Sunday, October 18, 2020

smallest early October natural gas inventory build​ in 13 years; largest distillates inventory draw in 17 years, etal

smallest early October addition to natural gas inventories​ in 13 years; distillates production at a 3 year low leads to largest inventory draw in 17 years; September OPEC report shows all members in compliance, inconsequential ​global ​oil shortfall..

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 a​fter 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...

meanwhile, 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 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 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 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....

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...

September 2020 OPEC crude output via secondary sources

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....

April 13th 2020 OPEC   emergency cuts

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 a​ny​ 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.... 

September 2020 OPEC report global oil supply

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...   

September 2020 OPEC report global oil demand

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 estimat​ing 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 a​n 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, 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, 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 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 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...    

October 16 2020 rig count summary

there was somewhat more activity this week than recently, but because 6 of this week's rig addition​s​ were vertical, they ​typically wouldn't be included in the second table 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 WarningLaw360 – 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 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.

Good Times Bad Times - RBN's Outlook for Oil, Gas, and NGL Supply, Demand, And Prices | RBN Energy - Six months on from the height of the crude oil price rout of April 2020 and the unprecedented market convulsions that followed, energy markets appear to be settling into a state of hyper-uncertainty amidst the ongoing pandemic. Crude oil prices have been downright equanimous, stabilizing near $40/bbl in recent months. Volatility has reigned in the gas market, but it has thus far managed to avoid a major collapse, and the NGLs market has dodged a complete derailment from norms, if barely. The relative calm provides the perfect opportunity to assess how COVID-era energy markets are operating and what lies ahead — which is what we’ll be doing next week at RBN’s Virtual School of Energy. There’s a new order taking shape, and we’re rolling out RBN’s freshly updated outlooks for U.S. crude oil, natural gas and NGL markets. As always, we’ll pull back the curtain on the fundamental analysis and models behind our forecasts, so you can understand how we arrived at our answers, and gain the skills and tools to adjust the assumptions as markets evolve. As you’ve gathered by now, today’s blog is an unabashed advertorial for our virtual conference, but read on if you’d like to hear more about the underlying premise behind our latest outlook. The last time we held our School of Energy online was in April — pretty much in the middle of the COVID meltdown.    Crude prices dropped below $20/bbl that week, propane prices were up by a dime a gallon, gas was bouncing up and down 5-10% each day, and the market was hard-pressed to know what would happen in the next five days, much less six months or a year.  In some ways, not much has changed since then; COVID is still with us, the toll in human lives has been horrendous, big pieces of the economy are still shut down, air travel is still comatose, and conferences are still virtual. The market has also since weathered a wipeout in LNG exports. What has changed, though, is that energy markets, like the rest of the world, have learned to adapt to life in a pandemic. So has RBN’s framework for understanding how energy markets are behaving. Ever since the collapse of OPEC+ and COVID struck, the RBN team has been retooling our production, infrastructure, and supply/demand models to reflect the new world order. Now that the market has gotten a breather from the rapid-fire punches of early 2020 and is operating somewhat more rationally, it’s a good time to assess what the recovery will look like longer term, in the upcoming months and years. That is what our Fall Virtual School of Energy is all about. Before we get to the highlights of our findings, here’s a little bit about the format. While this will be our 14th School of Energy, it’s our third time going virtual, and what that means is that you’ll not only be able to attend the conference online in real time on October 20-21, asking questions as we go, but after the conference, all the materials will be available for replay, in whatever order you choose. So you can view the modules you want during the online sessions and go back to look at any other modules after the fact. That way, you can view the sessions that are of most interest to you RIGHT NOW! And it’s not too late to sign up. You can register, here.

US oil, gas rig count up by 13 to 336 on week, resuming double-digit leap: Enverus — The US oil and gas rig count rose by 13 to 336 on the week, rig data provider Enverus said Oct. 15, as activity ticked up on the heels of what experts say may be a final push to complete projects in 2020 with remaining capital budgets. Stay up to date with the latest commodity content. Sign up for our free daily Commodities Bulletin. Sign Up Oil rigs accounted for the bulk of increases, up 10 to 238, but natural gas rigs were also up by three to 98. "These modest week-on-week gains were expected," analyst Matthew Andre of S&P Global Platts Analytics said. "Relative to what we've seen for growth it's pretty good. I'm not sure we'll see [double-digit] rig gains every week for the rest of the year." Horizontal activity, a better indicator of shale activity since it focus on players drilling larger, more productive wells, has climbed recently and is now at 265, up by seven on the week – far past its long rangebound period in the 230s-240s from June through most of September. Since then, the horizontal rig count has ticked up steadily. "This relatively widespread recent stability increases our confidence that the horizontal activity trough is now indeed behind us, and we continue to expect to see further modest gains into year-end 2020," Tudor Pickering Holt said in its daily investor note Oct. 12. This past week is the highest the horizontal rig count has been since June, although it's still just about a third of its recent peak of 734 in late February 2020. Most domestic basins saw multiple rig gains on the week and none lost rigs. Biggest were the Permian Basin and the Marcellus Shale, which each increased by four rigs. That resulted in totals of 143 rigs in the Permian, sited in West Texas/New Mexico, and 29 in the Marcellus, a largely gas-prone basin mostly in Pennsylvania and neighboring states. In addition, the Eagle Ford Shale of South Texas was up by three to 21, a volume not seen in the basin since mid-May. Also, the Bakken Shale of North Dakota/Montana and DJ Basin of Colorado were each up by two rigs, for respective totals of 13 and six. The SCOOP/STACK play in Oklahoma and Utica Shale of Ohio held steady at 12 and seven rigs respectively. The gassy Haynesville Shale of East Texas/Northwest Louisiana was up one to 39, the most activity posted in that play since late March. All things considered, the relatively buoyant rig activity of the last week comes a week before Q3 earnings begin, which typically provides a glimpse into activity outlooks during the following few months and the rest of the year. This year's Q3 outlooks will be especially scrutinized since activity is sluggish from two full quarters of activity tamped down by the coronavirus pandemic, as operators slashed drilling rigs and their 2020 capital budgets beginning in March. The oil and gas rig count, at its July trough of 279, was down more than 65% from early March.

Is U.S. Shale Finally Bouncing Back? - - As the oil price dropped through the first and second quarters of this year, oil companies closed in wells and laid off drilling and fracking crews. Activity bottomed in late May and has mounted a steady recovery in the months since. Rig count increases have been moderate, rising from low of 251 in May to 269 as of the 5thof October. What has been more spectacular is the increase in the deployment of frac crews as operators have allocated capex to bring Drilled by Uncompleted, (DUCs) out of inventory and into production. The graph above shows the true impact of this trend, with frac crews more than doubling since May’s lows.  The question before us now, is what can we expect through the rest of the year and on into 2021? In a recent OilPrice article I documented a relevant industry consolidation move by Schlumberger and Liberty Oilfield Services,   I’ll let you follow the link provided for relevant details on the joint venture between these two companies. For a quick reference this creates the largest player in U.S. shale fracking with an estimated twenty percent of the available hydraulic horsepower, HHP in the industry today. In this article we are going to concentrate on some broader industry trends and I will have an updated recommendation for shares of LBRT as well. I was cautious on LBRT immediately after this merger as the share rocketed 40% higher in a single day. That move wasn’t something I wanted to chase. As the chart below indicates this caution was well advised as the stock sold off over the next few weeks, before regaining most of its early value. Over the last week the market action has taken the general oilfield lower, and now we think that LBRT represents a compelling value at current prices.

US Oil Production Has Already Passed Its Peak, Occidental (OXY) Says - America’s oil production will never again reach the record 13 million barrels a day set earlier this year, just before the pandemic devastated global demand, according to Occidental Petroleum Corp.“It’s just going to be too difficult to replace the 2 million barrels a day of production that we’ve lost, and then to further grow beyond that,” Chief Executive Officer Vicki Hollub said Wednesday at the Energy Intelligence Forum. “Over the next three to four years there’s going to be moderate restoration of production, but not at high growth.”Occidental is one of the biggest producers in the U.S. shale industry, which added wells at such a rate prior to the spread of Covid-19 that the country became the world’s top crude producer, overtaking Saudi Arabia and Russia, ushering in an era that President Donald Trump called “American energy dominance.”Shale’s debt-fueled expansion came to a juddering halt due to lower gasoline demand and oil prices, but also because of Wall Street’s increasing reluctance to fund growth at any cost. Shale operators are increasingly prioritizing cash flow and returns to investors over production growth.Occidental, which vies with Chevron Corp. to be the biggest producer in the Permian Basin, has been forced to throttle back capital spending, lower growth targets and cut its dividend in a bid to save cash during the downturn. Its finances were already severely challenged by the debt taken on through its $37 billion purchase of rival Anadarko Petroleum Corp. last year.Hollub said global consumption stands at about 94 billion barrels a day, and it will take a Covid-19 vaccine before it returns to 100 million barrels. Due to cutbacks around the world, supply and demand for oil will likely balance again by the end of 2021, she said. Unlike some of her European peers, Hollub sees strong long-term demand for oil. “I expect we’ll get to peak supply before we get to peak demand,” she said.

