Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 17 October 2020. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening.
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Smallest early October natural gas inventory build in 13 years; largest distillates inventory draw in 17 years, etal
Oil prices finished fractionally higher this week, as bullish economic reports and the success of OPEC’s supply cuts were tempered by surging coronavirus infections worldwide…after rising more than 9% to $40.60 a barrel last week as Hurricane Delta shut down a near record 92% of US Gulf production, the contract price of US light sweet crude for November delivery opened the week lower and slid to a 4% loss on Monday as production resumed at Libya’s largest oilfield and the strike affecting Norwegian production came to an end, and ended the day $1.17 lower at $39.43 a barrel as U.S. producers began restoring Gulf output after Hurricane Delta...but oil prices partly recovered from that drop to rise 77 cents to $40.20 a barrel on Tuesday, supported by robust economic data and increased demand from China that offset returning supply from elsewhere…the price rally continued on Wednesday as the monthly OPEC report showed that OPEC and its allies were complying with a pact to cut oil supply in September and then held above $41 after the API reported large withdrawals of crude and oil products from inventories, with the benchmark US crude settling with a gain of 84 cents at $41.04 a barrel…oil then traded 2% lower early Thursday as new lockdowns following a surge in COVID-19 infections in Europe dimmed the outlook for fuel demand, but mostly recovered from that dip to end just 8 cents lower at $40.96 a barrel, buoyed by EIA data showing a bigger-than-expected weekly decline in domestic crude inventories and the largest draw on distillates supplies in 17 years…prices slipped again on Friday on concerns that a spike in Covid-19 cases in Europe and the US was curtailing demand in the world’s biggest fuel consuming regions and again finished down 8 cents at $40.88 a barrel, but still finished 0.7% higher for the week, partly due to assurances from OPEC+ that it remains committed to production cuts…
Natural gas prices also finished slightly higher this week, after the EIA reported the smallest early October addition to gas inventories since 2007…after rising 12.4% to $2.741 per mmBTU last week as natural gas exports rose while Hurricane Delta shut in 62% of Gulf production, the contract price of natural gas for November delivery opened nearly 6% higher on Monday and surged to $2.955 per mmBTU, as gas flowing to LNG export plants jumped while natural gas output was falling to a 27 month low, before pulling back and settling with a gain of 14.0 cents at $2.881 per mmBTU….but natural gas prices headed lower Tuesday as the morning weather models shifted to warmer, sending the November contract down 2.6 cents to $2.855 per mmBTU….then prices opened lower and tumbed to a loss of 21.9 cents, or nearly 8%, on Wednesday as gas production increased while a major data provider lowered the forecast for demand, but then turned around and rose 13.9 cents to $2.775 per mmBTU on Thursday after the EIA reported a smaller addition to storage than traders had expected and the weather forecast flipped back to colder…prices then sputtered on Friday as US and European weather models conflicted, and traders tried to tell whether LNG and weather demand would be enough to avoid a toppling of storage inventories by the end of October, with the November contract closing down two-tenths of a cent at $2.773 per mmBTU, but still 1.2% higher on the week..
The natural gas storage report from the EIA for the week ending October 9th indicated that the quantity of natural gas held in underground storage in the US increased by 46 billion cubic feet to 3,877 billion cubic feet by the end of the week, which left our gas supplies 388 billion cubic feet, or 11.1% greater than the 3,489 billion cubic feet that were in storage on October 9th of last year, and 353 billion cubic feet, or 10.0% above the five-year average of 3,524 billion cubic feet of natural gas that have been in storage as of the 9th of October in recent years….the 46 billion cubic feet that were added to US natural gas storage this week was less than the forecast for a 50 billion cubic foot increase from an S&P Global Platts’ survey of analysts, and it was far below the average of 87 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 less than half of the 102 billion cubic feet that was added to natural gas storage during the corresponding week of 2019…
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 9th showed that due to a decrease in our oil imports and a decrease in our oil production, we needed to withdraw oil from our stored commercial supplies for the 10th time in the past twleve weeks and for the 15th time in thirty-nine weeks…our imports of crude oil fell by an average of 447,000 barrels per day to an average of 5,286,000 barrels per day, after rising by an average of 610,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 524,000 barrels per day to an average of 2,135,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,151,000 barrels of per day during the week ending October 9th, 77,000 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 500,000 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 13,651,000 barrels per day during this reporting week…
US oil refineries reported they were processing 13,577,000 barrels of crude per day during the week ending October 9th, 277,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net total of 711,000 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 785,000 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 (-785,000) 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….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 rose to an average of 5,327,000 barrels per day last week, which was still 15.4% less than the 6,297,000 barrel per day average that we were importing over the same four-week period last year….the 711,000 barrel per day net withdrawal from our total crude inventories included 545,000 barrels per day that were withdrawn from our commercially available stocks of crude oil and 166,000 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 500,000 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 500,000 barrels per day to 10,000,000 barrels per day, while a 9,000 barrels per day increase to 450,000 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 October 11th 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 75.1% of their capacity while using 13,577,000 barrels of crude per day during the week ending October 9th, down from 77.1% of capacity during the prior week, and excluding the 2005 and 2008 hurricane-related refinery interruptions, one of the lowest refinery utilization rates of the last thirty years…hence, the 13,577,000 barrels per day of oil that were refined this week were 12.0% fewer barrels than the 15,436,000 barrels of crude that were being processed daily during the week ending October 11th of last year, when US refineries were operating at what was then a two year low of 83.1% of capacity…
With the decrease in the amount of oil being refined, gasoline output from our refineries was also lower, decreasing by 282,000 barrels per day to 9,240,000 barrels per day during the week ending October 9th, after our refineries’ gasoline output had increased by 630,000 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 7.6% less than the 9,998,000 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) decreased by 263,000 barrels per day to a three year low of 4,269,000 barrels per day, after our distillates output had increased by 174,000 barrels per day from the prior three year low over the prior week…after this week’s decrease, our distillates’ production was 8.9% less than the 4,688,000 barrels of distillates per day that were being produced during the week ending October 11th, 2019, which was the distillates’ production low for that year….
Along with the decrease in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 12th time in 15 weeks and for the 27th time in 37 weeks, falling by 1,626,000 barrels to 226,747,000 barrels during the week ending October 9th, after our gasoline supplies had decreased by 1,435,000 barrels over the prior week…our gasoline supplies decreased this week even though the amount of gasoline supplied to US markets decreased by 320,000 barrels per day to 8,576,000 barrels per day, because our imports of gasoline fell by 451,000 barrels per day to 398,000 barrels per day while our exports of gasoline fell by 178,000 barrels per day to 725,000 barrels per day…after the gasoline inventory drawdowns of recent weeks, our gasoline supplies were 1.0% lower than last October 11th’s gasoline inventories of 226,201,000 barrels, and about 1% below the five year average of our gasoline supplies for this time of the year…
Meanwhile, with our distillates production at another three year low, our supplies of distillate fuels decreased for the 10th time in 28 weeks and for the 30th time in 52 weeks, falling by a 17 year high of 7,245,000 barrels to 164,551,000 barrels during the week ending October 9th, after our distillates supplies had decreased by 962,000 barrels during the prior week….our distillates supplies fell by that much this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 307,000 barrels per day to 4,175,000 barrels per day, and because our exports of distillates rose by 258,000 barrels per day to 1,289,000 barrels per day, and because our imports of distillates fell by 70,000 barrels per day to 160,000 barrels per day….but even after this week’s big inventory decrease, our distillate supplies at the end of the week were still 33.2% above the 123,501,000 barrels of distillates that we had in storage on October 11th, 2019, and about 19% above the five year average of distillates stocks for this time of the year…
Finally, with the big decreases in both 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 11th time in the past eightteen weeks and for the 18th time in the past year, decreasing by 3,838,000 barrels, from 492,927,000 barrels on October 2nd to 489,109,000 barrels on October 9th…but even after that decrease, our commercial crude oil inventories were around 11% above the five-year average of crude oil supplies for this time of year, and about 48% above the prior 5 year (2010 – 2014) average of our crude oil stocks for the second 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 have generally been rising over the past two years, except for 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 9th were 12.5% above the 434,850,000 barrels of oil we had in commercial storage on October 11th of 2019, 17.5% more than the 416,441,000 barrels of oil that we had in storage on October 12th of 2018, and 7.1% above the 456,485,000 barrels of oil we had in commercial storage on October 13th of 2017…
OPEC’s Monthly Oil Market Report
Tuesday of this past week saw the release of OPEC’s October Oil Market Report, which covers OPEC & global oil data for September, and hence it gives us a picture of the global oil supply & demand situation in the second month of the extended agreement between OPEC, the Russians, and other oil producers to cut production by 7.7 million barrels a day cut, reduced from the 9.7 million barrels a day cuts they had imposed on themselves during May, June and July… understand that estimating oil demand while most countries are still trying to recover from a Covid-19 induced recession is pretty speculative, and hence the demand estimates we’ll be reporting this month should again be considered as having a much larger margin of error than we’d expect from this report during stable and hence more predictable periods..
The first table from this monthly report that we’ll review is from the page numbered 50 of this month’s report (pdf page 60), and it shows oil production in thousands of barrels per day for each of the current OPEC members over the recent years, quarters and months, as the column headings indicate…for all their official production measurements, OPEC uses an average of estimates from six “secondary sources”, namely the International Energy Agency (IEA), the oil-pricing agencies Platts and Argus, the U.S. Energy Information Administration (EIA), the oil consultancy Cambridge Energy Research Associates (CERA) and the industry newsletter Petroleum Intelligence Weekly, as a means of impartially adjudicating whether their output quotas and production cuts are being met, to thus avert any potential disputes that could arise if each member reported their own figures…
As we can see from the above table of their oil production data, OPEC’s oil output was down by 47,000 barrels per day to 24,106,000 barrels per day during September, from their revised August production total of 24,153,000 barrels per day…however that August output figure was originally reported as 24,045,000 barrels per day, which means that OPEC’s August production was revised 108,000 barrels per day higher with this report, and hence September’s production was, in effect, a rounded 61,000 barrel per day increase from the previously reported OPEC production figure (for your reference, here is the table of the official August OPEC output figures as reported a month ago, before this month’s revisions)…
From the above table, we can also see that the production cut of 239,000 barrels per day by the Emirates was responsible for OPEC’s September output decrease, as most other OPEC members actually posted small, but inconsequential production increases….recall that the original oil producer’s agreement was to cut production by 9.7 million barrels per day from an October 2018 baseline for just two months, during May and June, but that agreement was extended to include July at a meeting between OPEC and other producers on June 6th….then, in a subsequent meeting in July, OPEC and the other oil producers agreed to ease their deep supply cuts by 2 million barrels per day in August and subsequent months, which is thus the agreement that covers this month’s report…however, since Iraq hadn’t been in compliance with the original cuts during May, June and July, and since the Emirates had overproduced in August, the Saudis and other producers pressured them into committing to make “compensation cuts” over August and September to make up for their overproduction in previous months, which is what accounts for the Emirates’ deeper cut we see above….
