global oil shortage at 1.57 million bpd in August; DUCs fell as completions rose, new wells drilled remained at all time low

OPEC report indicates a global oil shortage of 1.57 million barrels per day in August; DUCs fell as completions rose and new wells drilled remained at all time low; November natural gas price is 28.6% higher than October natural gas price

​US ​oil prices rose for the first time in three weeks after hurricane Sally cut output, US ​oil ​supplies fell,​ ​and the Saudis pressured their OPEC partners to cut production...after falling 6.1% to $37.33 a barrel last week after the Saudis marked down their export prices and domestic crude supplies increased, the contract price of US light sweet crude for October delivery moved higher early Monday as another tropical storm in the Gulf of Mexico forced ​offshore ​production offline yet again, but turned lower and finished down 7 cents at $37.26 a barrel amid concerns about a stalled global economy, after OPEC ​had ​forecast a 9.46 million barrels per day drop in ​global ​demand this year...prices edged slightly lower early Tuesday, but turned higher as Hurricane Sally stalled offshore, and ended with a gain of $1.02 as $38.28 a barrel as more than a quarter of U.S. offshore oil and gas production was shut, and key exporting ports were closed by the approaching storm...oil prices then opened higher Wednesday after the API report indicated falling crude inventories, and then surged more than 4% after the EIA report confirmed a big drawdown in U.S. crude and gasoline inventories as Hurricane Sally left a swath of U.S. offshore production shut down, with US crude prices ending up $1.88 at $40.16 a barrel in their largest daily gain since June...oil prices gave up more than 1% of that gain in early trading on Thursday, but then reversed those losses to end 81 cents or 2% higher at $40.97 a barrel as an OPEC panel pressed laggards Iraq, Nigeria and the United Arab Emirates to cut more barrels to compensate for their overproduction in recent months...​​the oil rally weakened on Friday after a Libyan General said the blockade on the country’s oil exports would be lifted for a month as a prelude to negotiations, but still ended ​the day ​14 cents higher at $41.11 a barrel, the highest close in over two weeks...oil prices thus ended more than 10% higher for the week, after Saudi Arabia pressured its allies to stick to production quotas, Hurricane Sally cut U.S. production, and banks including Goldman Sachs predicted an oil supply deficit for the remainder of this year..

natural gas prices, on the other hand, fell for the third consecutive week, as a bigger than expected injection into storage put gas supplies on track to go into winter at a record level....after falling 12% to a four week low of $2.269 per mmBTU last week on an early cold weather outbreak and rising gas supplies, the contract price of natural gas for October delivery opened the week higher on Monday and held onto a 4.1 cent gain at $2.310 as LNG exports rose and natural gas output fell as producers shut in production ahead of Hurricane Sally's expected landfall on the Gulf Coast...natural gas prices rose another 5.2 cents on Tuesday as Sally's slow approach outweighed rising LNG exports and forecasts for milder weather and lower cooling demand over the next two weeks, but then gave up the week's gains in falling 9.5 cents to a four week low of $2.267 per mmBTU on Wednesday ​after Sally made landfall far east of Louisiana's gas production and was downgraded to a tropical storm...natural gas prices then plummeted 10% to a six week low of $2.042 per mmBTU on Thursday as the EIA reported a much bigger-than expected increase in gas inventories that kept stockpiles on track to reach record highs by the end of October....gas prices were then down another 6% at $1.926 per mmBTU on Friday before clawing their way back to close with a gain of six-tenths of a cent at $2.048 per mmBTU, as resuming output in the Gulf of Mexico offset an increase in LNG exports, which left the October contract down more than 9% on the week, and at a record 61 cents per mmBTU below the closing November natural gas quote of $2.633 per mmBTU...

the natural gas storage report from the EIA for the week ending September 11th indicated that the quantity of natural gas held in underground storage in the US increased by 89 billion cubic feet to 3,614 billion cubic feet by the end of the week, which left our gas supplies 535 billion cubic feet, or 17.4% greater than the 3,079 billion cubic feet that were in storage on September 11th of last year, and 421 billion cubic feet, or 13.2% above the five-year average of 3,193 billion cubic feet of natural gas that have been in storage as of the 11th of September in recent years....the 89 billion cubic feet that were added to US natural gas storage this week was significantly higher than the forecast of a 77 billion cubic foot increase from an S&P Global Platts'' survey of analysts, and it was also more than the 82 billion cubic feet addition of natural gas to storage during the corresponding week of 2019, and well above the average of 77 billion cubic feet of natural gas that has been added to natural gas storage during the same week over the past 5 years..  

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending September 11th showed that because of a drop in our oil imports and an increase in​ our​ refinery throughput, we needed to withdraw oil from our stored supplies for the seventh time out of 8 weeks and for the 12th time in thirty-five weeks...our imports of crude oil fell by an average of 416,000 barrels per day to an average of 5,423,000 barrels per day, after rising by an average of 523,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 349,000 barrels per day to an average of 2,595,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,413,000 barrels of per day during the week ending September 11th, 67,000 fewer barrels per day than the net of our imports minus our exports during the prior week...over the same period, the production of crude oil from US wells was reportedly 900,000 barrels per day higher at 10,900,000 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 13,313,000 barrels per day during this reporting week...

meanwhile, US oil refineries reported they were processing 13,488,000 barrels of crude per day during the week ending September 11th, 709,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA's surveys indicated that a net total of 931,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US....so based on that reported & estimated data, this week's crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 755,000 barrels per day more than what our oil refineries reported they used during the week....to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (-755,000) 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 there must be an error or errors of that magnitude in the oil supply & demand figures we have just transcribed...moreover, since last week's fudge factor was +547, indicating a week over week difference of 1,302,000 barrels per day in the line 13 balance sheet adjustment, the size of those errors render our week over week comparisons of oil supply and demand as nonsense...but 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... (for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....

further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 5,513,000 barrels per day last week, which was 20.1% less than the 6,652,000 barrel per day average that we were importing over the same four-week period last year....the 931,000 barrel per day net withdrawal from our total crude inventories was as 627,000 barrels per day were being pulled out of our commercially available stocks of crude oil and 304,000 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 900,000 barrels per day higher at 10,900,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states rose by 900,000 barrels per day to 10,400,000 barrels per day, while Alaska's oil production rose by 3,000 barrrels per day to 459,000 barrels per day but still added 500,000 barrels per day to the rounded national total....last year's US crude oil production for the week ending September 13th was rounded to 12,400,000 barrels per day, so this reporting week's rounded oil production figure was 12.1% below that of a year ago, yet still 29.3% 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 75.8% of their capacity while using 13,488,000 barrels of crude per day during the week ending September 11th, up from 71.8% of capacity during the prior week, but excluding the 2005 and 2008 hurricane-related refinery interruptions, still one of the lowest refinery utilization rates of the last thirty years...hence, the 13,488,000 barrels per day of oil that were refined this week were 19.3% fewer barrels than the 16,707,000 barrels of crude that were being processed daily during the week ending September 13th of last year, when US refineries were operating at 91.2% of capacity....

