and the five-year average build for the week of 52 Bcf.
Weekly Natural Gas Prices Plunge as Mild Temperatures Sap Demand – Natural Gas Intelligence – In a stark reversal from the prior week, temperatures climbed rapidly out of freezing territory and into the 60s and 70s across much of the Midwest, cutting off heating demand and driving down weekly cash prices. NGI’s Weekly Spot Gas National Avg. for the Nov. 2-6 period nosedived 61.5 cents to $2.385 as comfortable fall temperatures settled in across most of the Lower 48. A week earlier, when an early shot of winter blanked the nation’s midsection, weekly prices jumped 59.5 cents. Between the two weeks, the early winter gave way to a late round of near summer-like weather in the Midwest, and temperatures elsewhere were generally mild, minimizing furnace and air conditioner use. Bespoke Weather Services said the week’s warmth put the current month on track to finish as one of the top five warmest Novembers on record in terms of gas-weighted degree days. The lack of weather-driven demand more than offset strong liquefied natural gas (LNG) levels. LNG feed gas volumes hovered in 2020 peak territory of around 10 Bcf throughout the week. “It remains a weather-versus-balance battle, but one that weather is winning as long as we see such high-end warmth,” the firm said. “We still have no clear hints that we will move colder even into the late-month at this time.” On the supply front, meanwhile, offshore production largely recovered during the latest covered week after widespread shut-ins a week earlier as Category 2 Hurricane Zeta barreled into the Gulf of Mexico. This added a layer of pressure on prices. Weekly prices plummeted across the Lower 48. Tenn Zone 5 200L fell $1.550 to average $1.295, while Dominion Energy Cove Point dropped $1.035 to $1.395, and Algonquin Citygate sank $2.675 to $1.600. Additionally, coronavirus outbreaks dampened economic activity and energy demand over swaths of the United States, particularly in the Upper Midwest. Several states in the region – Wisconsin, Iowa and the Dakotas – were all grappling with surges and record case levels.While natural gas prices are poised to recover when colder weather returns, the pandemic threatens to intensify as people are indoors more in the winter, hastening virus spread. “The situation is likely to get worse,”
Natural Gas Rigs Slide as Oil Gains Push US Count to 300 – The U.S. natural gas rig count fell one unit to 71 for the week ending Friday (Nov. 6), while more gains in the oil patch lifted the overall U.S. rig count four units to an even 300, according to the latest data published by Baker Hughes Co. (BKR). The BKR numbers, which are based on data provided in part by Enverus Drillinginfo, showed a five-rig increase in oil-directed drilling in the United States for the week, offsetting the net decline of one natural gas-directed rig. The overall U.S. count ended the week 517 units behind the 817 rigs running at this time last year.Still, after plummeting in the economic aftermath of efforts to contain the Covid-19 pandemic, total U.S. rigs have now increased for eight straight weeks.Land drilling increased by four domestically, while one rig was deployed to inland waters. Gulf of Mexico rigs fell one unit to end at 12. Horizontal units increased by five, while vertical units increased by two, offsetting a decline of three directional rigs for the week.The Canadian rig count finished unchanged on the week at 86, with a three-rig increase in gas-directed drilling offsetting a three-rig decline in oil-directed units. The Canadian count finished 54 units behind the 140 rigs active in the year-ago period. The combined North American rig count ended the week at 386, off from 957 a year ago.Among major plays, the Permian Basin led with an increase of five units on the week, upping its total to 147. That’s still down sharply from 412 rigs active there a year ago.Elsewhere among plays, the Cana Woodford and Eagle Ford Shale each added two rigs, while the Marcellus and Utica shales each declined by one. Broken down by state, Texas added six rigs on the week to finish with 139, while New Mexico added three rigs, ending the period with an even 50. Ohio, Oklahoma and West Virginia each dropped one rig from their respective totals.
CenterPoint Energy files for recovery after completion of $240M natural gas pipeline modernization effort -Southern Indiana Gas and Electric Co., a subsidiary of CenterPoint Energy, filed a request last week to recover investments made in its southwestern natural gas service territory following the completion of a seven-year, $240 million modernization effort for its pipelines. The company’s pursuit of the plan began in 2013 and included upgrades to portions of a 3,200-mile network of distribution mains and transmission pipelines serving nine counties in southwestern Indiana. Bare steel and cast iron were swapped for plastic, inspections were undertaken, and upgrades were pursued as necessary. The results have already been felt, too: SIGECO reported a 36 percent reduction in methane emissions since 2013. “These infrastructure investments are vital to meeting federal mandates and ensuring the safe and reliable delivery of natural gas to our customers,” Richard Leger, CenterPoint’s vice president of natural gas distribution for Indiana and Ohio, said. “While our natural gas customers will experience a base rate increase to their bills, it will be the first time in nearly 14 years we have pursued such recovery.” For the average residential customer, this increase would reach around $15 per month.