Since there does not seem to be a table or listing available of how much each OPEC member was expected to produce under the eased production cuts of August and subsequent months, we’re including below the table which shows the October 2018 reference production for each of the OPEC members (as well as other producers party to the mid-April agreement), as well as the production level each of those producers was expected to cut their output to during May, June, and July….
The above table shows the oil production baseline in thousands of barrel per day from which each of the oil producers was to cut from in the first column, a figure which is based on each of the producer’s October 2018 output, ie., a date before the past year’s and this year’s output cuts took effect; the second column shows how much each participant had originally committed to cut in thousands of barrel per day, which was 23% of the October 2018 baseline for all participants except for Mexico, while the last column shows the production level each participant had agreed to after that cut…the producer’s agreement for August, September and subsequent months amends the above such that each member would be allowed to increase their production cut level shown above (ie, the “voluntary adjustment” shown above) by 20%…for example, Algeria’s “cut” was expected to be 241,000 barrels per day from May thru July, which would reduce their oil production to 816,000 barrels per day over that period…under the agreement for August and the following months, Algeria would reduce their “cut” by 20%, or to 193,000 barrels per day, allowing them to produce 864,000 barrels per day during September…offhand, by comparing this table’s allocation +20% to the initial OPEC production table above, it does not appear that any of the OPEC members has exceeded their production quota for September, at least not by any consequential amount…note that sanctioned OPEC members Iran and Venezuela and war-torn Libya are exempt from these cuts…
The next graphic from this month’s report that we’ll include shows us both OPEC and world oil production monthly on the same graph, over the period from October 2018 to September 2020, and it comes from page 51 (pdf page 61) of the October OPEC Monthly Oil Market Report….on this graph, the cerulean blue bars represent OPEC’s monthly oil production in millions of barrels per day as shown on the left scale, while the purple graph represents global oil production in millions of barrels per day, with the metrics for global output shown on the right scale….
After the reported 47,000 barrel per day decrease in OPEC’s production from what they produced a month earlier, OPEC’s preliminary estimate indicates that total global oil production decreased by a rounded 0.06 million barrels per day to average 90.71 million barrels per day in September, a reported decrease which apparently came after August’s total global output figure was revised up by 890,000 barrels per day from the 89.88 million barrels per day of global oil output that was reported a month ago, as non-OPEC oil production fell by a rounded 10,000 barrels per day in September after that revision, with oil production decreases by Brazil and Kazakhstan more than offseting increases by other non-OPEC producers in September…after that decrease in September’s global output, the 90.71 million barrels of oil per day that were produced globally in September were 7.83 million barrels per day, or 7.9% less than the revised 98.54 million barrels of oil per day that were being produced globally in September a year ago, the 9th month of OPECs first round of production cuts (see the October 2019 OPEC report (online pdf) for the originally reported September 2019 details)…with this month’s decrease in OPEC’s output, their September oil production of 24,106,000 barrels per day was at 26.6% of what was produced globally during the month, unchanged from August but up from their revised 26.3% share in July….OPEC’s September 2019 production, which included 547,000 barrels per day from former OPEC member Ecuador, was reported at 28,491,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 3,838,000, or 13.5% fewer barrels per day of oil in September than what they produced a year ago, when they accounted for 29.3% of global output…
After the decrease in OPEC’s and global oil output that we’ve seen in this report, there was a shortfall in the amount of oil being produced globally during the month, as this next table from the OPEC report will show us…
the above table came from page 25 of the September OPEC Monthly Oil Market Report (pdf page 35), and it shows regional and total oil demand estimates in millions of barrels per day for 2019 in the first column, and OPEC’s estimate of oil demand by region and globally quarterly over 2020 over the rest of the table…on the “Total world” line in the fourth column, we’ve circled in blue the figure that’s relevant for September, which is their estimate of global oil demand during the third quarter of 2020…
OPEC is estimating that during the 3rd quarter of this year, all oil consuming regions of the globe have used an average of 90.99 million barrels of oil per day, which is a 460,000 barrels per day downward revision from the 91.45 million barrels of oil per day they were estimating for the 3rd quarter a month ago (note revisions are encircled in green), reflecting quite a bit of coronavirus related demand destruction compared to 2019, when summertime global demand exceeded 100 million barrels per day….but as OPEC showed us in the oil supply section of this report and the summary supply graph above, OPEC and the rest of the world’s oil producers were producing just 90.71 million barrels million barrels per day during September, which would imply that there was a shortage of around 280,000 barrels per day in global oil production in September when compared to the demand estimated for the month, a shortfall that is really inconsequential in the larger scheme of global supply…
In addition to figuring the September oil shortage that’s evident in this report, the upward revision of 890,000 barrels per day to August’s global oil output that’s implied in this report, partly offset by the 460,000 barrels per day downward revision to 3rd quarter demand that we’ve circled in green, means that the 1,570,000 barrels per day global oil output shortage we had previously figured for August would now be revised to a shortage of 1,140,000 barrels per day…. similarly, the 2,890,000 barrels per day global oil output shortage we had previously figured for July, after adjusting for the downward revision in demand, would need to be revised to a global oil shortage of 2,430,000 barrels per day….
Note that in green we’ve also circled an upward revision of 920,000 barrels per day to second quarter demand, a quarter when there was a large excess of oil production due to coronavirus related lockdowns…based on that rather large upward revision to demand, our previous estimate that there was a surplus of 5,810,000 barrels per day in June would now be revised down to a 4,890,000 barrels per day surplus, the oil surplus of 8,590,000 barrels per day that we had previously figured for May would have to be revised to a surplus of 7,670,000 barrels per day, and the 17,340,000 barrels per day that we had previously figured for April would have to be revised to a surplus of 16,420,000 barrels per day…
However, there was also an downward revision of 10,000 barrels per day to first quarter demand, which we have also encircled in green on the table above…that means that the record global oil surplus of 17,778,000 barrels per day we had previously figured for March would have to be revised downward to an even higher record global oil surplus of 17,788,000 barrels per day, that the 1,890,000 barrel per day global oil production surplus we had figured for February would now be a 1,900,000 barrel per day global oil output surplus, and that the 920,000 barrel per day global oil output surplus we last had for January would now be revised to a 930,000 barrel per day oil output surplus.. so despite the shortage of oil that has developed in the 3rd quarter, it’s obvious the world’s oil producers had produced a lot of oil earlier this year that no one wanted…
Lastly, notice that in the first column of figures we’ve circled in orange an upward revision of 70,000 barrels per day in global demand for 2019…the last time OPEC revised their demand figures for 2019 was in July, and at that time we simply revised our aggregate oil shortage for 2019 from a total of 254,890,000 barrels to a revised total of 262,190,000 barrels for the entirely of the year…thus an upward revision of 70,000 barrels per day to 2019’s oil demand would increase 2019’s oil shortage by 25,550,000 barrels to 287,740,000 barrels, resulting in a global oil shortage that was the equivalent of nearly two days and 21 hours of global oil production at the December 2019 production rate…
This Week’s Rig Count
The US rig count rose for the 5th week in a row during the week ending October 16th, but for just the 7th time in the past 32 weeks, and hence it is still down by 64.4% over that thirty-two week period….Baker Hughes reported that the total count of rotary rigs running in the US rose by 13 to 282 rigs this past week, which was still down by 569 rigs from the 851 rigs that were in use as of the October 18th report of 2019, and was also 122 fewer rigs than the all time low prior to this year, and 1,660 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 12 rigs to 205 oil rigs this week, after increasing by 4 oil rigs the prior week, still leaving us with 508 fewer oil rigs than were running a year ago, and less than a seventh 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 increased by one to 74 natural gas rigs, which was still down by 63 natural gas rigs from the 137 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 only one such “miscellaneous” rig deployed…
The Gulf of Mexico rig count remained unchanged at 14 rigs this week, with 12 of those rigs drilling for oil in Louisiana’s offshore waters and two drilling for oil offshore from Texas…that was 7 fewer Gulf rigs than the 21 rigs drilling in the Gulf a year ago, when all 21 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 8 from the national offshore rig count of 24 a year ago….also note that in addition to those rigs offshore, a rig continues to drill through an inland body of water in St Mary County, Louisiana this week, while a year ago there were two rigs drilling on southern Louisiana inland waters..