even with the jump in the amount of oil being refined, gasoline output from our refineries was still lower, decreasing by 111,000 barrels per day to 8,819,000 barrels per day during the week ending September 11th, after our refineries' gasoline output had decreased by 604,000 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 6.7% less than the 9,451,000 barrels of gasoline that were being produced daily over the same week of last year....at the same time, our refineries' production of distillate fuels (diesel fuel and heat oil) increased by 5,000 barrels per day to​ ​4,403,000 barrels per day, after our distillates output had decreased by 381,000 barrels per day to a three year low of 4,398,000 barrels per day over the prior week...after this week's increase in distillates output, our distillates' production was still 13.8% less than the 5,109,000 barrels of distillates per day that were being produced during the week ending September 13th, 2019....

with the decrease in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 9th time in 11 weeks and for the 24th time in 33 weeks, falling by 381,000 barrels to 231,524,000 barrels during the week ending September 11th, after our gasoline supplies had decreased by 2,954,000 barrels over the prior week...our gasoline supplies decreased by less this week even though the amount of gasoline supplied to US markets increased by 88,000 barrels per day to 8,478,000 barrels per day because our imports of gasoline roseby 26,000 barrels per day to 574,000 barrels per day and because our exports of gasoline fell by 203,000 barrels per day to 506,000 barrels per day....but even after the gasoline inventory drawdowns of recent weeks, our gasoline supplies were still 0.8% higher than last September 13th's gasoline inventories of 229,685,000 barrels, and roughly 3% above the five year average of our gasoline supplies for this time of the year... 

meanwhile, even with our distillates production near a three year low, our supplies of distillate fuels increased for the eighteenth time in 24 weeks and for the 22nd time in 49 weeks, rising by 1,675,000 barrels to 177,195,000 barrels during the week ending September 11th, after our distillates supplies had decreased by 1,675,000 barrels during the prior week....our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 904,000 barrels per day to nearly a 28 year low of 2,809,000 barrels per day, and even as our exports of distillates rose by 128,000 barrels per day to 1,212,000 barrels per day, while our imports of distillates fell by 48,000 barrels per day to 112,000 barrels per day...and after this week's inventory increase, our distillate supplies at the end of the week were 31.2% above the 136,663,000 barrels of distillates that we had in storage on September 13th, 2019, and about 22% above the five year average of distillates stocks for this time of the year...

finally, with the increase in our refinery throughput and the decrease in our oil imports, our commercial supplies of crude oil in storage (not including commercial oil in the SPR) fell for the 9th time in the past fifteeen weeks and for the 16th time in the past year, decreasing by 4,389,000 barrels, from 500,434,000 barrels on September 4th to 496,045,000 barrels on September 11th...even after that decrease, our commercial crude oil inventories were still around 14% above the five-year average of crude oil supplies for this time of year, and about 53% above the prior 5 year (2010 - 2014) average of our crude oil stocks for the second weekend of September, 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 crude oil supplies as of September 11th were 18.9% above the 417,126,000 barrels of oil we had in commercial storage on September 13th of 2019, 25.9% more than the 394,137,000 barrels of oil that we had in storage on September 14h of 2018, and 5.9% above the 468,241,000 barrels of oil we had in commercial storage on September 8th of 2017...    

OPEC's Monthly Oil Market Report

Monday of this past week saw the release of OPEC's September Oil Market Report, which covers OPEC & global oil data for August, and hence it gives us a picture of the global oil supply & demand situation in the first month after the unprecedented agreement between OPEC, the Russians, and other oil producers to cut production by 9.7 million barrels a day was reduced to a 7.7 million barrels a day cut....we​'ll​ again​ ​caution 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 figures 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 normal, 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 63), and it shows oil production in thousands of barrels per day for each of the current OPEC members over the recent years, quarters and months, as the column headings indicate...for all their official production measurements, OPEC uses an average of estimates from six "secondary sources", namely the International Energy Agency (IEA), the oil-pricing agencies Platts and Argus, ‎the U.S. Energy Information Administration (EIA), the oil consultancy Cambridge Energy Research Associates (CERA) and the industry newsletter Petroleum Intelligence Weekly, as a means of impartially adjudicating whether their output quotas and production cuts are being met, to thus avert any potential disputes that could arise if each member reported their own figures...

as we can see from the above table of oil production data, OPEC's oil output was up by 763,000 barrels per day to 24,045,000 barrels per day during August, from their revised July production total of 23,283,000 barrels per day...however that July output figure was originally reported as 23,172,000 barrels per day, which means that OPEC's July production was revised 111,000 barrels per day higher with this report, and hence August's production was, in effect, a rounded 874,000 barrel per day increase from the previously reported OPEC production figure (for your reference, here is the table of the official July OPEC output figures as reported a month ago, before this month's revisions)...

from the above table, we can also see that production increases of 475,000 barrels per day from the Saudis, 180,000 barrels per day from the Emirates,​ and​ 175,000 barrels per day from Kuwait accounted for the August increase, even as Iraq made a deeper production cut of 100,000 barrels per day....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, which accounts for the output increase by most members that we see today...however, since Iraq had never been in compliance with the original cuts during May, June and July, the producers group 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 their deeper cut we see above....

​there does not seem to be a table ​or listing available ​of how much each OPEC member was expected to produce under the newly eased cuts of August, so we'll include below the table which shows the October 2018 reference production for each of the OPEC members (as well as other producers party to the mid-April agreement), as well as the production level each of those producers was expected to cut their output to during May, June, and July....

the above table shows the oil production baseline in thousands of barrel per day from which each of the oil producers w​a​​s 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 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​ amends the above such that each member would be allowed to increase their May thru July production cut level (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, Algeria would reduce their "cut" by 20% to 193,000 barrels per day, allowing them to produce 864,000 barrels per day during August...offhand, it appears that only the UAE, who should have held their production under 2,690,000 barrels per day, has exceeded their quota for August...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 September 2018 to August 2020, and it comes from page 51 (pdf page 64) of the September 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....

including the 763,000 barrel per day increase in OPEC's production from what they produced a month earlier, OPEC's preliminary estimate indicates that total global oil production increased by a rounded 1.32 million barrels per day to average 89.88 million barrels per day in August, a reported increase which apparently came after July's total global output figure was revised down by 190,000 barrels per day from the 88.75 million barrels per day of global oil output that was reported a month ago, as non-OPEC oil production rose by a rounded 560,000 barrels per day in August after that revision, with oil production from Canada and Russia accounting for the lion's share of the non-OPEC increase in August...but even with the increase in August's global output, the 89.88 million barrels of oil per day that were produced globally in August were 10.01 million barrels per day, or 10.1% less than the revised 99.89 million barrels of oil per day that were being produced globally in August a year ago, the 8th month of OPECs first round of production cuts (see the September 2019 OPEC report (online pdf) for the originally reported August 2019 details)...with this month's increase in OPEC's output, their August oil production of 24,045,000 barrels per day rose to 26.8% of what was produced globally during the month, up from their revised 26.3% share in July, and up from the 25.4% share they contributed to global output in June...OPEC's August 2019 production, which included 537,000 barrels per day from former OPEC member Ecuador, was reported at 29,741,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 5,159,000, or 17.4% fewer barrels per day of oil in August than what they produced a year ago, when they accounted for 30.0% of global output...