With Bankruptcies Mounting, Faltering Oil and Gas Firms Are Leaving a Multi-billion Dollar Cleanup Bill to the Public | DeSmog - Amid a record wave of bankruptcies, the U.S. oil and gas industry is on the verge of defaulting on billions of dollars in environmental cleanup obligations. Even the largest companies in the industry appear to have few plans to properly clean up and plug oil and gas wells after the wells stop producing — despite being legally required to do so. While the bankruptcy process could be an opportunity to hold accountable either these firms, or the firms acquiring the assets via bankruptcy, it instead has offered more opportunities for companies to walk away from cleanup responsibilities — while often rewarding the same executives who bankrupted them. The results may be publicly funded cleanups of the millions of oil and gas wells that these companies have left behind. In a new report, Carbon Tracker, an independent climate-focused financial think tank, has estimated the costs to plug the 2.6 million documented onshore wells in the U.S. at $280 billion. This estimate does not include the costs to address an estimated 1.2 million undocumented wells.Greg Rogers, a former Big Oil advisor, and co-author of a previous Carbon Tracker report on the likely costs of properly shutting down shale wells, suggested to DeSmog that oil and gas companies have factored walking away from their cleanup responsibilities into their business planning.“The plan is that these costs will be transferred, these obligations will be transferred to the state at some point,” Rogers told DeSmog, “Why would a company want to go out and spend hundreds of millions of dollars plugging all of these wells when it could instead pay its executives?”Despite federal and state laws requiring oil and gas companies to clean up and properly cap and abandon wells, there is overwhelming evidence that this is not happening.  One major reason why is that often, regulators lack the power to enforce compliance once the permits to drill the wells have been issued.  The best method to guarantee the wells are properly capped and abandoned is for regulators to require the companies to put up the money to do that before the well is drilled. This is most often done via a process known as surety bonding. However, if the amount of money required for bonding is small enough, there is no incentive for companies to spend the additional money to properly cap the wells once the wells are no longer producing oil or gas. From a business standpoint, it is smarter for the well owner to walk away from the obligations at that point.  The new report from Carbon Tracker also notes that current bonding monies allocated for well cleanup are equal to roughly only 1 percent of that total expected cost.

Oil, gas deal tracker: COVID-19 fallout stifled Q3'20 M&A -The pace of oil and gas M&A deal-making in the third quarter of 2020 remained well below year-ago levels as the industry reckoned with COVID-19's negative impacts on consumer demand and company balance sheets, according to S&P Global Market Intelligence data. The sector announced 25 fewer whole-company and minority-stake deals than in the third quarter of 2019 — 88 deals compared to 113. In the same period, the combined value of deals rose by just over $100 million to $27.14 billion. The number of announced asset transactions, meanwhile, fell from 134 to 100 and their aggregate value declined $1.09 billion to $14.54 billion. The quarter saw five billion-dollar-plus transactions, with Chevron Corp. and Noble Energy Inc.'s $13.76 billion combination topping the list of biggest whole-company and minority-stake deals in 2020 so far and Berkshire Hathaway Energy's $9.75 billion purchase of Dominion Energy Inc.'s gas transmission and storage assets taking the first spot among asset-level deals. During the period, Devon Energy Corp. also announced a $5.79 billion acquisition of fellow independent driller WPX Energy Inc. and The Blackstone Group Inc. sold its roughly 40% stake in Cheniere Energy Partners LP to Brookfield Infrastructure Partners LP for $3.48 billion. Smaller transactions included Southwestern Energy Co.'s $893.5 million purchase of Marcellus and Utica Shale driller Montage Resources Corp. and gas liquids producer Painted Pony Energy Ltd.'s $377.3 million merger with Canadian Natural Resources Ltd. In September, Schlumberger Ltd. agreed to merge its integrated completions services business with Liberty Oilfield Services Inc.'s fracturing and engineering operations for $427.8 million. According to 55% of oil and gas firms polled for the Kansas City Federal Reserve's third-quarter Energy Survey, constrained profitability will drive a massive increase in mergers and acquisitions through 2021. Momentum from upstream combinations is not expected to trickle down to the pipeline sector, however. Replicating that activity farther downstream presents "a lot more headwinds than tailwinds," according to Raymond James & Associates 

Exxon's Latest Business Plan -- Drill, Baby, Drill - While many of the world’s largest oil companies are rushing ahead with plans to slash carbon emissions and transition to renewable energy, ExxonMobil is charting its own course, one that will help heat the Earth’s environment to the point where human beings will no longer be able to survive. One would think a business corporation would want to keep its customers alive but Exxon sees things differently. Scientific American, citing a report by E&E News, says Exxon’s latest business plan calls for a massive increase in drilling operations, all in the name of profits. Bloomberg did some digging and found the company’s internal projections suggest the new strategy will increase Exxon’s carbon emissions from 122 million metric tons in 2017 to 143 million metric tons by 2025. To put that in perspective, that’s the equivalent of 5 new coal powered generating facilities every year for the next 5 years. But that’s not the half of it. Those projections are for the company’s operations, not for the carbon released when all that lovely new oil is burned or turned into plastics, known in the industry as Scope 3 emissions.  But wait, Exxon says. The emissions would be much higher if the company was not taking bold and decisive action to reduce methane leaks and lower emissions from its extraction technologies. Casey Norton, an Exxon spokesperson, challenged Bloomberg’s description of the numbers, saying they represented a projection of future greenhouse gas levels rather than a plan to increase emissions. “The emissions projection you cite is an early assessment that does not include additional mitigation and abatement measures that would have been considered as the next step in the process,” he said. “The same planning document illustrates how we have been successful in mitigating emissions in the past. As demand returns and capital investments resume, our growth plans will continue to include meaningful emission mitigation efforts.” Exxon is actually begging political leaders to impose a carbon tax. That may sound really progressive but it’s not. As Bloomberg points out in an e-mail, even with a carbon price of $40 a ton, average global temperatures will soar by 3º C or more, making the Earth inhospitable to most human life. But there’s a kicker. In exchange for accepting a carbon tax, it wants all regulations governing its industry dismantled. “For more than a decade, ExxonMobil has supported an economy-wide price on CO₂ emissions as an efficient policy mechanism to address greenhouse gas emissions,” Exxon said in a statement. “An effective carbon policy should replace the patchwork of literally thousands of regulations, laws and mandates today that have the effect of putting a price on carbon in a costly, inefficient way.”

Goldman says a Biden win could be a 'positive catalyst' for oil prices - Despite a grim demand outlook for energy as the coronavirus pandemic continues to weigh down the global economy, Goldman Sachs remains bullish on both oil and gas prices — regardless of the U.S. presidential election outcome in November. "We do not expect the upcoming U.S. elections to derail our bullish forecasts for oil and gas prices, with a Blue Wave likely to be in fact a positive catalyst," the bank's commodities team wrote in a research note Sunday. "Headwinds to U.S. oil and gas production would rise further under a Joe Biden administration, even if the candidate has struck a centrist tone," the note said. Goldman sees improved demand in 2021 and tighter supply for both gas and shale oil superseding election results, though a Biden administration could provide a further boost to oil prices by making production — especially for shale — more expensive and more regulated. If elected, Biden seeks to achieve a carbon pollution-free energy sector by 2035, and analysts expect his administration to impose regulations that would increase shale production costs with things like taxes and methane restrictions, which the Donald Trump administration had eased. Goldman estimates such taxes could increase costs by as much as $5 per barrel. And expected dollar weakness under Biden also provides upside risk to prices. VIDEO01:27 Oil prices to stay in $40-$45 range for the rest of 2020: Analyst While Biden has said that fracking would not be "on the chopping block," a Democratic administration could also move to reduce the scope for shale exploration with restrictions on federal land drilling and approvals for pipelines. The former vice president is currently leading incumbent Trump by double digits in major national polls. If Trump is re-elected, while pro-oil and gas policies would remain in place, "its impact would likely remain modest at best," Goldman's analysts wrote, "given the more powerful shift in investor focus to incorporate ESG metrics and the associated corporate

What the Frack? Why Waste Political Capital on a Pyrrhic Victory? - These days American politics are a little like Russian nesting dolls—there are stories, within stories, within stories. With just 22 days, 07 hours, and 30 minutes left until the November elections and Biden’s rising poll numbers, I’ve begun thinking in earnest about the chances of getting his $2 trillion[i] climate plan—or a reasonable facsimile— through Congress and back on the presidential desk for his signature. How Biden and progressive climate activists deal with fracking in the coming months could largely determine the possibility of putting the nation squarely on the path to long-term sustainability. I fear that too great a focus on fracking bans outside of federal lands—which is the current Biden position—could cancel the possibility of putting in place the government policies needed to decarbonize the economy in a timely fashion.As I will explain in a moment, the way forward need not force a binary vote on fracking. How is this possible? By doing what governments have always done best—kicking the can down the road—at least on this one issue. It may not be optimum, but it is likely to happen in a much shorter time than waiting for political forces finally to resolve.First off, to have any chance of that happening depends upon the Democrats keeping the House and flipping the Senate. All are well within the realm of possibilities. Should the Senate remain in the hands of Republicans, the nation would be looking at another two to four years of virtual gridlock and not just in the area of climate policy.Ill feelings run deep these days, and any pretense of bipartisan cooperation has been cast aside.Absent a deus ex machina or call to war against a common foreign enemy, it is difficult to conceive of any scenario in which a Republican Senate and a Democratic House and administration would work together to put an aggressive climate defense plan into motion. We already know what it means for the environment with a Democratic House, a Republican Senate, and Trump in the White House. It hurts me to write that. However, as President Trump likes to say–it is what it is.