The count of active horizontal drilling rigs was up by 7 to 240 horizontal rigs this week, which was still 505 fewer horizontal rigs than the 750 horizontal rigs that were in use in the US on October 18th 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 up by six to 21 vertical rigs this week, but those were down by 30 from the 51 vertical rigs that were operating during the same week of last year….on the other hand, the directional rig count was unchanged at 21 directional rigs this week, and those were down by 34 from the 55 directional rigs that were in use on October 18th 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 October 16th, the second column shows the change in the number of working rigs between last week’s count (October 9th) and this week’s (October 16th) count, the third column shows last week’s October 9th 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 18th of October, 2019…
There was somewhat more activity this week than recently, but because 6 of this week’s rig additions were vertical, they typically wouldn’t be included in the second table above…by checking the rig counts in the Texas part of Permian basin, we find that one rig was pulled out of Texas Oil District 8, which roughly aligns with the Permian Delaware, while 1 rig was pulled out of Texas Oil District 8A, which corresponds to the northern Permian Midland, thus leaving the rig count in the Permian basin unchanged…elsewhere in Texas, two rigs were added in Texas Oil District 2, and two more rigs were added in Texas Oil District 1, which together account for the 3 oil rigs added in the Eagle Ford, and one of the vertical rig additions not targeting the Eagle Ford…also in Texas, three rigs were added in Texas Oil District 6, which abuts the Louisiana border, and thus accounts for the Haynesville rig addition, while two rigs were concurrently pulled out of the Haynesville shale in Louisiana, thus accounting for the rig decrease in that state…elsewhere, the oil rig pulled out of the Denver-Julesburg Niobrara chalk came out of Colorado, the rig added in the Williston Basin was in North Dakota, and both the rig added in the Cana Woodford and the rig pulled out of the Granite Wash were oil rigs in Oklahoma, while the rig added in West Virginia Marcellus was targeting natural gas…the natural gas rig count was only up by one nationally because a natural gas rig was concurrently pulled out of a basin not tracked separately by Baker Hughes, which thus doesn’t show up above…
Ohio Power Plant Would Be First in US to Feature Gas-Hydrogen Blend – A blend of hydrogen and natural gas will fuel the 485-MW Long Ridge Energy Terminal combined cycle power plant beginning in November 2021, the first in the U.S., also putting the unit on a path to burn 100% hydrogen in the next decade, said plant owner New Fortress Energy on Oct. 13. The $588-million project is a collaboration with GE Power that will use the firm’s H-class gas turbine, which can burn 15% to 20% hydrogen.
Long Ridge Energy Terminal to transition to 100% hydrogen-fired plant – Long Ridge Energy Terminal will transition its 485-MW combined-cycle power plant in Ohio to run on a blend of natural gas and hydrogen by November 2021, and to burn 100% green hydrogen by 2030, the company announced Oct. 13. The project will be a partnership between Fortress Transportation and Infrastructure, which is the parent company of Long Ridge, as well as New Fortress Energy and GE Power, whose turbines are installed at the plant. The plant, based in Hannibal, Ohio, amidst he Marcellus and Utica shale formations, will be the first purpose-built hydrogen-burning power plant in the US and the first worldwide to blend hydrogen in a GE H-class gas turbine, according to the announcement. The turbine can burn between 15%-20% hydrogen by volume in the gas stream initially, with the capability to transition to 100% hydrogen. By November 2021, Long Ridge will begin blending hydrogen in the gas stream, using hydrogen byproduct from a nearby industrial facility. Longer term, a New Fortress Energy division, called Zero, will focus on investing in and deploying emerging hydrogen production technologies to produce low-cost, carbon-free hydrogen, according to the announcement. The site has access to the Ohio River for water, as well as below ground salt formations for large-scale hydrogen storage. Additionally, with access to large-scale underground storage, the plant will be capable of supporting a balanced and diverse power generation portfolio in the future; from energy storage capable of accommodating seasonal fluctuations from renewable energy, to cost effective, dispatchable intermediate and baseload power, the announcement said.
Driller Dodges Sanctions Bid But Gets Discovery Warning – Law360 – An Ohio federal judge warned Gulfport Energy Corp. on Wednesday to speed up its discovery responses in a case in which mineral owners say the company and others drilled where they didn’t belong, but stopped short of sanctioning it.
Researchers find elevated radiation near U.S. fracking sites (Reuters) – Radiation levels downwind of U.S. hydraulic fracturing drilling sites tend to be significantly higher than background levels, posing a potential health risk to nearby residents, according to a study by Harvard researchers released on Tuesday. The study, published in the journal Nature, adds to controversy over the drilling method known as fracking, which has helped the United States become the world’s biggest oil and gas producer over the past decade but which environmentalists say threatens water and air. President Donald Trump supports fracking because of its economic benefits, and his Democratic rival Joe Biden has promised to continue to allow it if elected even though he aims to impose an ambitious plan to fight climate change. Areas within 20 kilometers (12 miles) downwind of 100 fracking wells tend to have radiation levels that are about 7% above normal background levels, according to the study, which examined thousands of the U.S. Environmental Protection Agency’s radiation monitor readings nationwide from 2011 to 2017. The study showed readings can go much higher in areas closer to drill sites, or in areas with higher concentrations of drill sites. “The increases are not extremely dangerous, but could raise certain health risks to people living nearby,” said the study’s lead author, Petros Koutrakis. Radioactive particles can be inhaled and increase the risk of lung cancer. Koutrakis said the source of the radiation is likely naturally-occurring radioactive material brought up to the surface in drilling waste fluids during fracking, a process that pumps water underground to break up shale formations. The study found the biggest increases in radiation levels near drill sites in states like Pennsylvania and Ohio that have higher concentrations of naturally occurring radioactive material beneath the surface, and lower readings in places like Texas and New Mexico that have less.
Airborne radioactivity increases downwind of fracking, study finds – The radioactivity of airborne particles increases significantly downwind of fracking sites in the US, a study has found.The Harvard scientists said this could damage the health of people living in nearby communities and that further research was needed to understand how to stop the release of the radioactive elements from under the ground.The radioactivity rose by 40% compared with the background level in the most affected sites. The increase will be higher for people living closer than 20km to the fracking sites, which was the closest distance that could be assessed with the available data.The scientists used data collected from 157 radiation-monitoring stations across the US between 2001 and 2017. The stations were built during the cold war when nuclear war was a threat. They compared data with the position and production records of 120,000 fracking wells.”Our results suggest that an increase in particle radioactivity due to the extensive [fracking development] may cause adverse health outcomes in nearby communities,” the team concluded. Petros Koutrakis at the Harvard TH Chan School of Public Health in Boston, who led the study, said: “If you asked me to go and live downwind [of fracking sites], I would not go. People should not go crazy, but I think it’s a significant risk that needs to be addressed.”Previous work has shown that chemicals released during fracking could pose a health risk to children and the process has contaminated groundwater in some places. Fracking is also an issue in the forthcoming presidential election, particularly in swing states such as Pennsylvania. Donald Trump has falsely claimed Joe Biden will ban fracking but the Democratic presidential candidate is largely supportive of fracking and only backs a ban on federal lands and offshore. The new research, published in the journal Nature Communications, examined the increases in the radioactivity of airborne particles when there were operational fracking wells within 20km upwind of a location. With 100 wells upwind the average rise in radioactivity was 7%, but some places had nearly 600 wells upwind.
Fracking Is Elevating Levels of Radioactivity Downwind – The new research, published in Nature Communications on Tuesday, shows that radiation levels up to 12 miles (20 kilometers) downwind of drilling sites can be dangerously high. The Harvard scientists obtained data from 157 Cold War-era federal radiation monitoring stations across the U.S. between 2001 and 2017. They then compared those numbers with data on the position and production records of 120,000 fracking wells to examine the increase in the radioactivity levels of airborne particles in locations that had wells upwind.The researchers found that sites that had 100 fracking wells within 12 mileupwind, tended to have radiation levels about 7% above normal background levels. That alone “may cause adverse health outcomes in nearby communities,” the study says, but as the researchers note, some places in the Northeast are 12 miles downwind of over 500 fracking sites. The highest radioactivity levels they observed were near the Marcellus and Utica shale fields in Pennsylvania and Ohio, where air particle radioactivity was 40% higher than normal background levels.This level of radioactivity near fracking operations was higher than levels measured in areas near conventional drilling operations. Texas and New Mexico, for instance, registered lower readings than places near the fracking operations near the Northeast shale fields. That’s because conventional oil and gas drilling doesn’t disturb underground rocks very much, rocks that contain a uranium isotope that’s the source of their radioactivity. Fracking, on the other hand, involves blasting through shale and other rock formations, which releases the uranium. That uranium then breaks into particles, which then become attached to particles in the air and get carried downwind.The study’s lead author, Petros Koutrakis, told Reuters that the levels of radioactivity his team observed “are not extremely dangerous, but could raise certain health risks to people living nearby.” The authors note that short-term exposure to particle radioactivity has been linked to adverse health outcomes like a decrease in lung function, higher blood pressure, and increasedinflammation that can cause cardiovascular issues. The study adds to previous research which shows that fracking can turn nearby water radioactive, leak carcinogenic pollutants into air and water and can evenmess with testosterone levels. Fracking is also a massive source of planet-warming greenhouse gas emissions.
What’s The Future Of The Petrochemical Industry In The U.S.? (NPR podcast & transcript) For a decade, increasing American gas production has fueled a boom in petrochemical plants. There are big plans for more of them in Appalachia, but some wonder if the pandemic will crush those plans. Reid Frazier of the public radio program “The Allegheny Front” reports.
State AG Shapiro: Grand jury report reveals Pa.’s systemic failure to regulate shale gas industry – Pittsburgh Post-Gazette -A statewide grand jury investigating the operations and regulation of the shale gas drilling industry has issued a scathing report detailing the systemic failure of the state environment and health departments in regulating the industry and protecting public health.Pennsylvania Attorney General Josh Shapiro, who released the 235-pagereport on the grand jury’s two-year investigation Thursday morning, said it uncovers the “initial failure” more than a dozen years ago of the state Department of Environmental Protection to respond to and regulate the shale gas industry and the impacts of hydraulic fracturing, or “fracking.”And, while the Wolf administration has made improvements at the agency, the grand jury said, there remains room for improvement.”This report is about preventing the failures of our past from continuing into our future,” Mr. Shapiro said. “It’s about the big fights we must take on to protect Pennsylvanians – to ensure that their voices are not drowned out by those with bigger wallets and better connections. There remains a profound gap between our constitutional mandate for clean air and pure water, and the realities facing Pennsylvanians who live in the shadow of fracking giants and their investors.” In announcing the report’s findings at a Harrisburg news conference, Mr. Shapiro held up containers of brown water and clogged water filters while detailing testimony of residents who said the shale gas drilling industry has caused their well water to turn cloudy and become “black sludge,” and caused “problems with breathing whenever we were in the shower.” He said Pennsylvania farmers testified that their horses, pets and other livestock would sometimes become “ill, infertile and die” after drinking the same water as the farm families. According to Mr. Shapiro, the grand jury report noted that other residents testified that their air became so badly polluted from the drilling pad emissions and stray methane gas that they could not leave windows open or let their children play outside. He said parents testified that their children would wake at night with severe nosebleeds. He said the grand jury took 287 hours of testimony from rural residents of the shale gas fields and government officials, and that “there is still more to come from the investigation over the coming weeks and months.” The grand jury report makes eight recommendations:
- Expand the set back distance between homes and gas wells from 500 feet to 2,500 feet and require an even bigger buffer between wells and schools and hospitals.