Even with the increase in OPEC's and global oil output that we've seen in this report, there was still a shortfall in the amount of oil being produced globally during the month, as this next table from the OPEC report will show us...  

the above table came from page 27 of the September OPEC Monthly Oil Market Report (pdf page 40), 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 August, which is their estimate of global oil demand during the third quarter of 2020...

OPEC is estimating that during the 3rd quarter of this year, all oil consuming regions of the globe have been using an average of 91.45 million barrels of oil per day, which is a 650,000 barrels per day downward revision from the 92.10 million barrels of oil per day they were estimating for the 3rd quarter a month ago (​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....however, 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 only producing 89.88 million barrels per day during August, which would imply that there was a shortage of around 1,570,000 barrels per day in global oil production in August when compared to the demand estimated for the month... 

in addition to figuring th​at August ​oil ​shortage implied by this report, the downward revision of 190,000 barrels per day to July's global oil output that's implied in this report, combined with the 650,000 barrels per day downward revision to 3rd quarter demand that we've circled in green means that the3,350,000 barrels per dayglobal oil output shortage we had previously figured for July would now be revised to a shortage of 2,890,000 barrels per day....

Note that in green we've also circled a downward revision of 200,000 barrels per day to second quarter demand, a quarter when there was a​large excess of oil production...based on that downward revision to demand, our previous estimate that there was a surplus of 5,610,000 barrels per day in June would now be revised to a 5,810,000 barrels per day surplus, the oil surplus of 8,390,000 barrels per day that we had previously figured for May would have to be revised to a surplus of 8,590,000 barrels per day & the 17,140,000 barrels per day that we had previously figured for April would have to be revised to a surplus of 17,340,000 barrels per day... 

there was also an upward 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 17,788,000 barrels per day we had previously figured for March would have to be revised downward to a still record global oil surplus of 17,778,000 barrels per day, the 1,900,000 barrel per day global oil production surplus we had figured for February would now be a 1,890,000 barrel per day global oil output surplus, and the 930,000 barrel per day global oil output surplus we last had for January would now be revised to a 920,000 barrel per day oil output surplus.. so despite the shortage of oil that has developed in July and August, it's obvious the world's oil producers had produced a lot of oil earlier this year that no one wanted..​.​

This Week's Rig Count

the US rig count rose for the 3rd time in the past 28 weeks during the week ending September 18th, but it is still down by 68% over that twenty-eight week period....Baker Hughes reported that the total count of rotary rigs running in the US rose by 1 to 255 rigs this past week, which was still down by 613 rigs from the 868 rigs that were in use as of the September 20th report of 2019, and was also 149 fewer rigs than the all time low prior to this year, and 1,674 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 decreased by 1 rig to 179 oil rigs this week, after decreasing by 1 oil rig the prior week, leaving us with 540 fewer oil rigs than were running a year ago, and less than a eighth of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014....at the same time, the number of drilling rigs targeting natural gas bearing formations increased by two to 73 natural gas rigs, which was still down by 7​5 natural gas rigs from the 148 natural gas rigs that were drilling a year ago, and was also less than a twentieth of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008...in addition to those rigs drilling for oil & gas, three rigs classified as 'miscellaneous' continued to drill this week; one on the big island of Hawaii, one in Sonoma County, California, and one in the Permian basin in Eddy County, New Mexico...a year ago, there only one such "miscellaneous" rig deployed...

The Gulf of Mexico rig count fell by 1 to 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 9 fewer Gulf rigs than the 23 rigs drilling in the Gulf a year ago, when all 23 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 were also two rigs deployed offshore from Alaska, so this week's national offshore count is down by 11 from the national offshore rig count of 25 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 no rigs drilling in inland waters..

The count of active horizontal drilling rigs was up by 1 to 215 horizontal rigs this week, which was still 541 fewer horizontal rigs than the 756 horizontal rigs that were in use in the US on September 20th of last year, and less than a sixth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, the directional rig count was up by 21 to 23 directional rigs this week, but those were still down by 38 from the 61 directional rigs that were operating during the same week of last year....on the other hand, the vertical rig count fell by 2 to 17 vertical rigs this week, and those were also down by 34 from the 51 vertical rigs that were in use on September 20th of 2019....

The details on this week's changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes...the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of September 18th, the second column shows the change in the number of working rigs between last week's count (September 11th) and this week's (September 18th) count, the third column shows last week's September 11th 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 20th of September, 2019...    

as has been the case most of the summer, there were only a few changes in drilling activity again this week, with only four rig removals and just five rig additions, suggesting that prices are currently high enough that drillers are no longer trying to shut down money-losing operations, but not high enough to encourage the addition of new rigs to the field....checking the rig counts in the Texas part of Permian basin, we find that 2 rigs were added in Texas Oil District 8, which is the core Permian Delaware, while rig counts in the other Permian basin districts remained unchanged...since the national Permian basin rig count was down by one, that means that the three rigs that were pulled out of New Mexico must have been drilling in the far western Permian Delaware, to balance the national rig count on that basin...meanwhile, the Texas rig count is only up by one because the Gulf oil rig that was removed this week had been drilling in Texas waters...elsewhere, rig additions this week were in North Dakota's Williston basin, Louisiana's Haynesville, and West Virginia's Marcellus, with the latter two additions accounting for this week's increase in drilling for natural gas...