US-Venezuela dispute delays oil storage transfer -- Eni's plan to drain a Venezuelan floating oil storage vessel considered a potential environmental risk has been delayed for weeks because of concerns over US sanctions on the Opec country.The Venezuela-flagged Nabarima floating storage and offloading unit (FSO) had been listing in August, with flooding reported by workers on and off the vessel. In early September, Eni said the vessel had been stabilized and a water leak resolved.The FSO, which is carrying at capacity of up to 1.3mn bl of crude, has been moored at the offshore Corocoro field in Venezuela's Gulf of Paria for 10 years.The field belongs to PetroSucre, a joint venture operated by Venezuelan state-owned PdV. Eni holds a minority 26pc stake.Caracas has denied any problems with the vessel. In a 5 September statement, PdV-controlled PetroSucre said the vessel posed no environmental risk and deemed the information about its lack of structural integrity as "fake news" aimed at justifying US sanctions. Since then, neither PdV nor the Venezuelan government has commented. It is not clear if a ship-to-ship transfer would require a specific OFAC waiver, or explicit assurances that the operation, carried out on safety and environmental grounds, would not violate the US sanctions regime. Nor is it clear if Eni would retain title to the oil to be able to use or sell it, and how PetroSucre would be paid. Venezuela's wary neighbor, Trinidad and Tobago, says it is waiting for Caracas to allow its inspectors on to the vessel.The inspection has been delayed "until a late-October date" that has yet to be agreed on with Caracas, the energy ministry told Argus yesterday.Trinidad had hoped a government team could have inspected the Nabarimabefore the end of September, but is still awaiting Venezuelan permission, the ministry said.The inspection is intended to ensure that Trinidad's waters are not in danger of a major oil spill, the ministry said.

Idled Venezuelan floating oil facility under repairs amid environmental concerns - source (Reuters) - An idled floating oil facility off Venezuela’s eastern coast is undergoing repairs, according to a person familiar with the matter, as images showing the crude-laden vessel at an incline have raised concerns about possible environmental hazards. The Nabarima floating storage and offloading (FSO) facility is operated by the Petrosucre joint venture between Venezuelan state oil company Petroleos de Venezuela [PDVSA.UL] and Italy's Eni ENI.MI. Petrosucre suspended output shortly after Washington sanctioned PDVSA in January 2019. About 1.3 million barrels of Corocoro crude have remained stuck on the vessel, which is located in the Paria Gulf between Venezuela and Trinidad and Tobago. The sanctions have deprived Petrosucre of its former main crude buyer, PDVSA’s U.S.-based refining subsidiary Citgo Petroleum Corp [PDVSAC.UL]. Gary Aboud, the corporate secretary of Trinidadian environmental group Fishermen and Friends of the Sea, said he was concerned about a potential oil spill, which would devastate the livelihoods of the country’s fishermen. “If this thing flips we will all pay the consequences for decades to come,” Aboud said in a Friday telephone interview. “This should be red alert.” A crew is currently replacing the vessel’s valves, according to a person familiar with the matter who spoke on the condition of anonymity. The source said the vessel is leaning to one side in order to facilitate the repairs.

Hundreds of liters of oil poured into the river in the Krasnoyarsk Territory - Hundreds of liters of oil products poured from the barge into the Angara in the Kezhemsky district of the Krasnoyarsk Territory. This is reported on website regional Ministry of Emergency Situations.The local administration has declared a state of emergency from 9 October. According to preliminary data, about 500 liters of diesel fuel got into the river.  “There are no oil stains, the consequences have been eliminated. A group of representatives of the Investigative Committee, OMVD, UBEP, administration plus three rescuers left for the scene, ” RIA News in the administration of Kezhemsky district.According to the Ministry of Emergency Situations, an emergency regime was also introduced on the territory of the Bolshemurtinsky District of the Yukseevsky Village Council in connection with an oil spill on the territory of the Sever enterprise. In early October, it became known about the appearance of a lot of dead fish and sea animals on the shore of Khalaktyrsky beach in Kamchatka and in three other bays. Phenol and oil products were detected in three areas of the Avacha Bay water area. Rosprirodnadzor did not rule out that the incident may have man-made reasons. The authorities in the region are considering the possibility of leakage of toxic substances or the release of toxins of biological origin.

Large oil slick discovered on Russias Volga River - The Volga River slick is at least the second oil spill reported in Russia this week. Vladimir Smirnov / TASS An oil slick the size of a hockey rink has been discovered on the Volga River north of Moscow, authorities said Wednesday, the latest instance of pollution to hit Russia’s waterways this year. The 5,000 square meter layer of fuel was spotted near the port of Kimry some 150 kilometers north of the Russian capital, Moscow transport investigators said in a statement. “The discharge of petrochemical products from a vessel currently being identified has presumably occurred,” it said. On the opposite end of the Volga River more than 1,000 kilometers to the south, residents of the city of Volgograd were reported to have found hundreds of dead catfish washed up on the shore of a local reservoir. They linked it to poachers discarding small fish. The Volga River slick is at least the second oil spill reported this week and comes less than five months after a massive diesel fuel-tank leak in the Arctic city of Norilsk triggered by melting permafrost. The oil spill discovery also comes amid continuing questions over what caused a mass die-off of sea creatures, including seals, octopuses, starfish and sea urchins, in the Far East Kamchatka region last month. Scientists said the event, increasingly believed to be caused by toxins from microalgae known as algal bloom, wiped out up to 95% of seabed life. The governor of the Kamchatka region said this week that scientists and witnesses reported seeing more dead marine animals washing up to the shore south of the initial discovery. He suggested the mass die-off was linked to climate change and other polluting effects on the Pacific Ocean. Greenpeace Russia said Wednesday that “none of the compounds found in water samples could have caused the serious consequences we’re observing.” “This means that both man-made and natural theories remain in the search for the cause of the environmental disaster,” the organization said.

Russia Expanding Energy Influence in Africa - Part of Russia’s engagement with Africa is military. The Russian army and Russian private military contractors linked to the Kremlin have expanded their global military footprint in Africa, seeking basing rights in a half dozen countries and inking military cooperation agreements with 28 African governments, according to an analysis by the Institute for the Study of War. U.S. officials estimate that around 400 Russian mercenaries operating in the Central African Republic (CAR), and Moscow recently delivered military equipment to support counterinsurgency operations in northern Mozambique. Russia is the largest arms exporter to Africa, accounting for 39 percent of arms transfers to the region in 2013-2017.The fact that the Russian ambassador to Mali, Igor Gromyko, was one of the first officials to be received by the Junta is thus unsurprising. Local media source reports that the military leaders of the coup had just spent a year training in Russia. While this kind of activity is not extraordinary, with countries such as the U.S. training armies from more than 20 African countries and shaping its military leaders, it indicates that Russia considers its security presence in Africa necessary. The coup is a blow to French diplomacy, as Paris had heavily invested in Mali security through a tight alliance with former Mali President, Ibrahim Boubacar Keita. Keita’s time in office, which began in 2013 after a coup in 2012 ousted Amadou Toumani Toure, coincided with a French peacekeeping mission, and the Kremlin may seek to supplant France in West African countries whereParis has a stronghold and influence.  Russia could also leverage the Mali coup to secure economic deals while bolstering its geopolitical standing in West Africa. According to FPRI, Russian nuclear energy giant Rosatom, which directly competeswith its French counterpart for contracts in the Sahel, could benefit from favorable relations with Mali’s new political authorities. Nordgold, a Russian gold company that has investments in Guinea and Burkina Faso, could also expand its extraction initiatives in Mali’s gold reserves.However, Professor Irina Filatova, Research Professor at the Higher School of Economics in Moscow, who specializes in Russian Foreign Policy, insists on caution about assuming Russian interference in Malian politics:  “It’s difficult for me to judge how reliable this information is because Moscow has said nothing about it.”

Methane emissions up in 2020 amid turbulent year for oil and gas - Methane emissions have jumped so far this year even as oil and gas production has been hit hard by the coronavirus pandemic. The report from Kayrros, which analyzes methane leaks through satellite imagery, found visible methane emissions jumped 32 percent in the first eight months of 2020 when compared with the same period in 2019. The increase in methane is concerning because of its heat trapping powers — the gas is more than 80 times more potent than carbon emissions over a 20-year period. “Despite much talk of climate action by energy industry stakeholders, global methane emissions continue to increase steeply,” Antoine Rostand, president of Kayrros, said in a release. The U.S., Russia, Algeria, Turkmenistan, Iran and Iraq were the largest contributors according to the company’s analysis. Though the U.S. is a leading contributor, the Environmental Protection Agency (EPA) in August rescinded its regulations on methane emissions. “Regulatory burdens put into place by the Obama-Biden Administration fell heavily on small and medium-sized energy businesses," EPA Administrator Andrew Wheeler said at the time, adding that doing so would give oil and gas companies “flexibility to satisfy leak-control requirements by complying with equivalent state rules.” Methane figures grew even higher in other oil and gas hot spots such as Algeria, Russia and Turkmenistan, where methane emissions jumped by more than 40 percent. The high methane levels come even as many companies agreed to scale back the production of oil as prices for the commodity plummeted amid a trade war and a halt on human activity due to the spread of the virus. Though greenhouse gas emissions, in general, dropped in the early days of the pandemic, scientists say they have nearly returned to pre-March levels.

MMEA- Oil spill detected in Tanjung Tuan waters up to — Contamination of seawater due to an oil spill was detected about three nautical miles off Tanjung Tuan here up to Teluk Kemang, Negri Sembilan, yesterday, according to the Melaka and Negri Sembilan Malaysian Maritime Enforcement Agency (MMEA). Its director, Maritime Captain Haris Fadzillah Abdullah said the incident was detected by a Maritime patrol boat while patrolling the waters of Tanjung Tuan at about 11am yesterday. “The oil spill was detected in the waters of Tanjung Tuan about 1.3 nautical miles towards Pulau Perjudi and initial investigations found that the contamination was up to the waters of Teluk Kemang. “However, it did not appear that ships were dumping oil into the sea according to monitoring and patrolling by Maritime personnel around the scene,” he said in a statement here today. He said the Melaka Department of Environment (DOE), Negri Sembilan DOE and Teluk Kemang Fire Station had been informed of the incident, besides taking of the oil spill samples and cleaning up works being carried out. Commenting further, Haris Fadzillah said they have yet to confirm whether it was ships or other parties involved in the pollution and further investigations were ongoing. Meanwhile, he said monitoring, patrolling and enforcement operations to combat and prevent cross-border criminal activities in the waters of Melaka and Negri Sembilan would continue to be enhanced from time to time. The public could channel any criminal activities and emergencies at sea to the Maritime Operations Centre at 06-3876730 or 999 which operates 24 hours, he added. 