- Stop the “chemical cover-up” by requiring drillers to make public to everyone, not just the DEP, all the chemicals used in drilling and fracking.
- Seek safer ways than using tanker trucks prone to spills to transport toxic wastes from wastewater ponds, called impoundments.
- Enact strict regulations on high pressure gas gathering lines running from well pads.
- Enact rules requiring the DEP to consider the aggregated air quality impacts of well sites, compressor stations and “pigging,” that is pipeline clean-out operations, instead of looking at emissions from those facilities individually.
- Conduct a full and proper public health assessment of the impacts of shale gas drilling and fracking. The state Health Department is undertaking such a study.
- End the “revolving door” that allows DEP employees to go to work for the drilling industry because it erodes public trust.”
- End the “troubling pattern” of DEP addressing almost all drilling violations with civil penalties and make better use of the attorney general’s office to press criminal charges.
Along Mariner East pipelines, secrecy and a patchwork of emergency plans leave many at risk and in the dark – Meadowbrook Mobile Home Park in York County is nestled with brown-paneled trailers and potholes half-filled with jagged concrete. Sue Ritter has lived here for more than 40 years… When workers in large trucks began barreling down these roads in 2017, hollowing out part of the forest for Sunoco’s Mariner East pipeline project, it seemed like another nuisance the now 73-year-old had little choice but to accept.The only indication Ritter said she was given about the pipeline – designed to carry highly volatile natural gas liquids – was the sound of construction groaning late into the night. She said she had no idea the project was unlike any other in the region. Should a leak occur, she did not know it would be odorless and appear as a fog or frost, causing pools of water to bubble in low-lying areas. She did not know that dried grass or dead animals found near the yellow marker poles could be a sign to evacuate. She did not know that, in an emergency, she should leave on foot because turning a car ignition could cause an explosion. “I don’t remember seeing anything about what would happen in case of emergency,” she said, adding it’s a struggle for her to walk more than two blocks. “Where are you supposed to go? … My first instinct would be to get in the car.” “We can’t even say ignorance is bliss.” As the Mariner East pipelines become a permanent underpinning of Pennsylvania, many communities are still in the dark about what to do in the rare case of a serious accident. That’s in large part because pipeline operators have withheld critical safety information from the public with little oversight by the state, a Spotlight PA investigation has found. Three pipelines are part of the 350-mile Mariner East system, which runs across the lower half of Pennsylvania from Ohio and West Virginia to a storage and processing facility in Marcus Hook, just outside Philadelphia. .For decades, federal regulators have identified failures in public education as directly contributing to fatalities in natural gas liquids pipeline accidents. In separate incidents involving pipelines in Texas and Mississippi – operated by Koch Pipeline Co. and Dixie Pipeline Co., respectively – residents in 50 homes should have received informational mailers but did not, and four people burned to death, according to federal reports. Sunoco and its parent company, Energy Transfer Partners, have withheld information in Pennsylvania in part by citing a state law enacted in the wake of the Sept. 11 terrorist attacks intended to prevent key infrastructure, like water systems, from being compromised. But residents, school officials, and some local emergency planners said it is now preventing them from understanding the scope of harm associated with Mariner East and creating adequate response plans.
Natural gas-fired power plant project in WVa tabled for now (AP) – A company that received state approval for a loan guarantee for West Virginia’s first natural gas-fired power plant said it has stopped the project for now. Energy Solutions Consortium of Buffalo, New York, announced in a news release Friday that the project in Brooke County has been put on hold “due to changing conditions in the energy and financial markets,” news outlets reported. The West Virginia Economic Development Authority approved a $5.5 million loan guarantee for the project in September. The company’s statement said it is “evaluating alternative options to move forward.” The project would have brought more than 1,000 construction jobs alone to build the plant on the site of a reclaimed strip mine. Gov. Jim Justice had questioned why the project’s developers would need state funding. He also wanted the plant to be built with in-state labor and utilize natural gas produced in West Virginia.
Pipeline opponent falsely said to be part of antifa, lawsuit claims – Shortly before a Mountain Valley Pipeline opponent was charged in 2018 with trespassing in a construction zone, a member of the project’s security force falsely targeted her as “affiliated with Antifa,” a lawsuit claims. The charges against Nan Gray and two of her friends were later dropped by a prosecutor who said there was no evidence to support them. Gray and Gordon Jones then brought malicious prosecution lawsuits against Mountain Valley and its security firm, Global Security Corp., in December 2018. A lawsuit filed last week by a third person arrested, Hazel Beeler, alleges that a conspiracy to have the three Craig County residents charged was based, at least in part, on Gray’s supposed connections with antifa. Duane Moriarity, a security coordinator with lead pipeline partner Equitrans Midstream Corp., told colleagues shortly before Gray was arrested that she is a “leftist biologist” who “consorts with and gives direction to Antifa,” according to the lawsuits. “I hope she gets locked up,” the papers quote Moriarity as writing in a text shortly before Mountain Valley and Global Security officials obtained charges from a magistrate against Gray, Jones and Beeler. Gray, a soil scientist and outspoken opponent of Mountain Valley, has never been affiliated with antifa, the lawsuit states
FERC Extends Mountain Valley Pipeline Permit Despite Serious Doubts of Its Completion – – Today, the Federal Energy Regulatory Commission (FERC) granted Mountain Valley Pipeline, LLC (MVP) permission to resume construction, even though the beleaguered fracked gas project still lacks some necessary authorizations. Industry watchers are growing increasingly skeptical of MVP’s future after a similar fracked gas pipeline, the Atlantic Coast Pipeline, was cancelled as a result of similar permitting and legal challenges. Over a dozen environmental advocacy organizations have opposed MVP’s request. Planned to run over 300 miles through West Virginia and Virginia, state inspectors have already identified hundreds of violations of commonsense water protections, and MVP has paid millions of dollars in penalties. There are also questions about whether MVP is accurately reporting how much of the project has been completed, with one analysis showing it is only 51% finished. At this time the project is at least $2 billion over budget, two years behind schedule, and developers admit they need two more years to complete the project. In response, Sierra Club Beyond Dirty Fuels Senior Campaign Representative Joan Walker released the following statement: “MVP has violated commonsense water protections hundreds of times and allowing them to resume construction just means putting more communities at risk for an unnecessary pipeline that may never even be built. FERC is supposed to regulate these fracked gas projects, not roll over for them.” Roberta Bondurant of Preserve Bent Mountain/BREDL said: “MVP construction crews have yet to traverse the most intense and well known geohazards – steep, in some places, nearly vertical slopes, slip prone soils, karst, and earthquakes – in the height of a global pandemic, during hurricane season – these multiple geohazards make today’s FERC/MVP plan to resume construction maniacal, wholly destructive to land, forest, water and living beings. With such challenges ahead, MVP’s promises to complete by any time in 2021 simply fly in the face of fact. People and places in the path of MVP are not disposable – we won’t be sacrificed for MVP investment returns.” Russell Chisholm, Protect Our Water, Heritage, Rights Co-chair said: “FERC’s dangerous decision is an attempt to rescue MVP from their own mismanagement despite years of delays and documented failures. FERC favors energy policy by force, rewards negligence over the objections of thousands, ignores the evidence of harm to our communities, and shamefully denies climate realities. To do this as the COVID-19 crisis spreads through rural Virginia and West Virginia puts MVP and FERC’s disregard for our safety on full display.” David Sligh, Conservation Director of Wild Virginia said: “This is another in a long list of irresponsible decisions by FERC. In allowing construction to proceed while MVP still lacks required permits, the Commission is enabling the corporation’s attempt to rush ahead, heedless of the harm already done and that which is sure to follow if this decision stands. The MVP is still not a done deal and FERC’s collusion with the frackers won’t make it so.”
Work on Mountain Valley Pipeline can resume, FERC rules – Mountain Valley Pipeline was given another two years Friday to complete a natural gas pipeline already marked by six years of community opposition, environmental damage, legal fights and delays. In orders filed late Friday afternoon, the Federal Energy Regulatory Commission also lifted a stop-work order for all but a 25-mile segment of the interstate transmission line that includes the Jefferson National Forest and adjacent land. While acknowledging problems with erosion and sedimentation during the first two years of construction, FERC found that allowing the pipeline to be completed is best for both the environment and the public. “The presence of equipment, personnel, and partially completed construction is disruptive to landowners, some of whom have endured perturbation since February 2018,” the commission wrote in a 2-1 decision. “As such, proceeding to final restoration is in the best interest of these landowners and the environment.” In a dissent, Commissioner Richard Glick wrote that lifting the stop-work order is “plowing ahead with construction in the face of uncertainty.” While two permits set aside by legal challenges have since been reissued – allowing the pipeline to cross streams and wetlands and for work to resume without jeopardizing endangered wildlife – Mountain Valley still lacks approval to pass through the national forest. By allowing work in other areas to resume, Glick wrote, “the Commission has put the cart before the horse.” “That is a mistake,” he continued, because even if the Forest Service were to approve the pipeline’s passage through about 3.5 miles of federal woodlands, it could require a different route, “leaving the work done to date little more than a pipeline to nowhere.” Glick also dissented in part to FERC’s second order, which was to extend by two years its certificate of public necessity, a major decision that allowed construction to begin. Issued Oct. 13, 2017, the three-year certificate would have expired next Tuesday. While Glick joined commissioners Neil Chatterjee and James Danly in supporting the two-year extension, he had strong words for a part of the decision that precluded landowners who were not part of the original proceeding from having a say in the matter. “Time and time again, landowners do their very best to navigate the complexity of FERC proceedings,” he wrote. “And, time and time again, the Commission relies on technicalities to prevent them from even having the opportunity to vindicate their interests.” The owners of about 300 pieces of property in Virginia did not want to sell their rural land to a private venture, which then took it using the power of eminent domain.