DUC well report for August

Monday of this past week also saw the release of the EIA's Drilling Productivity Report for September, which includes the EIA's August data for drilled but uncompleted oil and gas wells in the 7 most productive shale regions....for the 14th time in the past eightteen months, this report showed a decrease in uncompleted wells nationally in August, as completions of drilled wells increased while drilling of new wells remained unchanged....for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 77 wells, falling from 7,742 DUC wells in July to ​7,665 DUC wells in August, which was also 7.8% fewer DUCs than the 8,310 wells that had been drilled but remained uncompleted as of the end of August of a year ago...this month's DUC increase occurred as 292 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during August, the same number that were drilled in July, and hence matching lowest number of wells drilled in any month in the history of this report, while 369 wells were completed and brought into production by fracking, an increase of 95 well completions from the 274 completions seen in July, but still down by 73.4% from the 1,389 completions seen in August of last year....at the August completion rate, the 7,655 drilled but uncompleted wells left at the end of the month represents a 20.7 month backlog of wells that have been drilled but are not yet fracked, down from the 29.3 month DUC well backlog of a month ago, ​with the understand​ing that this normally indicative backlog ratio is being skewed by near record low completions...

both oil producing regions and natural gas producing regions saw DUC well increases in August, even as one natural gas basin saw a small​ ​DUC increase... the number of uncompleted wells remaining in the Oklahoma Anadarko decreased by 25, falling from 725 at the end of July to 700 DUC wells at the end of August, as just 10 wells were drilled into the Anadarko basin during August, while 35 Anadarko wells were being fracked...at the same time, DUCs in the Permian basin of west Texas and New Mexico decreased by 22, from 3,554 DUC wells at the end of July to 3,532 DUCs at the end of August, as 133 new wells were drilled into the Permian, while 155 wells in the region were completed....in addition, DUC wells in the Bakken of North Dakota decreased by 14, from 881 DUC wells at the end of July to 867 DUCs at the end of August, as 19 wells were drilled into the Bakken in August, while 33 of the drilled wells in that basin were being fracked...there was also a decrease of 10 DUC wells in the Eagle Ford of south Texas, from 1,187 DUC wells at the end of July to 1,177 DUCs at the end of August, as 15 wells were drilled in the Eagle Ford during August, while 25 already drilled Eagle Ford wells were completed...meanwhile, the drilled but uncompleted well count in the Niobrara chalk of the Rockies' front range was unchanged at 481, as 20 new Niobrara wells were drilled in August while 20 drilled Niobrara wells were being fracked...

among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, fell by 10 wells, from 601 DUCs at the end of June to 591 DUCs at the end of August, as 61 wells were drilled into the Marcellus and Utica shales during the month, while 71 of the already drilled wells in the region were fracked....on the other hand, the natural gas producing Haynesville shale of the northern Louisiana-Texas border region saw their uncompleted well inventory increase by 4 to 317, as 34 wells were drilled into the Haynesville during August, while 30 of the already drilled Haynesville wells were fracked during the same period....thus, for the month of August, DUCs in the five major oil-producing basins tracked by this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a net of 71 wells to 6,757 wells, while the uncompleted well count in the natural gas basins (the Marcellus, Utica, and the Haynesville) decreased by 6 wells to 908 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas...

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Columbia Gas pipeline project would move gas under the Scioto River - Columbia Gas of Ohio is planning an expansion project that would transport gas under the Scioto River north of Columbus. The project is necessary to ensure that supplies of natural gas remain adequate to serve growing areas northwest of the city. Columbia Gas of Ohio is planning to expand its pipeline system to meet growing demand for gas in an area that extends from northwestern Franklin County into Delaware and Union counties. The routes that the natural gas distribution company is considering for the project would transport natural gas under the Scioto River. Called the Northern Loop, the project begins at Hyatts Road in Delaware County, where earlier segments of the Northern Loop end. It extends to U.S. 42 and down to U.S. 33 to McKitrick Road near Hyland Croy Road in Union County, where gas will enter existing lines. The project will bring natural gas from pipelines on the eastern side of Franklin County, where supplies are abundant, to areas north and west of Columbus. Columbia Gas expects construction to begin in 2022. The cost is projected at $100 million to $110 million. “It ensures upstream capacity is available to meet the growth that continues to occur in the northwest part of our system,” said Vince Parisi, president and chief operating officer of Columbia Gas of Ohio. Several phases of the project already have been completed, bringing the line to Delaware County. The final phase loops from southern Delaware County to southeastern Union County, where it will connect to the existing gas distribution system. The project will consist of 11 miles of 24-inch pipe and 4 miles of 16-inch pipe.

Fitch downgrades Encino Acquisition Partners' ratings to B from B+ -- Fitch Ratings on Sept. 14 said it has lowered the long-term issuer default ratings for Encino Acquisition Partners LLC and Encino Acquisition Partners Holdings LLC to B from B+. The ratings outlook is negative. The rating agency also downgraded the two companies', or Encino's, senior secured second-lien term loan to B/RR4 from BB-/RR3, according to a news release. Fitch said the downgrades reflect the agency's expectations that Encino's production may be lower than planned due to decreased drilling following a drop in natural gas and NGL prices early this year. Encino, the second-largest producer in the Ohio Utica Shale, has recorded a 25% production increase since it acquired Chesapeake Energy Corp.'s Utica Shale assets in 2018, according to the release. Fitch anticipates Encino's production to increase by 20% more during the year. Additionally, the rating agency said it does not expect Encino to be able to generate positive free cash flow this year and in 2021, which may lead to an increase in its borrowings on its revolver due in 2023. Fitch said Encino's anticipated inability to generate positive free cash flow and its "challenged ability to access debt capital markets" are expected to potentially impact the companies' capacity to refinance its revolver and term loan due in 2025. Encino has a $2 billion reserve-based credit facility due 2023, of which roughly $465 million has been drawn as of June. Encino was formed by Encino Energy LLC and the Canada Pension Plan Investment Board.

EQT Corp. in Talks With Chevron for Assets in Appalachia - EQT Corporation has keen interest in Chevron Corporation’s stakes in the Appalachian basin and a pipeline asset, per Reuters. The leading U.S. natural gas producer has offered $750 million for the properties, added the source. Notably, the assets Chevron is willing to sell comprise roughly 800,000 acres in the prolific Marcellus and Utica shale plays along with a 31% non-operating stake in Laurel Mountain Midstream. The midstream firm provides services to the Marcellus shale area through its intrastate and gathering pipelines.  According to the source, Chevron is now evaluating the company’s bid for the assets. The latest bid probably reflects EQT Corp.’s willingness to purchase the assets at bargain prices since the challenging business scenario has slashed commodity prices. However, the source added that although the companies are discussing the potential transaction, there is no assurance that Chevron will divest the properties.  The source added that on a per-day basis, the Appalachian properties produced 262 million cubic feet of natural gas in 2019.