Negri oil spill suspected to be from passing vessel - Clearing of an oil slick that was swept ashore at Pantai Cermin here will commence full-scale today and work is expected to take at least a week to complete. Sources at the Negri Sembilan Department of Environment (DOE) said the contamination’s origin is yet to be ascertained although it is suspected to be from a passing vessel. It is learnt that the DOE is expected to carry out an assessment to determine if the oil spill had caused any damage to marine life in the affected area. The DOE also collected samples of the spill for testing. The Malaysian Maritime Enforcement Agency reported it had carried out patrols in the area but did not spot any vessel responsible for dumping oil products into the sea. The strong fumes from the oil slick extending over 2km between Tanjung Tuan and Teluk Kemang drew the attention of passers-by early on Monday before the authorities were alerted. The fine for polluting the environment will be raised 20 times to RM10 million under an amendment to the Environmental Quality Act 1974, Environment and Water Minister Datuk Seri Tuan Ibrahim Tuan Man said, after visiting the oil spill site yesterday The amendment is expected to be tabled for debate in the Dewan Rakyat next month. The current maximum fine for the same offence is RM500,000. “The jail term will also be lengthened under the proposed amendment,” Tuan Ibrahim said, adding that the case is being investigated under Section 27 of the Environmental Quality Act.

Lanka court imposes fine of USD 64,972 on Greek captain of fire-damaged oil tanker - A Sri Lankan high court on Wednesday ordered the Greek captain of an oil tanker, which carried crude oil from Kuwait to India and caught fire off the country''s eastern Ampara coast, to pay a fine of USD 64,972 after he pleaded guilty to the marine environment pollution charge. The Panamanian-registered New Diamond was carrying 270,000 metric tonnes of crude oil from Kuwait to India when a boiler explosion in its engine room caused fire on September 3. The Sri Lanka Navy with the help from the Indian Navy and coast guards doused the fire after three days. Two Sri Lankan naval ships, one Indian naval ship and three Indian coast guard vessels were deployed in the operations. Last week, Sri Lanka indicted the Greek captain for causing the oil spill under the country’s Marine Pollution Prevention Act. Captain Sterio Illias pleaded guilty to the marine environment pollution charge at the Colombo High Court. Accordingly, a fine of Sri Lankan Rs 12 million (USD 64,972) was levied, court officials said. He appeared before the court on September 28 for negligence and not putting in place safety measures to prevent fire on board. The captain was barred from leaving the country although no remand order was served on him in spite of a state request. The tanker had 23 crew members - 18 Filipinos and five Greeks. Twenty-two of its 23-member crew had been safely rescued off the tanker.

BP and Petronas Achieve First Gas from Oman Field  - BP reported Monday that it has begun production from the Ghazeer field in the Omani desert ahead of schedule. The Ghazeer start-up occurred less than three years after production began from another field in Oman’s Block 61: the Khazzan field, BP noted in a written statement. BP holds a 60-percent stake in Block 61, located in Oman’s remote interior. The company’s partners include Makarim Gas Development Limited (OQ) (30-percent interest) and PETRONAS (10 percent). According to BP, the Ghazeer field development incorporates major advances in efficiency and working practices. It added the project also features flaring reduction techniques similar to those developed in the U.S. onshore, reducing emissions during on-site well testing. The company stated that “green completions” sent hydrocarbons during testing to a production facility rather than flaring them. “When we introduced our plans to reinvent BP, we were clear that to deliver them, we have to perform as we transform,” commented BP CEO Bernard Looney. “There are few better examples of how we are doing just that than Ghazeer. This project has been delivered with capital discipline four months early, wells are being drilled in record times and, importantly, safety performance has been excellent.” With Ghazeer online, BP pointed out that Block 61’s production capacity should rise to 1.5 billion cubic feet of gas per day and more than 65,000 barrels per day of associated condensate. The firm also noted the block’s estimated recoverable gas resources amount to an estimated 10.5 trillion cubic feet.

Uptick in LNG demand this winter - LNG demand is expected to increase by 4 billion cubic metres (bcm) this winter and that’s led by growth in China, Japan, and South Asia. “LNG supply is expected to grow by 3 bcm led by the United States. And when we put together demand and supply forecast, we expect the LNG market to be slightly tighter than last winter by 1 bcm,” noted Refinitiv Representatives at the latest GECF Monthly Gas Lecture. However, there remained several risks to the forecasts, foremost of which are winter temperatures and coronavirus pandemic. The former was unusually warm last winter for the northern hemisphere, dampening LNG demand. In the case of the latter, the full-blown effect of Covid-19 is unclear particularly as it is currently worsening in many countries and levelling off in others. Held via videoconference on October 6 and entitled ‘Winter Outlook for Global LNG – Cautiously Optimistic’, company analysts  sifted through the demand and supply outlook and their relationship with market’s balance and pricing dynamics. Recognising the importance of scientifically drawn forecasts – a hallmark of the GECF and epitomised in its annual Global Gas Outlook 20050 –Secretary General Yury Sentyurin said: “In many ways, Covid-19 has highlighted the importance of data so we can map and understand the economic and social effects of pandemic-related measures. This belief in the supremacy of data to generate valuable insights can be found in the DNA of both the Forum and Refinitiv.” “The GECF data is distinguished, for it is based on our Member Countries’ primary sources of information. This is why we regularly share our data externally, such as in the Opec World Oil Outlook, at the IEA-IEF-Opec Symposiums on Energy Outlooks, and through our participation in JODI-Gas World Database, so the gas industry can grow and thrive.” The audience at the lecture series further heard that accurate planning for the period ahead depends on not just weather but myriad factors such as government policies that can often change the course of LNG demand and pricing. For instance, the team of lecturers shared that the story of LNG played out vastly differently last winter in Japan and South Korea, the world’s largest and third largest LNG buyers, respectively. In Japan, LNG import declined by about 4% due to the mildest winter on record in addition to an industrial demand that was hit by Covid-19 in Q1 of 2020. In contrast, South Korea saw an uptick of about 7% in LNG import due to the government policy of turning off coal-fired power plants between December and March to improve air quality; March alone witnessed the shuttering of 28 coal-fired power plants, stimulating gas for power demand. 

Turkey to revise upward estimate of Black Sea gas discovery - Turkey is preparing to revise upward its estimate of its natural gas discovery in the Black Sea, Bloomberg reported, citing sources with direct knowledge of the plans. The country is said to be preparing to update the amount as soon as this week after further exploration drilling is completed, Bloomberg said on Friday, citing the sources. The Turkish government is about to disclose a “sizable revision” to the initial estimate, they noted. Turkey in August announced its biggest natural gas discovery, a 320 billion-cubic-meter field in the Black Sea that President Recep Tayyip Erdoğan said is part of even bigger reserves and could come onstream as soon as 2023. “This reserve is actually part of a much bigger source. God willing, much more will come,” Erdoğan said. “There will be no stopping until we become a net exporter in energy.” Turkey currently imports nearly all of its energy needs, and the discovery is promised to help drive down its current account deficit. Energy and Natural Resources Minister Fatih Dönmez on several occasions said data suggested more natural gas would be found as drilling continues deeper under the seabed. A senior energy ministry official in September said that Turkey hopes to announce the new discovery in October. Earlier this month, Dönmez said that Turkey’s third drillship would also be deployed and begin exploration for natural resources in the Black Sea in the first months of 2021. “We hope to begin operations in the first months of next year, and with that, Kanuni will be working together with the Fatih drillship in the Black Sea,” Dönmez said. Kanuni will support the Fatih drillship, which found the 320 billion-cubic-meter natural gas field some 100 nautical miles north of the Turkish coast.

Libya May Double Oil Output Next Week -- Libya took a major step toward reviving its battered oil industry by reopening its biggest field, presenting a new headache for OPEC+ as the alliance of major producers tries to curb global supplies. The National Oil Corp., Libya’s state energy company, lifted force majeure on the western deposit of Sharara and instructed its operator to resume production, according to a statement on Sunday. The field will initially pump 40,000 barrels of crude a day, before reaching its capacity of almost 300,000 barrels next week, a person with knowledge of the situation said. That would double overall output in Libya to around 600,000 barrels daily, said the person, who asked not to be identified because they aren’t authorized to speak to media. Crude from Sharara has begun reaching storage tanks at the port of Zawiya, another person said. Sharara’s reopening follows a truce in Libya’s long-running civil war that’s already led to many oil fields and ports in the east starting up after an almost total shutdown since January. The NOC didn’t mention the nearby deposit of El Feel, or Elephant in Arabic. The 70,000-barrel-a-day field normally follows Sharara’s shutdowns and restarts because it relies on electricity from its bigger neighbor to operate. Libya is an OPEC+ member and home to Africa’s largest crude reserves. But it’s exempt from the group’s supply cuts, initiated in May as the coronavirus pandemic stifled economies and caused oil prices to tank. The alliance, led by Saudi Arabia and Russia, planned to ease the curbs by 2 millions barrels a day from the start of 2021. Yet with virus cases accelerating in many countries, the cartel faces a difficult decision at its next policy meeting on Nov. 30-Dec. 1: whether to stay the course or delay the increase in production. Benchmark Brent crude has more than doubled to around $42.25 a barrel since May, but it’s still down 36% this year. “The Libyan oil restart is gaining momentum faster than most people expected,” The likelihood of more Libyan exports is “an additional headwind for OPEC at a time when it is already grappling with softer than expected demand as the second wave of Covid-19 intensifies.” JPMorgan Chase & Co. forecasts that production will rise to 1 million barrels daily by March.