Federal Regulators Rule Controversial Mountain Valley Pipeline Can Restart Construction – Construction can continue on most of the controversial Mountain Valley Pipeline (MVP), the Federal Energy Regulatory Commission (FERC) ruled Friday.The pipeline is scheduled to carry fracked natural gas through approximately 300 miles of Virginia and West Virginia, according to The Hill. The project was begun in 2018 and originally slated to be completed that same year, Reuters reported. But fierce legal opposition from environmental and community groups has significantly delayed the project. The FERC’s latest approval comes just months after the owners of another contested Appalachian pipeline, the Atlantic Coast Pipeline, canceled the project after years of similar delays.”MVP has violated commonsense water protections hundreds of times and allowing them to resume construction just means putting more communities at risk for an unnecessary pipeline that may never even be built,” Sierra Club Beyond Dirty Fuels senior campaign representative Joan Walker told WDBJ of the decision. “FERC is supposed to regulate these fracked gas projects, not roll over for them.”The FERC paused construction of the MVP in 2019 after a federal court halted a Biological Opinion from the U.S. Fish and Wildlife Service (FWS), which allows construction in the habitat of endangered or threatened species, according to Reuters and The Hill. Specifically, the court found fault with the opinion’s assessment of the pipeline’s impact on imperiled bat species, The Hill reported.However, the FWS issued a new opinion in September, according to Reuters, though environmental groups are once again challenging it.In light of the new FWS opinion, the FERC ruled two-to-one to allow the pipeline to resume construction along most of its route.”Based on staff’s review of the Mountain Valley Pipeline Project, we agree that completion of construction and final restoration … where permitted, is best for the environment and affected landowners,” Republican commissioners Neil Chatterjee and James Danly wrote.However, the pipeline still needs permission to cross the Jefferson National Forest, something dissenting commissioner Democrat Richard Glick pointed out.”MVP may eventually receive permission to cross the Jefferson National Forest. But, by allowing it to recommence construction before doing so, the Commission has put the cart before the horse,” Glick said, as The Hill reported. In addition to allowing the pipeline to resume construction Friday, the FERC also extended its certificate for another two years, as the company had requested, Appalachian Voices reported. The extension was granted despite the fact that more than 43,000 people had told the FERC they opposed the move during the public comment period. They noted that the pipeline had already amassed at least 350 environmental violations and $2.26 million in fines over the course of construction so far.
Groups take legal action to support North Carolina denial of Southgate pipeline > Appalachian Voices – The Center for Biological Diversity, Appalachian Voices and Sierra Club filed a motion Tuesday with the U.S. 4th Circuit Court of Appeals to defend the North Carolina Department of Environmental Quality’s denial of a key water permit for a major fracked-gas pipeline.In August, North Carolina denied a mandatory water permit for the 73-mile MVP Southgate pipeline, a proposed extension of the 300-mile, still-unbuilt Mountain Valley Pipeline. The department based its permit denial on “avoidable environmental impacts to water quality and protected riparian buffers,” in part due to dim prospects for the successful completion of the mainline. Mountain Valley, the project’s sponsor, filed a petition in the 4th Circuit to overturn the state’s decision.”As the climate crisis bears down on us all, with worsening fires, floods and extinctions, we need to focus our attention on advancing clean energy solutions, not fossil fuel boondoggles,” said Perrin de Jong, a North Carolina-based staff attorney at the Center. “For the communities and imperiled wildlife along the proposed pipeline’s route, it’s time to bury this senseless project once and for all.””North Carolina environmental regulators looked carefully at the Southgate proposal, and saw the dire implications for the water quality of our state that this wholly unnecessary project would bring. They made the right decision to reject the permit and avoid the risk, and we support that,” said Ridge Graham, Appalachian Voices’ North Carolina field coordinator.”Clean water is far too important to allow this unnecessary fracked gas pipeline to threaten it,” said Elly Benson, a senior attorney for the Sierra Club. “We moved to intervene in this action because MVP has proven it can’t be trusted to protect the streams and rivers that are so vital to these communities.” The project has faced significant headwinds from the start. The company has been fined for more than 300 water-quality violations in West Virginia and Virginia, and construction was halted for almost a year due to failures to properly protect endangered species along the project’s route. Mountain Valley is currently not permitted to complete construction of the Mountain Valley Pipeline.
Court Issues Emergency Order Blocking Mountain Valley Pipeline From Stream, Wetland Construction – A federal appeals court has temporarily blocked developers of the Mountain Valley Pipeline from doing construction across streams and wetlands in southern West Virginia and Virginia.The emergency administrative stay was issued Friday by the U.S. Court of Appeals for the Fourth Circuit.Environmental groups led by the Sierra Club appealed to the court to stop river and stream crossings after the U.S. Army Corps of Engineers on Sept. 25 reissued the project’s permit that allows the 303-mile natural gas pipeline to cross nearly 1,000 waterways in the two states. The original approvals were tossed by a federal appeals court in 2018.Environmental groups asked the Corps to reconsider. When the agency upheld its permits, advocates filed a lawsuit with the Fourth Circuit asking the court to review. The emergency order will remain in place until the court considers the full motion to stay.Environmental groups, in briefs, cited an Aug. 4 earnings call during which pipeline developer Equitrans told its shareholders it would rush to complete stream crossings before the court could stop it.In its response, Mountain Valley Pipeline opposed the stay. Developers said it ultimately expected cases from the environmental groups to fail and said it reached out to the Sierra Club in an effort to discuss the river crossings of most concern.Mountain Valley Pipeline had previously agreed not to undertake any waterbody construction through Oct. 17.The Friday ruling by the court puts stream construction projects on hold. However, an Oct. 9 order by the Federal Energy Regulatory Commission partially lifted a stop-work order for the multi-billion dollar project on all but 25 miles of national forest land. The agency also extended the project’s for two years. Despite the court order, construction along the route may resume in other areas.
New York regulators must act on Con Edison’s contract with Mountain Valley Pipeline — The CEO of New York gas utility Con Edison recently made the bold statement that natural gas is “no longer … part of the longer-term view” in the transition to a clean energy economy, and that he does not expect the company to make additional investments in natural gas pipelines. Many of the company’s actions – from its clean energy commitment, to its framework for pursuing non-pipe alternatives – place it on a path toward meeting that vision. But Con Ed’s investment and contract with Mountain Valley Pipeline call into question that bold statement and demand further scrutiny from the New York Public Service Commission.In 2016, Con Ed signed a 20-year contract for service on Mountain Valley Pipeline, a planned 300-mile pipeline in West Virginia and Virginia. Mountain Valley would connect with other pipelines on the East Coast to transport natural gas from the Marcellus Shale for ultimate delivery to the New York region. Since Con Ed entered the contract, the pipeline has been plagued by environmental and economic risks and significant legal challenges, and it is still not in service.Con Ed’s decision to enter a contract with the pipeline is particularly concerning because its affiliate company, Con Edison Transmission, is a 10% owner in the pipeline.When affiliated companies play on both sides of a gas pipeline – with one company as a pipeline developer and the other company, a utility, agreeing to buy transportation service from the pipeline – the result can enrich the developer and its shareholders, to the detriment of captive customers funding the project through their monthly energy bills. An EDF analysis indicates that Con Ed customers would shoulder $1.2 billion in costs for the Mountain Valley Pipeline, regardless of whether the company uses the pipeline capacity. Con Ed’s affiliate contract has never been scrutinized by the commission, despite repeated requests by EDF over the last three years. To ensure ratepayers are protected, EDF has called on the commission to clarify the law regarding oversight of these types of agreements. By acting on EDF’s petition and opening a separate proceeding to address the Mountain Valley Pipeline contract, the commission can ensure a forum is available to determine whether the contract is in the public interest.
Too Much Sun Degrades Coatings That Keep Pipes From Corroding, Risking Leaks, Spills and Explosions – For natural gas pipeline developers hunting for a good deal on a 100-mile section of steel pipe, a recent advertisement claimed to have just what they are looking for.Following the cancelation of the proposed Constitution natural gas pipeline in Pennsylvania and New York, a private equity firm recently offered a “massive inventory” of never-used, “top-quality” coated steel pipe. What the company didn’t mention is that the pipe may have sat, exposed to the elements, for more than a year, a period of time that exceeds the pipe coating manufacturers’ recommendation for aboveground storage, which could make the pipe prone to failure. Long term, aboveground pipe storage has become commonplace as pipeline developers routinely begin construction activity on pipeline projects before obtaining all necessary permits and as legal challenges add lengthy delays. Whether canceled or stalled, overdue oil and gas pipelines across the country may face a little-known problem that raises new safety concerns and could add additional costs and delays. Fusion bonded epoxy, the often turquoise-green protective coating covering sections of steel pipe in storage yards from North Dakota to North Carolina, may have degraded to the point that it is no longer effective. The coatings degrade when exposed to ultraviolet radiation from the sun while the pipes they cover sit above ground for years. The compromised coatings leave the underlying pipes more prone to corrosion and failures that could result in leaks, catastrophic spills or explosions. Degraded coatings were implicated in an oil spill from a failed pipeline near Santa Barbara, California in 2015. Toxic compounds may also be released as the coating breaks down, raising concerns that the pipes could pose a health threat to those who live near the vast storage yards holding them. “There are pipelines being built all over the place and it doesn’t seem like anyone is keeping close track of what the status is of the coatings,” said Amy Mall, a senior advocate with the Natural Resources Defense Council. “There are a lot of unknowns here and yet we’re relying on the coating to protect landscapes and communities from massive explosions.” The National Association of Pipe Coating Applicators, an industry group,states that “above ground storage of coated pipe in excess of 6 months without additional ultraviolet protection is not recommended.” However, photographs and satellite images suggest pipe sections for the Constitution Pipeline may have been stored aboveground without ultraviolet protection for more than a year before they were covered in “whitewash” – common household paint – that shields their coatings from the sun.As pipeline projects across the country face increasing legal challenges and construction delays, long-term aboveground storage of pipe sections are not limited to the Keystone XL and Constitution pipelines. Yet basic information is scant on how long pipe has been stored above ground; what, if any, measures developers took to protect the pipe from the elements, or what condition the pipe is in .