Exclusive: EQT bids for Chevron U.S. shale-gas assets in Appalachia - sources (Reuters) - EQT Corp, the largest U.S. natural gas producer by volume, has placed a bid on Chevron Corp’s Appalachia gas properties and a pipeline stake, people familiar with the matter said. EQT offered $750 million (578.53 million pounds) for the properties, one of the people familiar with the matter said. Chevron last year said it was considering sale of the properties and took an $8.17 billion charge to earnings to write down their value and an unrelated U.S. offshore project. Most of the impairment charge was for the gas properties. Chevron is marketing about 800,000 acres in the Marcellus and Utica shale basins of Pennsylvania and neighboring states and a 31% non-operating interest in Laurel Mountain Midstream, which has intrastate and gathering lines servicing the Marcellus shale area. EQT declined to comment. EQT Chief Executive Toby Rice in July described Appalachia shale as “a buyer’s market,” and called consolidation an opportunity for the Pittsburgh-based company. Bids for the properties were received on Aug. 12 and are being evaluated, Chevron said in response to inquiries. It declined to comment on the bids. There is no guarantee the talks will lead to a sale to EQT or another company. The shale assets are from Chevron’s purchase of producer Atlas Energy for $4.3 billion including debt in 2010, a time when shale gas fields were selling at large premiums. A year earlier, Exxon Mobil Corp. agreed to pay $30 billion for XTO Energy, then a large Appalachian shale basin operator. The deals soured for both companies. In addition to Chevron’s writedown, Exxon later took a $2 billion writedown on the value of its natural gas assets. U.S. natural gas futures are trading at about $2.27 a million British Thermal Units (BTUs) and have languished well below their peak 12 years ago when gas traded as high as $12.78 per million British Thermal Units. The Appalachian assets last year produced 262 million cubic feet of natural gas, on a net daily basis. EQT had average daily sales volumes of about 4.1 billion cubic feet equivalent.

More Drops in Gas, Oil Production in Utica, Marcellus – Oil and gas production in the Utica and Marcellus shale formations is expected to decrease again next month, the U.S. Energy Information Administration reports. The agency said in its monthly drilling productivity report that natural gas production across the Appalachian basin is projected to drop by 162 million cubic feet per day in October compared to September. Much of the Utica shale is drilled in eastern Ohio, while the Marcellus shale is found mostly in western Pennsylvania and West Virginia. Collectively, the EIA refers to both plays as the Appalachian Basin. The EIA reported that the region should produce 32.835 billion cubic feet of gas per day in October, down from 32.997 billion cubic feet this month. Six of the seven major shale plays across the country are projecting lower output next month compared to September, according to the EIA. A single shale play, the Permian Basin in Texas, was the sole region that is projected to post an increase in October. Oil production is also expected to drop in Appalachia. The Utica and Marcellus are projected to yield 134,000 barrels of oil per day, down by 1,000 barrels from September, the agency reported. The EIA reports five of the seven shale regions expect decreases in oil production next month.

New fracking wells are down in Pennsylvania, but natural gas production hits record - More natural gas was fracked from Pennsylvania wells in 2019 than in any previous year, although the number of new wells drilled declined, according to the state Department of Environmental Protection. Meanwhile, DEP reported environmental violations in 14% of its inspections, and collected fines of $4.1 million. The DEP’s 2019 Oil and Gas Annual Report, released Monday, shows 6.8 trillion cubic feet of natural gas was produced last year from the state’s Marcellus and Utica shale gas formations, topping the 2018 production total of 6.2 trillion cubic feet and continuing an upward trend that has gone on for more than a decade. Pennsylvania is the second-largest producer of natural gas in the U.S., behind Texas.

Natural gas production in Pennsylvania hits record high - Pennsylvania’s natural gas drillers extracted the largest volume of gas on record for a single year in 2019, according to the Department of Environmental Protection’s latest annual report on the industry. Unconventional drillers extracted 6.8 trillion cubic feet of natural gas last year, a more than 10 percent increase from 2018. The number of new wells drilled with hydraulic fracturing has been on a downward trend since a peak in 2014. Companies drilled 615 new wells in 2019, down from 777 the year before. Pennsylvania doesn’t tax the gas companies extract, but charges a per-well impact fee. That fell last year, according to the state’s Independent Fiscal Office. The IFO also reports the rate of growth for gas production has been ticking down since a high point in mid-2018, likely due to persistently low prices. Gas company representatives tout the industry’s growth and 90 percent drilling fluid recycling rate as good for the state’s economy and environment. “And we’re doing so with an exceptional inspection compliance rate, reflecting our commitment to safety, operational excellence and public health,” said Marcellus Shale Coalition president David Spigelmyer. A recent grand jury report detailed numerous health and environmental impacts of the natural gas industry and called out state regulators as unprepared to corral the industry during the start of the gas rush. DEP conducted more than 35,000 inspections across both conventional and unconventional well sites and collected $4 million in fines. The agency found 985 compliance violations out of nearly 19,000 inspections at unconventional sites. At conventional sites, inspectors found 1,763 violations from 12,000 visits. Conventional operators drill vertical wells that are shallower compared to unconventional operators, which use horizontal drilling and hydraulic fracturing to reach deeper deposits of oil and natural gas in rock formations like Pennsylvania’s Marcellus shale. The state’s more than 70,000 conventional wells produced about 71 billion cubic feet of gas in 2019. There are about 8,400 active unconventional wells. The latest report also documents nearly 12,000 abandoned wells. DEP estimates there could be as many as 200,000 of them, many of which predate regulatory oversight. The orphan wells can leak methane into the air and possibly contaminate groundwater or surface water.

State orders reroute of part of natural gas pipeline (AP) — State environmental authorities have ordered Sunoco to reroute a portion of its Marine East 2 natural gas liquids pipeline in southeastern Pennsylvania following last month's spill of more than 8,000 gallons of drilling fluid into a wetland area. The Pennsylvania Department of Environmental Protection halted drilling stopped after the Aug. 10 spill into wetlands and a tributary of Marsh Creek Lake in Chester County. About 33 acres of the 535-acre lake, located in a state park, were placed off limits to boating and fishing during cleanup. Secretary Patrick McDonnell called it “yet another instance where Sunoco has blatantly disregarded the citizens and resources of Chester County with careless actions while installing the Mariner East 2 pipeline." “We will not stand for more of the same," he said in a statement. “An alternate route must be used.” Lisa Coleman, a spokeswoman for Energy Transfer, which owns Sunoco, said the company was examining the order and would work closely with the department “as we have done throughout the duration of this project." “Our first priority remains the safe completion and then operation of this important infrastructure project,” she said. Sunoco has 30 days to file an appeal that would send the matter to the state Environmental Hearing Board, department spokesperson Virginia Cain said. Sunoco had to propose an alternate route for the 20-inch pipeline in 2017 after a spill that year, and Friday's order directs the company to use that route, she said. The new route would run for a little over a mile in an area north of where the current pipeline drilling is taking place. It would still cross two waterways and forested wetlands, and would be closer to five homes, The Philadelphia Inquirer reported. Exploration firms drilling in the booming Marcellus Shale and Utica Shale fields ship natural gas liquids through the Mariner East pipelines to Marcus Hook refinery and export terminal near Philadelphia, helping the U.S. become the world’s leading ethane exporter.