J.P. Morgan sees Saudi Arabia offering deeper oil cuts --A worsening global oil demand outlook will prompt OPEC to reverse a planned easing of oil cuts in 2021 with Saudi Arabia offering deeper cuts below its current quota, J.P. Morgan said in a research note.“Against relatively bearish investor sentiment on the near-term demand outlook as COVID-19 potentially accelerates infections into winter, we highlight the potential for Saudi to drive incremental cuts at the Nov. 30 OPEC meeting,” analysts including Christyan Malek said in a note. “Our base case is a reversal of the 1.9 million barrels per day output increase slated for 2021 with an upside scenario of a deeper cut whereby Saudi reduces its own quotas even lower (in the event of a worsening demand outlook),” J.P. Morgan said.

Why Saudi Arabia May Be Forced To Start Another Oil Price War - The ongoing weakness of global oil markets seems to be stoking tensions within OPEC+, and a split within its leadership is now imminent. From the start of this year’s Moscow-Riyadh brokered OPEC+ production cut deal, internal differences have been kept at bay by a global pandemic and high crude oil storage volume. Market optimism now seems to be growing, from bullish reports about next year’s crude oil prices and even today’s IEA World Energy 2020 Report. But the reality of oil markets is far bleaker. The threat of European lockdowns is real, hitting global demand again while taking a heavy toll on the economy.Nobody is speaking about a new oil price war yet, but the writing is on the wall with some producers now fed up with strangling their own production to counter the overproduction of others. Asian importers, especially China and India, have been reaping the rewards of this low price environment, filling their oil storage tanks to the brim. Although most Asian importers now seem to be content with storage. An OECD economic downturn will put several million barrels per day of expected Asian demand at risk. It is a worrying time for the two main architects of the OPEC+ agreement. One could say that Riyadh and Moscow are caught in a Catch22 situation, as whatever they try to do, the market is likely too weak to react and will come back to hurt both parties. Saudi Arabia, supported by its main ally UAE, and Russia are both looking at a financial crash of unknown magnitude if oil markets don’t recover soon. Oil prices are currently too low to sustain the government strategy of both nations. The latest reports on the Saudi government budget, which is based on a $50 per barrel scenario, is realistically too optimistic, as prices right now are in the low $40s. For Russia, its economy has been hit from all sides, as oil and gas is weak, demand worldwide is down, and the diversification of its economy is stalling. Putin’s maneuverability, however, is higher than that of the Saudi rulers. Russia’s global power position still opens doors to make life bearable in the coming months. Saudi Arabia, however, is looking at a situation in which a straightforward strategy does not seem to exist. Without higher crude oil prices, not only is the Kingdom’s flagship Saudi Aramco suffering but most government projects too. The world’s largest oil company has already put several major new projects on hold, while at the same time reassessing investment levels of others. High-profile offshore projects, such as the Red Sea or the setup of the new shipyard in Ras Al Khair, are not progressing as fast anymore, showing some internal constraints.

Oil prices extend slide as U.S. producers restore output (Reuters) - Oil prices fell on Monday as force majeure at Libya’s largest oilfield was lifted, a Norwegian strike affecting production ended and U.S. producers began restoring output after Hurricane Delta.  Brent crude fell 52 cents, or 1.2%, to $42.33 a barrel by 1052 GMT and U.S. West Texas Intermediate CLc1 was down 58 cents, or 1.4%, at $40.02.  Production in Libya, a member of the Organization of the Petroleum Exporting Countries (OPEC), is expected to rise to 355,000 barrels per day (bpd) after force majeure at the Sharara oilfield was lifted on Sunday. Rising Libyan output will pose a challenge to OPEC+ - a group comprising OPEC and allies including Russia - and its efforts to curb supply to support prices. “If oil demand recovery continues to struggle due to new or stricter COVID-related mitigation measures, the (OPEC+) producer group may need to reconsider the planned tapering of their voluntary supply cuts,”  Front-month prices for both contracts gained more than 9% last week in the biggest weekly rise for Brent since June. But both fell on Friday after Norwegian oil companies struck a deal with labour union officials to end a strike that had threatened to cut the country’s oil and gas output by close to 25%. Hurricane Delta, which dealt the greatest blow to U.S. Gulf of Mexico energy production in 15 years, was downgraded to a post-tropical cyclone at the weekend. Workers headed back to production platforms on Sunday and French oil major Total TOTF.PA was working to restart its 225,500 barrel per day Port Arthur refinery in Texas. Prices were also pressured by a jump in new COVID-19 cases, which has raised the spectre of more lockdowns. Infections are at record levels in the U.S. Midwest and in Britain Prime Minister Boris Johnson is expected to announce new measures on Monday while Italy is preparing fresh nationwide restrictions. Goldman Sachs, meanwhile, said that the outcome of the U.S. presidential election would not impact its bullish oil and natural gas outlook and that an overwhelming Democratic victory could be a positive catalyst for these sectors.

Oil falls nearly 3% as production comes back online - Oil prices fell about 3% on Monday as force majeure at Libya's largest oilfield was lifted, a Norwegian strike affecting production ended and U.S. producers began restoring output after Hurricane Delta. Brent crude fell $1.21, or 2.8%, to $41.64 a barrel West Texas Intermediate fell 2.88%, or $1.17, to settle at $39.43 per barrel. "Renewed post hurricane production in the Gulf of Mexico, an apparent restart over the weekend of Libya's largest oil field and today's strength in the U.S. dollar increase the possibility of a WTI downswing back to the early October lows," said Jim Ritterbusch, president of Ritterbusch and Associates. Hurricane Delta, which inflicted the biggest blow in 15 years to energy production in the U.S. Gulf of Mexico last week, was downgraded to a post-tropical cyclone at the weekend. Workers headed back to production platforms on Sunday and French oil major Total restarted its 225,500 barrel per day Port Arthur refinery in Texas. Front-month prices for both contracts gained more than 9% last week in the biggest weekly rise for Brent since June. But both fell on Friday after Norwegian oil companies struck a deal with labour union officials to end a strike that had threatened to cut the country's oil and gas output by close to 25%. Production in Libya, a member of the Organization of the Petroleum Exporting Countries (OPEC), is expected to rise to 355,000 barrels per day (bpd) after force majeure at the Sharara oilfield was lifted on Sunday. Rising Libyan output will pose a challenge to OPEC+ - a group comprising OPEC and allies including Russia - and its efforts to curb supply to support prices. Prices were also pressured by a jump in new COVID-19 cases, which has raised the spectre of more lockdowns which could dampen demand for oil. Infections are at record levels in the U.S. Midwest. In Europe, British Prime Minister Boris Johnson announced new coronavirus lockdown measures and Italy is preparing fresh nationwide restrictions.

Oil gains nearly 2% as robust China trade data offsets returning supply Oil prices rebounded on Tuesday, supported by robust economic data from China that offset returning supply in other regions but gains were capped by forecasts for a slow recovery in global oil demand as coronavirus cases rise. Brent crude futures were up 72 cents, or 1.7%, to $42.44 a barrel. West Texas Intermediate crude futures settled 77 cents, or 1.95%, higher at $40.20 per barrel. On Monday, both benchmarks fell nearly 3%. China, the world's top crude oil importer, took in 11.8 million barrels per day (bpd) of oil in September, up 5.5% from August and up 17.5% from a year earlier, but still below the record high level of 12.94 mln bpd in June, customs data showed. "Oil prices, which suffered quite a blow the previous day, were looking for a bright spot and Tuesday offered just that," said Rystad Energy's senior oil markets analyst Paola Rodriguez-Masiu. "We find that China's record haul of crude growth is poised to cease as independent refineries have nearly fully utilized their state-issued import quotas and companies struggle with extremely high crude inventories. Therefore, despite the initial enthusiasm, we find that the uptick in oil prices today is unjustified." The International Energy Agency (IEA) - which advises Western governments on energy policy - said in its World Energy Outlook that in its central scenario a vaccine and therapeutics could mean the global economy rebounds in 2021 and energy demand recovers by 2023. But under a "delayed recovery scenario," it said the energy demand recovery is pushed back to 2025. "The era of global oil demand growth will come to an end within the next 10 years, but in the absence in a large shift in government policies, I don't see a clear sign of a peak," IEA chief Fatih Birol told Reuters. The Organization of the Petroleum Exporting Countries (OPEC) also forecast a slower demand recovery on Tuesday. In a monthly report, it said oil demand will rise by 6.54 million bpd next year to 96.84 million bpd, 80,000 bpd less than expected a month ago. Social restrictions were being tightened in Britain and the Czech Republic to battle rising cases of COVID-19, and French Prime Minister Jean Castex said he could not rule out local lockdowns. On the supply side, workers have been returning to U.S. Gulf of Mexico platforms after Hurricane Delta and Norwegian workers to offshore rigs after ending a strike. The energy minister from the United Arab Emirates (UAE) said on Tuesday that OPEC+ oil producers will stick to their plans to taper oil production cuts from January. OPEC member Libya on Sunday also lifted force majeure at its Sharara oilfield. Libya's total output on Monday was expected to hit 355,000 bpd while a full return of the 300,000 bpd Sharara field would nearly double that.