A Bumpy Ride as Storms Face Inventories – The 2020 hurricane season has been active. The past three significant storms headed for the Gulf of Mexico and the Louisiana coast. In early September, Hurricane Laura pushed the November NYMEX natural gas futures price to a high of $3.002 per MMBtu. Towards the end of the month, Hurricane Sally was the second storm of the season. The approach of Sally pushed the November futures contract to a high of $2.928 on September 24.The most recent storm, Hurricane Delta, was charging towards the US Gulf Coast last week. So far, the threat to energy production sent the price of November natural gas futures to a high of $2.821on October 9.The Henry Hub is the delivery point for NYMEX natural gas futures. The Hub is in Erath, Louisiana, not far from the Gulf of Mexico. In 2005 and 2008, Hurricanes Katrina and Rita sent the natural gas futures price above $10 per MMBtu. In 2005, the energy commodity rose to its highest level in history at $15.65 per MMBtu. Meanwhile, natural gas has not traded north of $6.493 since 2008. At below $3, the price remains under pressure. Massive discoveries of natural gas reserves in the Marcellus and Utica shale regions and fewer regulations have increased supplies of the energy commodity over the past years. While storms that threaten natural gas infrastructure can still push prices higher, they remain at very low levels. As we head into the peak season for demand during the winter months, the amount of natural gas in storage is approaching record levels in the US. So far, even though the hurricane season has caused periodic rallies, the highs continue to be lower as we move towards the time of the year when natural gas often reaches a seasonal high. The move to a new high for 2020 at $2.821 last week was more a function of the roll from October to November futures than price action in the natural gas futures arena. The contracts rolled at an over 60 cents per MMBtu contango or premium for the November contract, creating the higher high. Even though Hurricane Delta was descending on Louisiana on Friday, the price of nearby natural gas closed the week below the medium-term technical resistance level at $2.905 per MMBtu.
U.S. natgas jumps to 19-month high on cold, rising LNG exports – (Reuters) – U.S. natural gas futures spiked on Monday to their highest since March 2019 as the amount of gas flowing to liquefied natural gas (LNG) export plants jumps with units returning in Louisiana after Hurricane Delta and in Maryland after maintenance work. Traders also noted prices were up on forecasts for colder weather and higher heating demand over the next two weeks and with output on track to drop to its lowest since July 2018 due mostly to well shut-ins for Delta. Delta slammed into the Louisiana coast late Friday, causing over 878,000 customers to lose power. There were about 224,000 homes and businesses still without service Monday morning, mostly in Louisiana. Front-month gas futures rose 14.0 cents, or 5.1%, to settle at $2.881 per million British thermal units, their highest close since March 2019. Data provider Refinitiv said output in the Lower 48 U.S. states would slide from a 26-month low of 82.4 billion cubic feet per day (bcfd) over the weekend to a preliminary 82.0 bcfd on Monday due to the Delta shut-ins. The U.S. Bureau of Safety and Environmental Enforcement said energy firms started to return offshore production in the Gulf of Mexico. BSEE said that output was now curtailed by 1.3 bcfd, down from 1.7 bcfd on Sunday. In Louisiana, the Cameron and Sabine Pass LNG export plants both took in more pipeline gas over the weekend and tankers started to return to Sabine. There is also at least one vessel waiting in the Gulf of Mexico to go to Cameron, according to Refinitiv data. In Maryland, Dominion’s Cove Point started to exit its three-week annual maintenance outage. As LNG feedgas rises and the weather turns colder, Refinitiv projected average demand would jump from 84.6 bcfd this week to 94.8 bcfd next week. That is higher than Refinitiv’s forecast on Friday.
U.S. natgas futures ease from 19-month high on lower demand forecasts (Reuters) – U.S. natural gas futures eased on Tuesday from a 19-month high in the prior session as output started to rise after Hurricane Delta and on forecasts for less demand over the next two weeks than previously expected. That price drop came despite a continued increase in gas flows to liquefied natural gas (LNG) export plants now that all facilities were ramping up following hurricane and maintenance shutdowns over the past few weeks. Front-month gas futures fell 2.6 cents, or 0.9%, to settle at $2.855 per million British thermal units. On Monday, the contract closed at its highest level since March 2019. Data provider Refinitiv said output in the Lower 48 U.S. states jumped to 84.1 billion cubic feet per day (bcfd) on Monday from a 26-month low of 82.4 bcfd over the weekend as wells shut for Delta returned to service. As LNG exports rise and the weather turns colder, Refinitiv projected average demand would jump from 84.6 bcfd this week to 92.6 bcfd next week. That, however, is lower than Refinitiv’s forecast on Monday. The amount of gas flowing to LNG export plants has averaged 6.7 bcfd so far in October, up from 5.7 bcfd in September, despite several hurricane and maintenance outages this month. That would be the most in a month since April and puts exports on track to rise for a third month in a row for the first time since February when feedgas hit a record 8.7 bcfd as rising global gas prices prompted buyers to reverse some cargo cancellations. Prior to that, U.S. exports fell every month from March to July as coronavirus-related demand destruction caused prices in Europe and Asia to collapse and buyers to cancel over 150 cargoes.
U.S. natgas futures drop over 7% on lower demand forecasts, rising output (Reuters) – U.S. natural gas futures dropped over 7% on Wednesday as output climbs with Gulf Coast wells returning to service after Hurricane Delta and on forecasts for milder weather and lower heating demand than previously expected over the next two weeks. That price drop came despite a continued increase in gas flows to liquefied natural gas (LNG) export plants now that all facilities were ramping up following hurricane and maintenance shutdowns. Front-month gas futures fell 21.9 cents, or 7.7%, to settle at $2.636 per million British thermal units. That puts the contract down about 11% since hitting a 20-month intraday high on Monday. Data provider Refinitiv said output in the Lower 48 U.S. states jumped to 85.8 billion cubic feet per day (bcfd) on Tuesday from a 26-month low of 82.4 bcfd over the weekend as wells shut for Delta returned to service. As LNG exports rise and the weather turns colder, Refinitiv projected average demand would jump from 85.0 bcfd this week to 91.5 bcfd next week. That, however, is lower than Refinitiv’s forecast on Tuesday. The amount of gas flowing to LNG export plants has averaged 6.7 bcfd so far in October, up from 5.7 bcfd in September, despite several hurricane and maintenance outages this month. That would be the most in a month since April and puts exports on track to rise for a third month in a row for the first time since February when feedgas hit a record 8.7 bcfd as rising global gas prices have prompted buyers to reverse some earlier cargo cancellations. Previously, U.S. exports fell every month from March to July as coronavirus-related demand destruction caused prices in Europe and Asia to collapse and buyers to cancel around 175 cargoes.
US working natural gas volumes in underground storage rise by 46 Bcf: EIA | S&P Global Platts – US natural gas injections into storage the week ended Oct. 9 increased by less than half the volume reported during the same week one year prior as weaker Henry Hub prices prompted coal-to-gas switching and stronger residential and commercial demand. Storage inventories increased by 46 Bcf to 3.877 Tcf for the week, the US Energy Information Administration reported the morning of Oct. 15. The injection was less than an S&P Global Platts’ survey of analysts calling for a 50 Bcf build. The injection measured much less than the five-year average gain of 87 Bcf, according to EIA data. The 41 Bcf drop in the surplus marked the largest reduction since January as the prolonged weakness in US production, combined with the return of both heating demand and LNG exports, begin to tighten domestic gas markets through the end of the year. Storage volumes stood at 388 Bcf, or 11% more than 3.489 Tcf a year earlier; and 353 Bcf, or 10%, more than the five-year average of 3.524 Tcf. Total US demand increased by roughly 3.8 Bcf/d on the week to 85.2 Bcf/d, led by a combined 2.8 Bcf/d increase in residential-commercial demand in the East and Midwest regions on colder weather, according to Platts Analytics. Demand was further bolstered by an uptick in LNG feedgas deliveries along the Gulf Cost. Upstream, total supply slipped 200 MMcf/d week on week as onshore and offshore production fell almost 1 Bcf/d, though an uptick in net Canadian imports helped minimize the drop in supply. The approach of Hurricane Delta in the week ended Oct. 10 prompted most Gulf of Mexico operators to shut in production. The NYMEX Henry Hub November contract leaped 14 cents to $2.77/MMBtu in trading following the release of the weekly storage report. The December-through-March contract strip increased 6 cents on average to $3.31/MMBtu. ICE end-of-season storage peak inventory trades were at 3.94 Tcf after spending much of the past three months trading above 4 Tcf. Platts Analytics’ supply and demand model currently forecasts a 48 Bcf injection for the week ending Oct. 16. This would lower the surplus to the five-year average by 27 Bcf. Sample storage injections for the week in progress increased by 1 Bcf week over week as US balances flicker in the middle ground between waning power burn and waxing res-comm demand. Total supply has averaged 1.4 Bcf/d lower on the week at an average of 89.4 Bcf/d, with the offshore production sector posting a 500 MMcf/d dip due to Hurricane Delta. However, South Central demand has proven unexpectedly buoyant in the wake of Hurricane Delta. As a result, depleted field injections fell while the US Gulf Coast salt dome sample flipped from a net injection of 1 Bcf to a net draw of less than 100 MMcf/d week over week.