Pennsylvania orders Sunoco to reroute section of Mariner East 2 NGL pipe(Reuters) - Pennsylvania environmental regulators ordered Energy Transfer LP’s Sunoco Pipeline unit to reroute a section of the Mariner East 2 natural gas liquids pipeline after spilling 8,000 gallons of drilling fluid in Marsh Creek State Park in August. Analysts at Height Capital Markets said on Monday the reroute could delay an upgrade to the already operating Mariner East 2 project that was expected to be completed in the second quarter of 2021. Officials at Energy Transfer were not immediately available for comment. The Pennsylvania Department of Environmental Protection said late Friday the Marsh Creek spill caused the park to close 33 acres (13 hectares) of the lake from boating and other recreational uses. “These incidents are yet another instance where Sunoco has blatantly disregarded the citizens and resources of Chester County with careless actions while installing the Mariner East II Pipeline,” DEP Secretary Patrick McDonnell said in a statement. The reroute order was the latest in a long series of sanctions against the company for violations of its permits during construction of Mariner East 2. Since May 2017, Pennsylvania has issued 115 notices of violation to Mariner East, mostly for drilling fluid spills, including one in September. Pennsylvania has fined the company and stopped construction on the pipe several times. Several politicians and local groups have long urged the state to stop work again and shut the pipe. Mariner East transports liquids from the Marcellus and Utica shale in western Pennsylvania to customers in the state and elsewhere, including international exports from Energy Transfer’s Marcus Hook complex near Philadelphia. Sunoco started work on the $2.5 billion Mariner East expansion in February 2017 and had planned to finish the 350-mile (563-km) pipeline in the third quarter of 2017. But completion was delayed until December 2018 due to several work stoppages by state agencies.

Over 43,000 Demand Feds Reject Extension of Fracked Gas Pipeline Permit Timeline — Water and climate advocacy organizations submitted comments and signatures from more than 43,000 people demanding the Federal Energy Regulatory Commission (FERC) deny the fracked gas Mountain Valley Pipeline more time to construct the pipeline. Developers of the controversial project, which is billions of dollars over budget and years behind schedule, asked FERC for a two-year extension of a certificate it needs to continue construction. 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.  The comments and petition signatures were collected by the Sierra Club, Appalachian Voices, Chesapeake Climate Action Network, Food and Water Watch, Friends of the Earth Action, Beyond Extreme Energy, 198 Methods, and the NC Alliance to Protect Our People and the Places We Live. They represent people from West Virginia, Virginia, and North Carolina. The Sierra Club and several of its allies also moved to intervene in the proceeding and submitted comments opposing the extension request. Additionally, senators Tim Kaine and Mark Warner have asked FERC to extend the public comment period on MVP’s request, asking for 30 days because the 15 currently granted are “inadequate.” In response, the following coalition organizations fighting the Mountain Valley Pipeline issued the following statements:

Top Marcellus CEO urges government help to boost infrastructure projects - A key Pittsburgh-based natural gas CEO told the presidential's economic adviser and the U.S. energy secretary that natural gas producers need government help in building infrastructure in the face of strong and effective environmental opposition.Richard D. Weber, the chairman and CEO of PennEnergy Resources, said the Marcellus and Utica Shale revolution of the past 15 years has created clean, low-cost energy with the three-state region of Pennsylvania, West Virginia and Ohio producing about 32 billion cubic feet of natural gas per day. It's the largest natural gas field in the world and a big reason why the United States being the largest producer of natural gas on Earth. But, Weber said, production exceeds the local markets. "We have to be able to move our product around the country and also overseas," Weber said Thursday afternoon at the virtual National Gas Summit that was held by the U.S. Department of Energy.Weber said opponents in the environmental sector are well-funded and have targeted infrastructure projects — mainly pipelines but also liquified natural gas export terminals — as an effective way to stop natural gas production. He pointed to the cancellation of the Atlantic Coast Pipeline over the summer after billions of dollars already invested. He called the Mountain Valley Pipeline, owned by Pittsburgh-based Equitrans Midstream Corp. (NYSE: ETRN) and stalled by lawsuits and regulatory action, at risk due to opposition. "What we need as an industry, we need support from the federal government to permit intelligent infrastructure development and that also includes the ability to export our products," Weber said.Other panelists at the summit agreed. Mike Sommers, president and CEO of the American Petroleum Institute, likened activists as trying to "step on the hose" between supply and demand. Kathleen Sgamma, president of the Western Energy Alliance, said that Oregon was blocking western states' attempts to ship natural gas overseas via terminal on what she called "ideological opposition." Weber's request found a welcome reception in the host, Energy Secretary Dan Brouillette, and the moderator, Larry Kudlow, director of the United States National Economic Council and a key adviser to President Donald J. Trump. "What is challenging us, and what I think is challenging the industry, is an infrastructure problem," Brouillette said. "We need more pipelines, we need more export facilities. We have to improve our permitting processes so we can allow this infrastructure to be built quickly and more efficiently."

DEQ required Dominion to pay $1.5 million for potential, actual damage from Atlantic Coast Pipeline - Dominion Energy paid more than $1.5 million to the NC Department of Environmental Quality to offset potential and actual damage from the construction and operation of the now-defunct Atlantic Coast Pipeline. The payment, made in February 2018 to the Division of Mitigation Services, was part of a state program for impacts to water quality and stream and river buffers. Both state and federal regulators require developers to pay a third-party or conduct mitigation themselves if their projects unavoidably damage waterways or buffers. Under the state’s in-lieu fee mitigation program, a state agency like DMS, or a nonprofit organization, sells credits to developers, in this case, Dominion. The payment is required in advance of construction, and DMS or the nonprofit is responsible for the mitigation project’s success. In some instances, the developer chooses to hire a contractor and pay for its own mitigation. Just under half of the funds Dominion paid to DMS — $719,240 — were allocated for buffer projects in Upper Tar River and Fishing Creek sub-basins. This area includes the cities of Rocky Mount, Nashville and Enfield, where the pipeline would have routed. Another $849,000 was allocated to buffer projects in the Upper Neuse River and Contentnea sub-basins, which include Smithfield, Selma and Wilson, also along the proposed route.

Enbridge Asks to Start Up Compressor in Two Weeks - Less than a week after workers vented an unspecified amount of natural gas as part of an emergency shutdown, energy giant Enbridge asked federal regulators for the green light to start up a Weymouth compressor station in two weeks.The company filed a request Wednesday to place the station on the banks of the Fore River, between densely packed neighborhoods in Quincy Point and North Weymouth, in service by Oct. 1, asking for a decision by Sept. 24 so its customers have a chance to prepare for gas supplies. "In order to meet the needs of our project customers ahead of the upcoming winter heating season, we are requesting approval to place the Weymouth Compressor Station in service by October 1, 2020," Enbridge spokesman Max Bergeron wrote in a Thursday morning email. "The Weymouth Compressor Station will enable three local gas utilities in Maine and one in Canada to benefit from additional access to natural gas, helping homes and businesses switch from higher-emitting fuels to cleaner-burning natural gas."The station is currently in the testing process after a lengthy permitting fight. On Friday, a gasket failure prompted crews to trigger an emergency shutdown and release at least 10,000 cubic feet of natural gas.  Following the incident, Congressman Stephen Lynch urged the U.S. Department of Transportation to shut down the project immediately for additional oversight before work proceeds, warning that it poses "an immediate public safety threat to the residents of Weymouth and its surrounding communities."  Massachusetts Energy and Environmental Affairs Secretary Kathleen Theoharides said Enbridge followed the proper safety and notification protocols after the gasket failure, and rather than shutting down Enbridge is angling to ramp up operations. Enbridge is seeking the Weymouth station as part of its Atlantic Bridge pipeline infrastructure.