Oil rises 2% as OPEC complies with production cuts  (Reuters) - Oil prices strengthened on Wednesday, as OPEC and its allies were seen complying with a pact to cut oil supply in September, even as concerns loomed that recovery in fuel demand will be stalled by soaring global coronavirus cases. Early in the day crude was boosted by a bullish stock market. Even as equities whipsawed on pandemic worries, oil stayed higher, buoyed by expectations that OPEC could staunch a supply glut. Wall Street’s main indexes opened higher on Wednesday, supported by heavyweight technology stocks. The dollar traded lower, which can boost oil as investors switch asset classes. “Between the dollar, the EIA and the warning from the IEA that may impact future OPEC policy, the tone has turned bullish here,” said Bob Yawger, director of energy futures at Mizuho in New York. Data from the U.S. Energy Information Administration (EIA)is expected to show crude oil stockpiles moving lower in the latest week, according to analysts polled by Reuters. The American Petroleum Institute said U.S. crude inventories fell more than expected in the latest week, according to a report released after market close on Wednesday. Analysts expect the U.S. Energy Information Administration data to confirm that draw on Thursday, a Reuters poll showed. Brent crude futures LCOc1 for December delivery settled up 87 cents, or 2.05%, at $43.32 a barrel. U.S. West Texas Intermediate CLc1 futures also traded higher, settling up 84 cents, 2.09%, at $41.04 a barrel. OPEC+ had 100% compliance with a pact to cut oil supply in September was seen at 102%, two OPEC+ sources told Reuters.

WTI Holds Above $41 After Large Crude & Product Inventory Draws - Oil prices rallied today on the back of a weaker dollar and somewhat optimistic report from IEA, which decided to leave its 2020 forecast for oil demand unchanged at 91.7 million barrels per day while painting a picture of contracting supply, penciling in a 4-million-barrel-a-day drop in the fourth quarter.But there is a lot of noise in the data still... "Inventories are famously all over the board as a hurricane comes in,"  . Hurricane Delta made landfall on Louisiana's Gulf Coast last week. The supply numbers "will be skewed enough and will cause more confusion than really shed any light." But the algos will get triggered one way of the other... API

  • Crude -5.422mm (-2.3mm exp)
  • Cushing +2.199mm
  • Gasoline -1.513mm (-1.8mm exp)
  • Distillates -3.93mm (-2.5mm exp)

After last week's surprise crude build, analysts continue to expect another draw and got a really big one (-5.42mm vs 2.3mm exp). Products also showed notable draws... Graphs Source: Bloomberg   WTI hovered around $41 ahead of the print and held those gains after the bigf draws... Going forward, OPEC+ members "will likely adopt a wait-and-see approach and not pursue new policies, since the market seems to be in balance and they will be cautious not to mess with the fragile recovery recently achieved," said Manish Raj, chief financial officer at Velandera Energy."OPEC+ has shown its willingness to step in to rebalance the market, should that be necessary, but they will not risk prematurely tilting the balance in either direction," he told MarketWatch.

Oil jumps 2% ahead of U.S. inventory data - Oil prices strengthened on Wednesday, as equities also rose and the dollar traded lower, even as concerns loomed that recovery in fuel demand will be stalled by soaring global coronavirus cases. Wall Street's main indexes opened higher on Wednesday, supported by heavyweight technology stocks. The dollar traded lower, which can boost oil as investors switch asset classes. "Between the dollar, the EIA and the warning from the IEA that may impact future OPEC policy, the tone has turned bullish here," said Bob Yawger, director of energy futures at Mizuho in New York. Data from the U.S. Energy Information Administration (EIA) is expected to show crude oil stockpiles moving lower in the latest week, according to analysts polled by Reuters Brent crude futures for December delivery were up 49 cents, or 1.18%, at $42.94 a barrel. West Texas Intermediate futures settled 84 cents, or 2.1%, higher at $41.04 per barrel. "There is a risk that the demand recovery is stalled by the recent increase in COVID-19 cases in many countries," the International Energy Agency said on Wednesday. "The longer term offers little encouragement for producers; the curve shows prices not reaching $50 per barrel until 2023. Truly, those wishing to bring about a tighter oil market are looking at a moving target." The Organization of the Petroleum Exporting Countries (OPEC) cut its oil demand forecast on Tuesday, citing economic dislocations caused by the virus. Russian Energy Minister Alexander Novak said that leading oil producers will start easing output curbs as planned in January despite a spike in coronavirus cases. U.S. crude oil inventories were seen falling last week while distillate stockpiles are likely to have declined for a fourth week, a preliminary Reuters poll showed on Tuesday. The poll was conducted ahead of reports from the American Petroleum Institute and the Energy Information Administration. Both reports were delayed by a day because of a public holiday in the United States on Monday.

Oil slips as new lockdown measures threaten demand recovery - Oil prices slipped on Thursday as new restrictions to stem a surge in COVID-19 infections increased uncertainty over the outlook for economic growth and a recovery in fuel demand. But prices bounced off their lows after better-than-expected inventory data. Brent futures fell 25 cents, or 0.6%, to trade at $43.06 per barrel, while U.S. West Texas Intermediate (WTI) crude was down 21 cents, or 0.5%, at $40.83 per barrel. Traders noted the price decline was limited by industry data showing a fall in U.S. oil inventories last week. The U.S. Energy Information Administration said Thursday that inventory declined by 3.818 million barrels in the prior week, larger than the 1.9 million barrel draw analysts polled by FactSet had been expecting. The American Petroleum Institute industry group on Wednesday said U.S. crude, gasoline and distillate inventories all fell in the week to Oct. 9. Some European countries are reviving curfews and lockdowns to try to contain the rise in new coronavirus cases, with Britain expected to impose tougher COVID-19 restrictions on London from midnight on Friday. "If demand weakens noticeably, OPEC+ will have no choice but to call off its production increase if it does not want to risk a renewed oversupply and another price slide," Commerzbank said. OPEC and its allies, together called OPEC+, are due to taper production cuts by 2 million barrels per day (bpd), from 7.7 million bpd currently, in January. OPEC+ had 102% compliance with its agreement to cut oil supply in September, two OPEC+ sources told Reuters ahead of a technical committee meeting on Thursday. The group will ensure oil prices do not plunge steeply again when it meets to set policy at the end of November, OPEC's Secretary General said, adding that demand has been recovering more slowly than expected. Top global oil traders Vitol, Trafigura and Gunvor said they saw slow oil demand recovery because of a second coronavirus wave with oil prices rising to or above $50 per barrel only by October next year. "Toxic brew of COVID-19 lockdowns, especially in Europe, and the apparent end of any hopes for a U.S. stimulus deal before the election are weighing on risk assets," said Bob Yawger, director of energy futures at Mizuho in New York.

WTI Pops Back Above $40 After Biggest Distillates Draw Since 2003 -Oil prices plunged overnight, with WTI back below $40, as last night's bullish API-reported bigger-than-expected draw was trumped by traders fears that weaker than expected US jobs data and new virus restrictions in Europe will further threaten any sustained demand rebound. U.S. labor market data is providing “more fuel for the fire of a sour economic outlook,” said Gary Cunningham, a director at Tradition Energy. “If there are further restrictions or new restrictions put in place in Europe or here in the U.S., then that further decreases travel demand for petroleum.” DOE

  • Crude -3.818mm (-2.3mm exp)
  • Cushing +2.906mm
  • Gasoline -1.626mm (-1.8mm exp)
  • Distillates -7.245mm (-2.5mm exp) - biggest draw since 2003

Official data showed a crude draw that was smaller than API reported, a big build at Cushing, and a huge draw in Distillates (biggest since 2003)... US Crude production remains noisy given the storm-related impacts, with shut-ins sending production levels down 500k barrels per day... Latest EIA data indicate drilling activities remain anemic in September, even as WTI recovered to near $40 per barrel. WTI traded just below $40 ahead of the official inventory data, popping back above $40 after the draws...

Oil eases as new lockdowns raise concern about fuel demand - (Reuters) - Oil prices eased on Thursday as new restrictions to stem a surge in COVID-19 infections dimmed the outlook for economic growth and fuel demand. Traders said prices pared earlier losses after the U.S. Energy Information Administration (EIA) reported an increase in U.S. petroleum demand last week that helped reduce crude stockpiles, while distillate inventories dropped by the most since 2003 as Hurricane Delta cut oil production and shut Gulf Coast refineries. “The (EIA) report halted the (price) slide, which was threatening to turn into an avalanche earlier this morning,” said Robert Yawger, director of energy futures at Mizuho in New York. Brent LCOc1 futures fell 16 cents, or 0.4%, to settle at $43.16 a barrel, while U.S. crude CLc1 fell 8 cents, or 0.2%, to settle at $40.96. Earlier, both benchmarks were down more than $1 a barrel. In Europe, some countries were reviving curfews and lockdowns to fight a surge in new coronavirus cases, with Britain imposing tougher COVID-19 restrictions in London on Friday. “The coronavirus surge is forcing Europe to reinstate pandemic restrictions and that is ... crippling short-term crude demand forecasts,” said Edward Moya, senior market analyst at OANDA in New York. “Anemic demand will force (OPEC+) to delay any easing of oil production cuts.” OPEC and allies in a group called OPEC+ are due to taper production cuts in January by 2 million barrels per day (bpd), from 7.7 million bpd currently. A Joint Technical Committee, which includes representatives from key OPEC+ producers such as Saudi Arabia and Russia, met to review compliance with its global oil output cuts. OPEC+ made little progress in September in compensating for over-production in previous months, figures given to Reuters by OPEC sources showed on Thursday. “It’s apparent ... that Saudi Arabia is getting impatient, both with the lack of compliance by others and “low” oil prices,” said Bjornar Tonhaugen, head of oil markets at Rystad Energy. OPEC’s Secretary General said demand was recovering more slowly than expected and OPEC+ will ensure oil prices do not plunge steeply again when it meets at the end of November. Top global oil traders Vitol, Trafigura and Gunvor said they saw slow oil demand recovery because of the resurgent pandemic.