U.S. natgas jumps over 5% on small storage build, cold forecasts – (Reuters) – U.S. natural gas futures rose over 5% on Thursday on forecasts for colder weather and more heating demand over the next two weeks and a smaller-than-expected storage build. That price increase came despite a rise in output with Gulf Coast wells returning after Hurricane Delta and an increase in gas flows to liquefied natural gas (LNG) export plants. The U.S. Energy Information Administration said U.S. utilities injected 46 billion cubic feet (bcf) of gas into storage in the week ended Oct. 9. That is lower than the 55-bcf build analysts forecast in a Reuters poll and compares with an increase of 102 bcf during the same week last year and a five-year (2015-19) average build of 87 bcf. The increase boosted stockpiles to 3.877 trillion cubic feet (tcf), 10.0% above the five-year average of 3.524 tcf for this time of year and keeps inventories on track to reach a record over 4.0 tcf by the end of October. After falling almost 8% in the prior session, front-month gas futures rose 13.9 cents, or 5.3%, to settle at $2.775 per million British thermal units. Data provider Refinitiv said output in the Lower 48 U.S. states jumped to 87.0 billion cubic feet per day (bcfd) on Wednesday from a 26-month low of 82.4 bcfd over the weekend as wells shut for Delta returned to service. As LNG exports rise and the weather turns colder, Refinitiv projected average demand would jump from 85.2 bcfd this week to 91.6 bcfd next week. That is higher than Refinitiv’s forecast on Wednesday. The amount of gas flowing to LNG export plants has averaged 6.8 bcfd so far in October, up from 5.7 bcfd in September, despite several hurricane and maintenance outages this month.
Natural Gas Futures Sputter on Weather, LNG Demand Uncertainty — Natural gas futures struggled to maintain momentum early Friday as traders tried to determine whether liquefied natural gas (LNG) and weather demand would be enough to ward off a toppling of storage inventories by the end of October. With an increasingly chillier weather pattern emerging for the end of the month, the November Nymex gas futures contract took off midday, but then retreated to settle the day at $2.773, off two-tenths of a cent. December climbed 1.0 cent to $3.271. Spot gas prices moved lower on soft weekend demand. NGI’s Spot Gas National Avg. fell 8.5 cents to $1.995. With LNG demand not yet able to reach its full potential because of restrictions preventing deep draft traffic in the Calcasieu Ship Channel following Hurricane Delta, weather has become increasingly important to the storage trajectory for the remainder of October and into the early part of winter. Feed gas flows to U.S. terminals on Friday moved closer to 8 Bcf, but Cameron LNG may not resume full operations until the waterway restrictions are lifted. Given the current rate of liquefaction, Genscape Inc. analyst Amir Rejvani said Cameron would need to shut down or decrease operations significantly over the weekend in order to not reach local LNG tank capacity. Cameron spokesperson Anya McInnis told NGI the facility “continues to make progress toward resuming normal operations” and is “in contact with the U.S. Army Corps of Engineers, the U.S. Coast Guard and the Lake Charles Pilots to determine their timeline for restoring deep-draft vessel access to the waterway.” Army Corps spokesperson Ricky Boyett told NGI at midday Friday that the previously submerged oil rig had been removed, and the removal of a recreational boat “was in the process.” Plans to remove the barge that was discovered late Tuesday were expected to be finalized over the weekend, and a dredger was currently working in the waterway. “As long as the channel remains shut in, weak demand and low cash prices could limit the November contract’s upside potential,” said EBW Analytics Group. As for weather, the midday Global Forecast System (GFS) continued to favor cold slowly easing across the northern and central United States Oct. 29-Nov. 1, and teasing cold air could hold longer, NatGasWeather said. However, the weather data was inconsistent after Oct. 24-25, and big changes were possible. “What’s likely to be of greatest importance is how the weather data trends for Oct. 28-Nov. 1 and whether cold shots can prove to continue into the northern United States,” the forecaster said. The European model favors a milder pattern gradually returning Oct. 28-Nov. 1, while the GFS has demand slowly easing but trying to hold a little stronger. NatGasWeather said it was important to consider that the GFS has had “credibility problems” to start the heating season by over-forecasting cold shots, which is evidenced by giving back a huge amount of demand for the coming week. Any prolonged period of mild weather may keep a lid on prices for the near term, with storage inventories still sitting well ahead of historical levels. On Thursday, the Energy Information Administration (EIA) said stocks grew by 46 Bcf to 3,877 Bcf. This is 388 Bcf above year-ago levels and 353 Bcf above the five-year average.
Pandemic puts natural gas projects on hold – The COVID-19 pandemic has suppressed demand for energy around the world, and the United States is producing a lot of natural gas that doesn’t have anywhere to go. Last year saw massive investment in liquified natural gas facilities, but that expansion has come to a grinding halt. The price of natural gas is at historic lows, so the plans to expand existing liquified natural gas terminals and build more in the U.S. have been put on hold.”They may not be put off forever – some just a couple years, some maybe a bit longer,” said Joshua Rhodes, research associate at the University of Texas Energy Institute.Rhodes said that could hurt workers in places like the Gulf Coast of Texas and Louisiana.”As that process stops, you’re going to have less need for construction workers; you’re gonna have less need for the engineers and the overseers on those projects,” Rhodes said.And beyond the stalled projects, Rhodes said reduced LNG exports mean less work for those who already have jobs in natural gas. Because building facilities requires a huge capital investment, they have to remain active for a while, according to Nikos Tsafos, a senior fellow with the Energy Security and Climate Change Program at the Center for Strategic and International Studies.”The thing about LNG projects is they have a long time horizon,” he said. “They take about five years to build, and they stay online for 20 plus years.” Tsafos said that means energy companies have to assume we’ll be consuming natural gas for decades, despite accelerating climate change concerns.
Crews clean up oil spill on Wilmington River – Crews are cleaning up an oil and fuel spill in the Wilmington River after a barge and crane flipped over and sunk into the water. The Coast Guard says construction was happening at a resident’s property along the river when the crane flipped. Over the last few days, various teams have been overseeing cleanup operations. Since Thursday night, the Coast Guard and other crews have been investigating the spill’s potential impact on the environment and human health. “We sent a team of personnel to the residence and investigated the situation,” Lieutenant Matthew Spado with the Marine Safety Unit. “We found out there’s about 20-30 gallons of fuel onboard the crane and tug that were there.” Spado says dive operations took place on Monday to assess the equipment that has sunk and to begin rigging it for salvage operations. “The crane was attached to the barge and that flipped over and so those pieces are intact,” he said. A spill containment method called a boom has been put around the area and since Thursday, Spado says there’s been minor sheening in the water. “We will ensure that all of the pollution is cleaned up in an appropriate manner,” he says. David Mewborn is with the Savannah Riverkeeper. Their job is to advocate for clean water often participating in volunteer cleanups around the rivers and tributaries of the river basin. “Accidents like this can affect something as small as the microorganisms in the marsh to the shellfish, the shore birds, the fish and the mammals that are in the water,” Mewborn said. Until the spill is cleaned up, Mewborn says they will keep an eye on it to make sure no residue or oils can be seen or that any hazardous materials are floating on the surface.
Colonial Pipelines Line 2 shut after Hurricane Delta: company (Reuters) – Colonial Pipeline, the largest oil products pipeline in the United States, shut its main distillate fuel line after Hurricane Delta disrupted electric power, the company said on Sunday. Line 2 was shut on Saturday evening, pending the restoration of commercial power to stations upstream of Baton Rouge, Louisiana, the company said. Its main gasoline line resumed operations on Saturday, the company said. Hurricane Delta made landfall on Friday evening in southwestern Louisiana as a Category 2 hurricane on the five-step Saffir-Simpson scale. It had weakened by Sunday. Colonial connects Gulf Coast oil refineries with markets across the southern and eastern United States. Line 2 runs from Houston to Greensboro, North Carolina.
U.S. Gulf of Mexico offshore oil production cut by 92% – regulator – U.S. Gulf of Mexico offshore oil output on Friday was down by 1.69 million barrels, or 92% of the region’s daily production, the U.S. Department of Interior reported, as energy companies shut wells and offshore pipelines as Hurricane Delta churned through. Producers had evacuated staff from 281 platforms and drilling rigs operating in the Gulf of Mexico as of midday on Friday. Producers had halted some 62% of offshore natural gas production, or 1.68 billion cubic feet per day, Interior Department figures showed.
U.S. energy companies begin restoring oil and gas output (Reuters) – U.S. energy companies were returning workers and restarting operations at storm-swept production facilities along the U.S. Gulf Coast on Sunday, two days after Hurricane Delta barreled through the area. Chevron Corp, Royal Dutch Shell Plc and BHP Group were returning workers to production platforms in the U.S.-regulated northern Gulf of Mexico, the companies said. BHP expects to complete the return of workers to its Shenzi and Neptune production platforms on Sunday, spokeswoman Judy Dane said, but resuming flows will depend on how quickly pipelines return to service, she said. It can take several days after a storm passes for energy producers to evaluate facilities for damage, return workers and restore offshore production. The companies that operate oil and gas pipelines and process the offshore output also shut ahead of the storm. Cumulative volumes shut-in by Hurricane Delta through Sunday, according to company reports to the U.S. government, amounted to 8.79 million barrels of oil and 8.30 billion cubic feet of natural gas. The area produces about 1.8 million barrels of oil per day, or 17% of total daily U.S. output, and 5% of daily U.S. natural gas production. Still remaining shut are the Calcasieu Waterway in Calcasieu and Cameron Parishes in Louisiana and the ports of Lake Charles and Cameron, Louisiana, near where Delta made landfall Friday evening. The ports of Beaumont and Port Arthur, Texas, including the Sabine Pass, which serve major oil and liquefied natural gas processing plants, were reopened with restrictions on Sunday, the U.S. Coast Guard said. Total SA continued restarting its 225,500 barrel-per-day Port Arthur, Texas, refinery on Sunday. The refinery, which is about 65 miles (100 km) west of Creole, Louisiana, where the storm went ashore, lost power on Friday. Fast-moving Delta swept over Louisiana on Saturday and became a low-pressure system over the U.S. state of Mississippi later that day. It was south of Knoxville, Tennessee, Sunday morning and moving northeast at 16 mph.