Trump claims of Wisconsin job losses over fracking are implausible — It was a big claim and a bigger number.In an essay written for the Journal Sentinel last week, President Trump wrote:”Biden has repeatedly pledged to ban fracking throughout his campaign. … This radical energy policy means the elimination of 300,000 Wisconsin jobs, according to a report by the Global Energy Institute at the U.S. Chamber of Commerce.”300,000 jobs.Is that plausible?Not really. First, it’s false to say that Joe Biden “has repeatedly pledged to ban fracking” – short for hydraulic fracturing, a method of extracting oil and natural gas from rock formations.The former vice president has said he would only ban new gas and oil permits on federal lands. Existing fracking would be unscathed, under his plan. Second, even if Biden did cave to pressure from progressives in the Democratic Party who want an outright ban – Bernie Sanders, say – it’s simply not conceivable that existing fracking would go away all at once or at all.But this is the fear of some conservatives and the dream of some liberals so let’s take a closer look at the evidence for Trump’s claim.The chamber’s dire study, published in late 2019, found that Wisconsin would lose 300,000 jobs over a five-year period and $8.3 billion in state and local tax revenue.Wisconsin has some jobs directly tied to fracking because the state produces sand used in the process, but the vast majority of jobs at risk are in energy-intensive industries such as manufacturing and agriculture, the study found.But two economists I spoke with have big questions about the study’s methodology and findings.Tim Bartik, a senior economist at the Upjohn Institute in Kalamazoo, Michigan, says the study assumes there would be no adjustments in the economy if fracking was banned, which isn’t the case.”It vastly overstates the impact,” he wrote in an email. “All the Wisconsin impact is done by assuming that the fracking ban just sucks money out of the U.S. economy and sends it to Mars, and there are no macroeconomic adjustments due to this other than lower demand. These are not reasonable assumptions to make.”So, the 300,000 job loss impact is overstated by roughly … 300,000. Well, to be conservative, maybe by 299,000.”
Louisiana approves property tax measure tied to oil, gas production – Louisiana voters approved a change to the state constitution to allow the presence or production of oil or gas to be taken into account when assessing the fair market value of an oil or gas well for ad valorem property taxes. Stay up to date with the latest commodity content. Sign up for our free daily Commodities Bulletin. Sign Up Constitutional Amendment 2 received 58% of votes with 97% of precincts reporting, according to preliminary results from the Louisiana Secretary of State. Supporters said the measure would ensure that when wells are more valuable, owners will pay more taxes, but when they are less valuable, they will pay lower taxes, the Louisiana Oil and Gas Association said. It was also supported by the Louisiana Tax Committee, Louisiana Tax Assessor’s Association, and the Louisiana Mid-Continent Oil and Gas Association.
Shell mulls closure of some oil refineries if it can’t sell them; Convent on the list – The Shell oil refinery in Convent is up for sale but could face closure if the company doesn’t find a buyer as it consolidates its refinery portfolio from 14 sites to only six by 2025. Shell warned local officials several months ago that it was testing the market for the potential sale of the Convent site, located between Baton Rouge and New Orleans, and its associated facilities. “We’ve had success (with asset sales) in the past in difficult markets. If it’s not possible, we’ll consider closing and shutting down,” Chief Financial Officer Jessica Uhl said during a conference call with analysts and investors. The company does expect to keep “refinery capacity in the key markets tied to our chemical business,” she said. Shell plans to consolidate its assets into six energy and chemical parks, which includes the Norco site near New Orleans. Other sites are in Deer Park, Texas; The Netherlands; Singapore; Germany; and Canada. The new petrochemical parks are expected to be located near existing complexes, such as Shell’s Geismar site in Ascension Parish. The goal is for the refineries to be more integrated with the chemical complexes and produce more biofuels, hydrogen and synthetic fuels, executives told investors. Other refineries under review for potential sale or closure include Puget Sound, Washington, and Mobile, Alabama, along with ones in Canada and Denmark. The Convent refinery sits on 4,400 acres that straddles Ascension and St. James parishes and can process 240,000 barrels of crude oil per day. It employs 700 Shell workers and 400 contract workers. The processing equipment connected to the plant is located in St. James Parish and occupies about 900 acres. Shell’s subsidiary, Equilon Enterprises LLC, has $1.18 billion in total taxable value in St. James Parish and paid $18.8 million for the refinery in 2019, tax assessor records show. The refinery produces various grades of gasoline; jet fuel; diesel fuel and heating oil; propane and butane for residential and industrial use; and oil for tankers, power generation and vehicles. The facility has access to multiple major crude oil and product pipelines, which ship gasoline, diesel, kerosene and jet fuel. The site’s location on the Mississippi River allows shipping and receiving petroleum products aboard ocean-going vessels. The refinery uses two docks along 6,000 feet of Mississippi River access.
Shell decides to shutter the Convent oil refinery; hundreds of jobs lost – After failing to find a buyer for its refinery in Convent, Shell is shutting down the plant, which employs 700 company workers and 400 contract workers.The shutdown process is expected to begin in mid-November and run through the end of the year as the company consolidates its international oil refinery portfolio from 14 sites to only six by 2025. To free up some jobs for those displaced by the Convent shutdown, Shell is offering a voluntary severance program to some workers at its Norco refinery near New Orleans. Shell also operates a chemical plant in Geismar where some workers could land. Others without jobs will get help finding employment with other companies, Shell and the governor said Thursday. Shell will continue trying to sell the idled refinery, which sits midway between Baton Rouge and New Orleans, straddling Ascension and St. James parishes, and can process 240,000 barrels of crude oil per day. “Despite efforts to sell the asset, a viable buyer was never identified,” said Curtis Smith, spokesperson for Shell. “After looking at all aspects of our business, including financial performance, we made the difficult decision to shut down the site.” Shell is consolidating its assets into six energy and chemical parks internationally. The Norco refinery in conjunction with Shell’s chemical complex in Geismar in Ascension Parish are one of the six sites. Shell’s Convent and Norco facilities are unionized but its Geismar facility in Ascension Parish is not. A union representative could not be reached. The other sites are in Deer Park, Texas; The Netherlands; Singapore; Germany; and Canada. Shell said the goal is for the refineries to be more integrated with the chemical complexes to produce more biofuels, hydrogen and synthetic fuels as Shell positions itself for a transition from fossil fuels to a low-carbon future because customers are asking for lower carbon products.
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