Oil prices end a bit lower, but nearly erase their losses as U.S. supplies decline – Oil futures settled a bit lower on Thursday, as rising cases of COVID-19 sparked new lockdowns in Europe, raising worries about further slowdowns in energy demand. Prices, however, nearly erased the day’s losses, buoyed by U.S. government data showing a bigger-than-expected 3.8 million-barrel weekly decline in domestic crude inventories reported MarketWatch. November West Texas Intermediate crude fell 8 cents, or 0.2%, to settle at $40.96 a barrel on the New York Mercantile Exchange. The global benchmark, December Brent crude shed 16 cents, or 0.4%, to $43.16 a barrel on ICE Futures Europe. “COVID-19 reports will continue to rule the daily volatility,” said James Williams, energy economist at WTRG Economics. “In the longer term, there is a lot of upward pressure building,” as prices are not high enough to “encourage sufficient drilling to offset U.S. production declines,” he said, adding that demand will likely recover faster than U.S. output.

Oil slides on Covid-19 resurgence, strong dollar - Oil prices slid on Friday dragged down by concerns that a spike in Covid-19 cases in Europe and the United States is curtailing demand in two of the world's biggest fuel consuming regions, while a stronger U.S. dollar also added to pressure. Brent crude futures for December dropped 46 cents, or 1.07%, to $42.70 a barrel, while U.S. West Texas Intermediate (WTI) crude futures for November delivery slid 43 cents, or 1.05%, to $40.53 a barrel. Both benchmarks fell slightly the previous day and are on track to remain little changed for the week. "Worries over weakening fuel demand in Europe due to a resurgence in COVID-19 cases and a higher U.S. dollar against the euro weighed on investor sentiment," said Kazuhiko Saito, chief analyst at Fujitomi Co. In Europe, some countries were reviving curfews and lockdowns to fight a surge in new coronavirus cases, with Britain imposing tougher Covid-19 restrictions in London on Friday. Pandemic cases have surged in the U.S. Midwest and beyond, with new infections and hospitalizations rising to record levels in an ominous sign of a nationwide resurgence as temperatures get colder. The dollar was headed for its best week of the month on Friday, as surging coronavirus cases and stalled progress toward U.S. stimulus had nervous investors seeking safe assets. A technical committee of the Organization of the Petroleum Exporting Countries (OPEC) and allied oil producers, a group know as OPEC+, also ended a meeting on Thursday expressing concerns about rising oil supply as social restrictions to curb the spread of COVID-19 limit fuel usage. "All eyes are on OPEC+ move from January," said Hiroyuki Kikukawa, general manager of research at Nissan Securities. OPEC+ is set to reduce its current supply cuts of 7.7 million barrels per day (bpd) by 2 million bpd in January even as OPEC Secretary General Mohammed Barkindo admits fuel demand is looking "anemic." The bearish demand outlook and rising supply from Libya may mean OPEC+ could roll over the existing cuts into next year, OPEC+ sources said on Thursday. There is an OPEC+ meeting scheduled for Nov. 30 to Dec. 1 to set policy. "With uncertainty over OPEC+ future policy and the U.S. presidential election, oil prices will likely remain in a tight range for a while,"

Oil ends lower on demand concerns, but prices score a gain on the week - Oil futures slipped a bit on Friday as rising COVID-19 cases in the U.S. and Europe heightened worries about demand for crude, but prices finished higher for the week, partly due to assurances from OPEC+ that it remains committed to production cuts. The Organization of the Petroleum Exporting Countries and their allies, together known as OPEC+, seem “to have comforted markets that they are leading the oil market to balance,” s Oil prices found support for the week after Saudi Arabia and Russia reportedly reiterated their commitment to the OPEC+ production cut agreement. That raised expectations that “the alliance might take further action to either address some of its members’ undercompliance or re-evaluate its plan to boost production again from January,” “If these hopes prove futile then prices may be in danger again next week after the OPEC+ meeting.” The Joint OPEC-Non-OPEC Ministerial Monitoring Committee, or JMMC, which monitors compliance with production cuts, is scheduled to meet on Monday. West Texas Intermediate crude for November delivery CL.1, -0.24% fell 8 cents, or 0.2%, to $40.88 a barrel on the New York Mercantile Exchange. Prices for the front-month contract, which expires at Tuesday’s settlement, posted a weekly rise of 0.7%. Read: Here’s how the U.S. presidential election could shake up the oil market December Brent crude, the global benchmark, lost 23 cents, or 0.5%, to $42.93 a barrel on ICE Futures Europe. Brent saw a 0.2% weekly climb. Moya warned, however, that “Libya’s oil production revival might complicate the supply side narrative.” Bloomberg reported Thursday that Libya’s output has climbed to around 500,000 barrels per day, after the reopening of facilities last month that had been shutdown since January due to a blockade related to the civil war. Meanwhile, “the market is worried about how the increasing lockdown measures in Europe will affect demand,” . “Mobility data suggests that travel has only recovered to 60% of its pre-pandemic levels in Europe, and it’s about to get a new hit as several European countries restrict gatherings again.” “The not-too distant memory of negative oil prices still stings traders across the space as the threat of another supply chain crunch would rise exponentially with expectations of new lockdown measures being imposed in the U.S.,” Still, “more widespread lockdowns do remain rather unlikely.”

Lebanon explosion: Deadly fuel tank blast rocks Beirut – BBC  - A fuel tank has exploded in a densely populated area of the Lebanese capital, Beirut, killing at least four people and injuring 20. The blast occurred after the tank caught fire in Tariq-al-Jdide district. TV footage showed flames leaping up buildings in the area's narrow streets. There is no word on the cause of the fire. The rescue efforts are ongoing. The blast caused panic in a city scarred by the explosion that killed 203 people in the port area in August. The latest fire and explosion also comes amid a severe financial crisis and the coronavirus pandemic - which have fuelled widespread discontent. On Friday firefighters used ladders to scale the outside of apartment buildings to rescue residents from their balconies. "The sound and our house shaking made us panic and the whole street I live in started screaming. I had flashbacks," tweeted one woman.

Aden seaport authorities demand hire charge before dumping fertilizers -- Seaport authorities in Aden continue to store urea fertilizer despite an order to dump the hazardous material, government officials said Saturday. In August, a committee assigned by Yemen’s attorney general to investigate reports of thousands of tons of ammonium nitrate being stored at the port found that the material was in fact a different fertilizer, urea. It ordered the seaport authority to get rid of it as it could explode if mixed with other materials. The investigation followed a media report about ammonium nitrate gathering dust at the port that could cause a massive explosion, similar to the one that ravaged Beirut on Aug. 4. The story caused uproar and panic in Yemen, prompting lawmakers, government officials and the public into demanding a quick investigation. When asked why the judiciary order had not been followed, Mohammed Amzrabeh, chairman of the Yemen Gulf of Aden Ports Corporation, told Arab News that the case was in court, without giving further details. But, according to two local government officials familiar with knowledge of the case, seaport authorities are demanding that a local trader who imported the materials pay hundreds of thousands of dollars in hire charge for storing the urea. “The seaport authorities seek a financial settlement with the trader,” one of the officials, who requested anonymity, told Arab News. “The materials have expired and no longer pose a threat to anyone.” The Saudi-led Arab coalition and the internationally recognized government have asked local traders to get permission before importing urea fertilizer, widely seen as an explosive material that could be used by the Houthis for military purposes. 

U.N. access to decaying Yemen tanker could take weeks - (Reuters) - A United Nations team will have to wait several weeks to access a deteriorating tanker off Yemen’s shore that is threatening to spill 1.1 million barrels of crude oil in the Red Sea, two U.N. sources told Reuters. The United Nations has warned that the Safer, stranded since 2015, could spill four times as much oil as the 1989 Exxon Valdez disaster near Alaska, but access to the vessel has been complicated by the war in Yemen. Yemen’s Houthi movement, which controls the area where the tanker is moored and the national oil firm that owns it, agreed in July to allow a technical team to assess the ship and conduct whatever repairs may be feasible. But the two sources said that it could take another seven weeks to finalise details of the agreement and logistics, with the coronavirus pandemic further complicating planning. The deal includes the eventual sale of the oil on board with proceeds divided between Houthi authorities and Yemen’s internationally recognised government, which the movement ousted from the capital, Sanaa, in late 2014. Some diplomats say there are still doubts about the mission as Houthi officials had last year reneged on granting access. The Safer, built in 1974, is moored off the Ras Issa oil terminal, 60 km (40 miles) north of the port of Hodeidah. The area is held by the Houthis, but the high seas are controlled by a Saudi-led coalition that intervened in Yemen in 2015 against the movement and has prevented it from selling oil. U.N. and Houthi officials say water has entered the Safer’s engine room at least twice since 2015. The latest leak in May was plugged by Safer Corp divers and Houthi naval units. While the Houthis can fix small leaks it remains unclear how long such repairs can hold, U.N. officials and experts said. Last month, Riyadh warned that an “oil spot” was seen in a shipping transit area 31 miles (50 km) west of the tanker. The United Nations says a major rupture could severely harm Red Sea ecosystems and shut Hodeidah port, Yemen’s main entry point for imports and aid.

Aframax mine blast off Yemen puts shipping on alert  - Shipping has been put on alert to be highly vigilant when transiting the Gulf of Aden with news of an aframax tanker suffering sizeable damage after it struck a sea mine in Yemeni waters. Significant pollution has been spotted in satellite images in the wake of the Syra, a 10-year-old Maltese-flagged ship, hitting a mine just before midnight on October 3.The ship was taking on crude at the Bir Ali crude single buoy mooring system, located in central Yemeni waters when the explosion happened.  Security consultant Ambrey Intelligence has suggested the incident was likely a symptom of the ongoing battle between the Yemeni government and the Southern Transitional Council, a secessionist organisation. Ambrey senior analyst Jake Longworth told Splash that no group has claimed responsibility for the attack.“The war risk rating for Bir Ali and Ash Shihr – Yemen’s only operational export terminals – has been raised to elevated. This is due to the credible risk that the actor behind the attack on the Syra attempts to disrupt any future exports from Yemen using the same tactic,” Longworth said.. Officials at Eastmed declined to comment on the damages sustained to the ship when contacted by Splash today.  Splash understands the tanker suffered damage to its forward ballast tanks, but has been able to move on its own power and is due to arrive in Fujairah in the United Arab Emirates later today where its cargo will be transferred and then the ship will head for repairs. Eyewitness reports sent to Splash show significant hull damage to the ship, which is carrying around 65,000 tons of crude.