91 Percent of US GOM Oil Still Knocked Out – The Bureau of Safety and Environmental Enforcement (BSEE) revealed on Sunday that 91.01 percent of oil production and 62.15 percent of gas production in the U.S. Gulf of Mexico (GOM) was still shut-in as a result of Hurricane Delta. These oil and gas shut-in figures, which stood at 91.72 percent and 62.43 percent, respectively, on Saturday, correspond to 1.68 million barrels of oil per day and 1.68 billion cubic feet of gas per day, the BSEE highlighted. As of Sunday, personnel had been evacuated from a total of 198 production platforms from the U.S. GOM, which is equivalent to 30.79 percent of the 643 manned platforms in the region. Personnel have also been evacuated from four non-dynamically positioned rigs in the area, which is equivalent to 40 percent of the ten rigs of this type currently operating in the U.S. GOM. A total of one dynamically positioned rig remained off the location out of the hurricane’s projected path as a precaution. On Saturday, CBS News outlined that Hurricane Delta led to more than 600,000 power outages being reported across Texas, Louisiana and Mississippi. The National Hurricane Center (NHC) described Hurricane Delta as “major”. On Monday, the NHC highlighted that Delta had turned into a post-tropical cyclone and noted that post-tropical remnants of Delta continued to weaken. The BSEE is the lead federal agency charged with improving safety and ensuring environmental protection related to the offshore energy industry, primarily oil and natural gas, on the U.S. Outer Continental Shelf. The organization works to promote safety, protect the environment and conserve resources offshore through vigorous regulatory oversight and enforcement, according to its website.
Hurricane Delta compounds oil pollution left by Hurricane Laura – photos – Hurricane Delta made landfall in Creole, Louisiana, on October 9 – 13 miles east of where Hurricane Laura struck 43 days before. It touched down in an area packed with oil and gas wells, pipelines, and rigs. An assessment of how much oil was spilled after Laura had not been made when Hurricane Delta created a new round of destruction along a similar track, from Port Arthur, Texas, to Baton Rouge. Delta, the 10th named storm to hit the United States in 2020, set a new record for the most storms to hit in a single Atlantic hurricane season. Gerry Bell, lead hurricane forecaster for NOAA’s Climate Prediction Center, told NOLA.com that it’s too early to say whether climate change is a factor in producing storms this year, but that it is definitely a factor in the potential effects of tropical storms and hurricanes that approach land. The day after Delta hit, I drove to Creole to document the storm’s aftermath. On nearly deserted roads, some still covered with standing water, I found a desolate landscape that in places reeked of spilled oil. While a few structures remained standing, they all seemed to have sustained damage. On October 12, I flew over Creole and the surrounding area on the western Louisiana coastline near the Texas border. The flight followed a similar path to one I took following Hurricane Laura. I noticed that some structures that withstood Laura’s winds of 150 mph and a 17 foot storm surge could not withstand Delta, with winds up to 100 mph and 9.3 foot storm surge. There were fresh oil slicks and sheen in the wetlands, though not as much as what I saw after Laura. Margie Vicknair-Pray, spokesperson for the Delta Chapter of the Sierra Club expressed concern about migratory birds after seeing my photos of oil in the marsh after Laura and Delta. “Tens of thousands of birds can pass through the coastal marshes each day,” she said. “Bird enthusiasts follow the migrations of songbirds, shore birds and arctic summer residents like many ducks and geese who find their way to south Louisiana expecting rest and a meal before the exhausting trip across the Gulf. What awaits them is oil strewn marshes and death,” she said. With over 1,400 active oil wells in the storm’s path, it is no surprise that Louisiana regulators in the Louisiana Department of Natural Resources (DNR) and the Department of Environmental Quality (LDEQ) were still dealing with issues from Hurricane Laura when Delta hit. Also in both storms path were dozens of offshore oil platforms, pipelines, the LNG plant in Cameron Parish and petrochemical plants and refineries in the Lake Charles area.
Delta causes outages, flaring among industry – Heavy industry in Southeast Texas is still dealing with the aftermath of Hurricane Delta after the storm briefly knocked out units at two major refiners and caused flaring at plants across the area. Winds from Delta caused power outages across southern Jefferson County on Friday that disrupted production at the Total Petrochemicals and Motiva Enterprises refineries in Port Arthur. Bloomberg reported that the Motiva refinery lost power to “several key production units,” but the company did not return requests for comment. Motiva’s Port Arthur refinery is the largest in North America and is capable of producing more than 600,000 barrels of refined product a day. Motiva had not submitted an air event report to the Texas Commission on Environmental Quality for the outage or any resulting air emissions. Total also had an outage at its refinery and a storage facility that caused it to slow its production and activate flares for 12 hours. In its report to TCEQ, the company said it was an external power interruption caused by Delta, and the Total refinery began the restart process after safely securing equipment. Total initially reported an estimated 14,737 pounds of sulfur dioxide and more than 550 pounds of volatile organic compounds were released in the event, along with thousands of pounds of other compounds. It also reported a flare with 100% opacity at the Cray Valley Beaumont location on Interstate 10 operated by Total. Brian McGovern, a spokesman with TCEQ, said that 100% opacity is reported when a flare emits smoke and vapors through which light can’t be detected by instrumentation or an observer. While Louisiana refiners took the brunt of the production disruption with 951,000 of 3.4 million barrels per day of refining capacity offline, according to Robert Yawger with Mizuho securities, Texas is experiencing similar issues. “Texas is looking at 116,000 of 5.905 million (barrels per day) of crude oil production offline,” he wrote in a Monday report. “Unfortunately, Gulf of Mexico crude oil production is likely to return to normal levels faster than refiners will return to normal.” With production delayed at refineries, companies will likely have to find a place to stash those barrels for the time being.
Under Great Lakes, group may have found evidence of Ice Age culture – A team of nonscientists may have inadvertently confirmed the most important finding in Great Lakes archaeology in at least a decade.The group, made up mostly of Native American tribal citizens, utilized a remote-operated underwater vehicle in the Straits of Mackinac to take a look at Enbridge’s Line 5 oil and natural gas pipelines on the lake bottom. But among the things they found were stones they say appear arranged in circular and linear patterns on the lake floor.If that was done by the hands of humans, it occurred when the Straits area, which divides Michigan’s peninsulas, was last above water – near the end of the last Ice Age, about 10,000 years ago.”We didn’t expect to find this – it was really just amazing,” said Andrea Pierce, a 56-year-old Ypsilanti resident and citizen of the Little Traverse Bay Bands of Odawa Indians, who was one of four women who drove the project to inspect the Straits bottom.A side-scan sonar image of the Straits of Mackinac lake bottom, taken in late August or early September 2020 by Busch Marine Inc. on behalf of Terri Wilkerson and others, shows what appears to be stones in at least a half-circle, visible in the orange and yellow band on the left, about halfway down. Side-scan sonar uses ultra-sonic waves bounced along a lake bottom to detect items on the sea floor. The group behind the Straits exploration believe this is evidence of rocks intentionally placed there by a culture at a time when the area would have been above-water — around the end of the Ice Age some 10,000 years ago. The finding seems to correlate with a University of Michigan archaeologist’s 2009 discovery of similar stone formations under water in Lake Huron, near Alpena, Michigan, also believed to be from an ancient, Ice Age-era culture. That professor, John O’Shea, told state officials in February that a consultant, hired by Enbridge to explore the area of its proposed Straits tunnel pipeline project, relayed to O’Shea that he had seen similar rock formations in the Straits.”The technician assigned to the job was told only to consider shipwrecks,” O’Shea wrote in a Feb. 12, 2020, letter to deputy state historic preservation officer Martha MacFarlane-Faes. “When the technician noticed linear stone alignments of the type documented in Lake Huron, he was told to ignore them. When he asked permission to consult with me about their potential cultural origin, his request was again denied. He was subsequently removed from the project and was not allowed to see the final report.”
Possible Ice Age artifacts ignored by Line 5 tunnel survey, archeologist says – – A University of Michigan archeology professor says an Enbridge subcontractor was directed to ignore possible prehistoric cultural artifacts in the Straits of Mackinac and was then removed from a Line 5 tunnel site assessment project after asking to consult with experts.”This entire story is very disturbing,” wrote archeologist John O’Shea in a February letter to officials in Michigan’s State Historic Preservation Office.The revelation comes as a group of northern Michigan tribal members say they’ve recently discovered possible evidence of underwater Ice Age artifacts in the area where Enbridge is seeking permits to build a tunnel for its oil pipeline.O’Shea, who co-authored a 2009 paper in the National Academy of Sciences documenting evidence of prehistoric hunting grounds under Lake Huron, has been trying to alert state officials for much of the year about a conversation he had with an Enbridge subcontractor worried over apparent disregard for submerged artifacts in tunnel survey work.O’Shea said a colleague sub-contracted by the Florida firm SEARCH, Inc. approached him at a conference in January to express concern about inadequate materials and a limited scope of work he was given for a cultural resources assessment of the Straits of Mackinac in connection with the tunnel project.His colleague, which O’Shea declined to name, had seen rock formations in underwater imagery similar to those discovered along the Alpena-Amberly Ridge – a prehistoric caribou hunting corridor connecting Ontario to northeast Michigan that’s now under Lake Huron.The subcontractor asked to explore the imagery further but was told to only assess shipwrecks in the straits, O’Shea says.”When the technician noticed linear stone alignments of the type documented in Lake Huron, he was told to ignore them,” O’Shea wrote in a Feb. 12 letter to deputy state historic preservation officer Martha MacFarlane-Faes.”When he asked permission to consult with me about their potential cultural origin his request again was denied. He was subsequently removed from the project and was not allowed to see the final report.” Enbridge denies any knowledge of the potential artifacts.
Enbridge completes 12-mile North Dakota stretch of Line 3 – Enbridge Energy officials said Wednesday that they have completed a small section of its Line 3 crude oil pipeline replacement project in North Dakota, leaving only the Minnesota stretch that has been challenged by state officials and others. Line 3 starts in Alberta and clips a corner of North Dakota before crossing northern Minnesota en route to Enbridge’s terminal in Superior, Wisconsin. More than 400 construction workers started on the 12-mile North Dakota project in August, the company said in a release. The Calgary, Alberta-based company has also completed the Canadian and Wisconsin portions of the pipeline. Plans to complete the 337-mile line in Minnesota have been approved by the the independent Public Utilities Commission but is facing its third appeal from the state Commerce Department An administrative law judge is due to issue a report Friday that will inform the Minnesota Pollution Control Agency as it decides on water quality permits for the project. The new line is popular among Minnesota Republicans who control the Senate and construction unions that have previously backed Democratic Gov. Tim Walz. Environmental and tribal groups oppose the project, citing climate change and spill risks. Enbridge is replacing the line that was built in the 1960s.
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