Natural gas line explosion leaves crater-sized hole near Piedmont— Numerous agencies responded to the scene of a natural gas explosion Wednesday night near Piedmont. Officials said a 12-inch pipeline running under Waterloo Road near Piedmont Road exploded, creating a crater all across the roadway. Police told KOCO 5 that it's a rural area and very few residents live nearby. The police chief said there are no injuries that he knows of and no evacuations were issued. The police chief said there could be a lot of other intersecting power lines near the initial line that was ruptured, which could impact power. Cimarron Power responded to the scene, and police said other agencies will be notified if they are affected. The explosion left behind a crater-sized hole that's roughly 35 feet long and 20 feet wide. Crews were still putting out hot spots Thursday morning. Officials with CimarronElectric Cooperative said they lost six power poles in the pipeline explosion.

Cause of natural gas line fire under investigation in Fort Smith — Investigators from the Arkansas Oklahoma Gas Corp. were at the intersection of Massard Rd. and Zero street to determine the cause of a natural gas fire that broke out last night. "We're looking at every possibility to define what actually caused the incident," said Fred Kirkwood, AOG Chief Customer Officer. "It's basically a gathering point for a number of gas lines as they come into one point for monitoring, measuring and distribution back into the system." The fire was first reported to Fort Smith dispatchers shortly after 9:00 Wednesday evening. The Fort Smith fire chief said a high pressure transmission line carrying natural gas ruptured and resulted in the fire. The line was owned by Arkansas Oklahoma Gas and crews were battling flames until the company could shut it down. Crews worked about four hours to suppress the flames while they were waiting for the gas company to turn the gas off. "They had to get the situation under control where it was safe to go in and shut the gas off," said Kirkwood. Shawn Fuller, incident commander and fire battalion chief in Fort Smith, said their main focus was protecting nearby buildings and nearby transmission lines. Fuller said there were five other transmission lines, owned by five other gas companies, that needed protection from the flames. "It's safer for the fire to be burning because you know where the gas is at that point so you can protect the exposures around it," said Mark Talley, Division Chief of Operations, for the Fort Smith Fire Department. "If the fire's out and the gas is leaking, you don't know where it's going. It could or it will find an ignition source."

U.S. natgas futures rise near 2% as output falls ahead of Hurricane Sally (Reuters) - U.S. natural gas futures rose near 2% on Monday as liquefied natural gas exports continued to rise and output dipped as Gulf Coast producers shut some production before Hurricane Sally smashes into the Gulf Coast. Sally is expected to hit near the Louisiana-Mississippi border early on Tuesday. Entergy Corp , the biggest power company in Louisiana and Mississippi, still has about 50,000 customers without service from Hurricane Laura in southwestern Louisiana since late August. After falling to a four-week low last week, front-month gas futures rose 4.1 cents, or 1.8%, to settle at $2.310 per million British thermal units. Data provider Refinitiv said output in the Lower 48 U.S. states was on track to slide to a two-week low of 86.1 billion cubic feet per day on Monday due to a near 1-billion-cubic-feet-per-day (bcfd) decline in the Gulf Coast. Traders noted futures rose despite a decline in overall demand as the weather turns mild. Refinitiv projected demand, including exports, would slide from 85.3 bcfd this week to 82.4 bcfd next week. The amount of gas flowing to U.S. LNG export plants, meanwhile, was on track to average 5.1 bcfd in September. That is the most in a month since May and up for a second month in a row for the first time since hitting a record high of 8.7 bcfd in February. The LNG-export gain comes as Cheniere Energy Inc's Sabine Pass in Louisiana ramps up after shutting in late August for Hurricane Laura and as global gas prices rise, making U.S. gas more attractive in Europe and Asia following months of U.S. cargo cancellations due to coronavirus demand destruction. Cameron LNG's export plant in Louisiana, however, has remained shut since Aug. 27 due to lingering power outages from Laura. Some analysts say the plant could remain shut through mid October.

U.S. natgas up over 2% as producers cut output for Hurricane Sally   (Reuters) - U.S. natural gas futures gained over 2% on Tuesday as output fell after producers shut some Gulf of Mexico wells before Hurricane Sally smashes into the coast. That price rise came despite forecasts for milder weather and lower cooling demand over the next two weeks and a continued rise in liquefied natural gas exports. Sally is expected to hit near the Mississippi-Alabama border early Wednesday - far from any operating LNG export plants. There were no power outages from Sally yet. But Entergy Corp, the biggest power company along the Gulf Coast, still has about 50,000 customers without service in southwestern Louisiana since late August from Hurricane Laura, including the Cameron LNG export plant. Front-month gas futures rose 5.2 cents, or 2.3%, to settle at $2.362 per million British thermal units. Data provider Refinitiv said output in the Lower 48 U.S. states was on track to slide to a 16-week low of 84.6 billion cubic feet per day (bcfd) on Tuesday due to Sally-related shutdowns. The U.S. Bureau of Safety and Environmental Enforcement (BSEE) said almost 0.8 bcfd, or 28%, of Gulf of Mexico gas production was shut-in. With cooler weather coming, Refinitiv projected demand, including exports, would fall from 84.8 bcfd this week to 81.9 bcfd next week. The amount of gas flowing to U.S. LNG export plants, meanwhile, has averaged 5.2 bcfd so far in September. That is the most in a month since May and up for a second month in a row for the first time since hitting the 8.7-bcfd record high in February. The LNG-export gain comes as Cheniere Energy Inc's Sabine Pass in Louisiana ramps up after shutting in late August for Hurricane Laura and as global gas prices rise, making U.S. gas more attractive following months of U.S. cargo cancellations due to coronavirus demand destruction.