Britain: The world’s second largest arms exporter and friend to warmongers and despots - According to data released by the Department for International Trade (DIT), the UK government was the world’s second biggest arms exporter behind the US between 2010-2019. Britain signed £86 billion worth of contracts for military equipment and services. Last year, Britain exported £11 billion worth of fighter jets, radar, missiles, arms, and materiel, the second highest year for UK arms sales since 1983. While the US was by far the largest arms exporter, accounting for 47 percent of the global arms trade, the UK accounted for 16 percent, while Russia and France had 11 percent and 10 percent respectively. Sales were down from 2018’s £14 billion due to what DIT said was “the volatile nature of the global export market for defence.” The UK won “no major platform orders in 2019” and arms exports to Saudi Arabia were halted in June last year, following the Court of Appeal’s ruling that the UK government had failed to take into account whether Saudi airstrikes in Yemen that targeted civilians broke humanitarian law. While the US is Britain’s largest single arms customer, most of Britain’s arms exports (60 percent) go to the Middle East, with Saudi Arabia by far the largest buyer along with Oman, Turkey, the United Arab Emirates (UAE), Qatar, Israel, Bahrain, and Egypt. The UK government had no hesitation in greenlighting the sale of arms to countries waging war at home or abroad, including to Saudi Arabia, the Philippines, Afghanistan, UAE, Nigeria, Mexico, Iraq, Ukraine, the Democratic Republic of Congo, Kenya, and South Sudan. The list of Britain’s customers reads like a roll call of the most corrupt and blood-soaked regimes on the planet. The UK has licensed more than £6.5 billion worth of arms to the Saudi-led coalition in the five years since March 26, 2015, when the bombing began.  According to the Armed Conflict Location & Event Data Project (ACLED), the Saudi-led war against Yemen—waged with the full backing of Washington and London—has killed over 100,000 people, mostly civilians.

Delivery Of 2 Million Flu Vaccines To Iran Blocked By US Sanctions On Banks -Last Thursday the US Treasury announced fresh sanctions on 18 Iranian banks in order to “stop illicit access to U.S. dollars” — a move widely seen as the most aggressive and devastating measure against Iran's financial sector to date. Given it effectively blacklists the entire Iranian financial system, Treasury Secretary Steven Mnuchin tried to proactively address European allies and international critics' concerns that this would only massively increase the suffering of the common Iranian people amid a raging pandemic. His statement last week vowed that certain exemptions will "continue to allow for humanitarian transactions to support the Iranian people."But now Iranian health officials say they've been prevented by US sanctions from importing 2 million influenza vaccines, amid a desperate and deteriorating health crisis inside the country.Iran’s Red Crescent says due to the new US sanctions against Iranian banks, the humanitarian organization is not able to purchase two million doses of flu vaccines that were supposed to be distributed for vaccination of medical staff, high risk patients and pregnant mothers.— Zahra Shafei (@shafei_d) October 14, 2020   Iran’s Red Crescent Society announced on Twitter that new US sanctions on Shahr Bank are to blame. The bank is reportedly largely responsible for foreign-currency purchases of drugs, but has now “been sanctioned by the U.S. government and the vaccines haven’t reached the Red Crescent.”According to Bloomberg, this has left the health organization scrambling: The Red Crescent said it was attempting to source replacement vaccines through neighboring countries. Some 200,000 flu doses had been delivered to the ministries of health and education, the organization said in a subsequent tweet, without giving more details.Iran's leaders have been outraged, also alleging over the past days the United States has intentionally severely exacerbated the impact of the coronavirus pandemic inside the Islamic Republic, essentially kicking the country while it's already down, choking off even humanitarian and medical supplies via sanctions and threats against those willing to trade with Iran.“Amid Covid19 pandemic, U.S. regime wants to blow up our remaining channels to pay for food & medicine,” Foreign Minister Javad Zarif tweeted last week. “Iranians WILL survive this latest of cruelties.”

Russian-brokered ceasefire in Azeri-Armenian war collapses - Russian President Vladimir Putin’s attempt to broker a truce in the two-week-old war between Azerbaijan and Armenia collapsed over the weekend. Fighting erupted between the two former Soviet republics in the Caucasus five minutes after the agreement reached by Azeri and Armenian diplomats in Moscow was to go into effect, at noon on Saturday. Bombings of civilian targets on both sides, and bloodshed along the front and in the disputed Nagorno-Karabakh region all continue to mount. The Kremlin had invited delegations from the Azeri and Armenian foreign ministries on October 9 to Moscow, declaring: “The President of Russia is issuing a call to halt the fighting in the Nagorno-Karabakh on humanitarian grounds in order to exchange dead bodies and prisoners.” French President Emmanuel Macron, who has aggressively backed Armenia, also called for a cease-fire. Armenian officials went to the talks, reversing their stated position that they would only attend talks if a cease-fire was first agreed to. Shortly before talks began in Moscow, however, officials in both Azerbaijan and its main regional backer, Turkey, said they would make no compromises. Turkish presidential spokesman Ibrahim Kalin bluntly predicted that the Moscow talks would be a failure. “If they’re calling only for a ceasefire, if they’re working only towards a ceasefire, it will be nothing more than a repeat of what went on for the last 30 years or so,” he said. Restating the Turkish government’s position that Armenia illegally occupies the Karabakh, Kalin added: “It is almost certain to fail if it doesn’t also involve a detailed plan to end the occupation.” Azeri President Ilham Aliyev gave a televised address to the nation insisting he would make no concessions to Armenia. Aliyev said, “Azerbaijan’s use of force had changed the facts on the ground” and that has “proved there was a military solution to the dispute,” Reuters reported. He added that these negotiations were Armenia’s “last chance” to peacefully resolve the conflict. Aliyev added that Azeri forces had taken the communities of Hadrut, Chayli, Yukhari Guzlak, Gorazilli, Gishlag, Garajalli, Afandilar, Suleymanli and Sur in the Karabakh, calling it a “historic victory.” He reported that Armenian-held Fuzuli province in Azerbaijan had also been surrounded, and that Azeri forces had left a small escape route through which Armenians were leaving.

Turkey Weapons Sales To Azerbaijan Witnessed Huge Surge Just Before Armenia Conflict - New figures produced by the Turkish Exporters’ Assembly and subject of an investigation by Reuters show a massive surge in Turkish weapons exports to its ally Azerbaijan just ahead of the raging conflict sparked late last month in the disputed Nagorno-Karabakh region."Turkey’s military exports to its ally Azerbaijan have risen six-fold this year, with sales of drones and other military equipment rising to $77 million last month alone before fighting broke out over the Nagorno-Karabakh region, according to exports data," reports Reuters.  It's a massive figure for the tiny Caucasus country of just less than ten million people. The data shows that over the first nine months of 2020 Turkey sold Azerbaijan $123 million in defense and aviation equipment. But this ramped up significantly by August once clashes between Armenian and Azeri forces, which have been sporadic and fierce since the early 1990's collapse of the Soviet Union and self-declared autonomy of ethnic Armenian Nagorno-Karabakh, grew more intense at the end of the summer. According to the reportMost of the purchases of drones, rocket launchers, ammunition and other weapons arrived were after July, when border clashes between Armenian and Azeri forces prompted Turkey and Azerbaijan to conduct joint military exercises. Sales jumped from $278,880 in the month of July to $36 million in the month of August, and $77.1 million in just September, the data showed.  Other major suppliers of Azerbaijan's military have included Russia and Israel. Russia also has a defense pact with Armenia, including a major base in the country's north.

In "Major Escalation" Turkey Renews Gas Exploration Off Greece, Vows Military Escort - In late September into early this month for a brief moment it looked as if the Turkey-Greece East Mediterranean dispute over Turkish hydrocarbons exploration was cooling, given intense diplomatic contacts and negotiations among the major players, which includes Cyprus and the EU. This after in August and earlier last month the rival sides conducted increased war games which threatened at any moment to become 'live' fighting.But now this momentary calm has been shattered, as Turkey's navy late Sunday issued a public advisory saying it will sail the Oruc Reis survey ship to conduct exploration activities just off Greece's easternmost island of Kastellorizo. Turkey indicated the mission is planned over the next ten days, until October 22. Predictably, Athens was swift to condemn the move as a “major escalation and a direct threat to peace and security in the region,” according to a Foreign Ministry statement. Greek Prime Minister Kyriakos Mitsotakis notified the European Council by phone, at a moment the EU has threatened sanctions on NATO country Turkey. “This new unilateral act is a severe escalation on Turkey’s part,” Mitsotakis said.Like in prior instances of Turkish oil and gas vessels being sent into Greek and Cypriot waters widely recognized internationally as their Exclusive Economic Zones (EEZ), Ankara has vowed a military escort could be present if “support and protection” are necessary, according to Turkish Defense Minister Hulusi Akar.Greek Foreign Minister Nikos Dendias has used this latest provocative act to highlight a pattern of Turkish aggression spanning the entire near East region: “I explained the obvious, who is the common denominator in all problematic situations in the area: Nagorno-Karabakh, Syria, Iraq, Cyprus, the southeastern Mediterranean,” he said.