U.S. natgas futures fall to four-week low on mild weather forecasts  (Reuters) - U.S. natural gas futures fell 4% to a four-week low on Wednesday on forecasts for milder weather and lower cooling demand over the next two weeks. The price decline came despite a continued rise in liquefied natural gas exports and a drop in output to its lowest in two years as producers shut wells for Hurricane Sally. Sally, now a tropical storm, knocked out power to around 570,000 homes and businesses in Alabama and Florida after smashing into the Alabama coast early Wednesday. The storm is expected to stay far from LNG export plants as it moves toward Georgia and South Carolina. Front-month gas futures fell 9.5 cents, or 4.0%, to settle at $2.267 per million British thermal units, their lowest since Aug. 13. After the close, prices fell over 5%. Data provider Refinitiv said output in the Lower 48 U.S. states was on track to fall to 84.1 billion cubic feet per day (bcfd), its lowest since August 2018, due to Sally-related shutdowns. The U.S. Bureau of Safety and Environmental Enforcement (BSEE) said 0.8 bcfd, or 30%, of Gulf of Mexico gas production was shut-in. With cooler weather coming, Refinitiv projected demand, including exports, would fall from 85.2 bcfd this week to 81.8 bcfd next week. The amount of gas flowing to U.S. LNG export plants, meanwhile, averaged 5.3 bcfd so far in September. That was the most in a month since May and was up for a second month in a row for the first time since hitting a record 8.7 bcfd in February as global gas prices rise, making U.S. gas more attractive following months of U.S. cargo cancellations due to coronavirus demand destruction. Cameron LNG's export plant in Louisiana, however, remained shut since Aug. 27 due to lingering power outages from Hurricane Laura. Some analysts say the plant could be getting closer to returning to service.

U.S. natgas futures dive nearly 10% to 6-week low on big storage build  (Reuters) - U.S. natural gas futures tumbled almost 10% to a six-week low on Thursday as a bigger-than expected storage build last week kept stockpiles on track to reach record highs by the end of October. The U.S. Energy Information Administration (EIA) said utilities injected 89 billion cubic feet (bcf) of gas into storage in the week ended Sept. 11. That is higher than the 79-bcf build analysts forecast in a Reuters poll and compares with an increase of 82 bcf during the same week last year and a five-year (2015-19) average build of 77 bcf. Even before the EIA released its report, prices were already under pressure with output expected to rise from a two-year low as producers return wells shut-in for Hurricane Sally and on forecasts calling for milder weather and lower cooling demand over the next two weeks. Front-month gas futures fell 22.5 cents, or 9.9%, to settle at $2.042 per million British thermal units, their lowest since July 31. That was the contract's biggest one-day percentage loss since January 2019. "The magnitude of today’s decline strongly suggested some margin call selling as remaining recently acquired speculative longs were forced to liquidate," said Jim Ritterbusch, president of Ritterbusch and Associates in Galena, Illinois. In recent weeks, speculators had boosted their net long positions to the highest in almost three years despite expectations record stockpiles would make price spikes and gas shortages unlikely this winter. Data provider Refinitiv said output in the Lower 48 U.S. states was on track to rise to 85.3 billion cubic feet per day (bcfd) on Thursday from a two-year low of 84.8 bcfd on Wednesday due to Sally-related shutdowns. With cooler weather coming, Refinitiv projected demand, including exports, would fall from 85.3 bcfd this week to 81.9 bcfd next week.

US working natural gas volumes in underground storage rise by 89 Bcf: EIA | S&P Global Platts  Total additions to US natural gas in storage last week surprised to the upside, prompting a selloff in the Henry Hub prompt futures market with a much smaller declines seen for the winter 2020-21 contracts. Storage inventories increased by 89 Bcf to 3.614 Tcf for the week ended Sept. 11, the US Energy Information Administration reported the morning of Sept. 17. The injection was significantly higher compared with S&P Global Platts' survey of analysts calling for a 77 Bcf build. Responses to the survey ranged from an injection of 68 Bcf to 80 Bcf. The injection was also more than the 82 Bcf build reported during the same week last year and 12 Bcf above the five-year average gain of 77 Bcf, according to EIA data. Storage volumes now stand 535 Bcf, or about 17%, above the year-ago level of 3.079 Tcf and 421 Bcf, or 13%, higher than the five-year average of 3.193 Tcf. Following release of the EIA's storage report, the Henry Hub prompt-month futures contract dropped by over 20 cents to trade in the low $2/MMBtu area, data from the CME Group showed. The downward pressure extended only partially to the November futures contract, which dropped about 14 cents to around $2.50/MMBtu. The December, January and February contracts came under significantly less pressure during morning trading, falling only about 5 cents. While total US storage volumes continue to hover well above five-year average levels, the additional underground supply hasn't countered the market's bullish sentiment for winter 2020-21. Since the start of August, the winter gas contracts have gained about 20 cents and continue to trade in the low-$3/MMBtu area. The upward pressure comes as dramatic cuts in drilling budgets and rig counts this year have left US gas production sputtering around 87 Bcf/d – about 8 Bcf/d, or more than 8%, below its record-high monthly average recorded in November 2019. At current activity levels, US output would remain around its current 87 Bcf/d level through at least mid-2021, recent forecasts from S&P Global Platts Analytics show. On Sept. 17, the US rig count was estimated at 293 amid a modest but bumpy rebound from its 15-year low level at just 279 rigs in July. In January 2020, the US rig count had totaled over 840 rigs – already significantly below a prior, multiyear high at nearly 1,200 rigs in early 2019, data from Enverus DrillingInfo showed. Heading into mid- to late-September, upcoming storage reports from the EIA could add more bullish sentiment to a market already concerned over recent upstream supply cuts. For the week currently in progress, the EIA is likely to announce an injection of just 66 Bcf, according to a recent forecast from Platts Analytics. Assuming the forecast holds, the injection to US stocks for the week ending Sept. 18 would fall short of the five-year average by 14 Bcf.

U.S. natgas holds near 7-wk low as rising output offsets higher LNG exports  (Reuters) - U.S. natural gas futures held near a seven-week low on Friday as rising output in the Gulf of Mexico after Hurricane Sally offset an increase in liquefied natural gas (LNG) exports. Front-month gas futures rose 0.6 cents, or 0.3%, to settle at $2.048 per million British thermal units (mmBtu). On Thursday, the contract closed at its lowest since July 31. That put the front-month down about 9% for the week and helped boost the November futures premium over October NGV20-X20 to a record 61 cents per mmBtu. Data provider Refinitiv said output in the Lower 48 U.S. states rose to 86.3 billion cubic feet per day (bcfd) on Thursday from a three-month low of 84.8 bcfd on Wednesday as producers started returning Gulf of Mexico wells shut-in for Sally. The storm smashed into the Gulf Coast near the Alabama-Florida border early Wednesday. With cooler weather coming, Refinitiv projected demand, including exports, would fall from an average of 85.5 bcfd this week to 82.7 bcfd next week before rising to 83.9 bcfd in two weeks as LNG exports increase. The amount of gas flowing to U.S. LNG export plants was on track to reach 7.6 bcfd on Friday, its highest in a day since April. For the month, LNG feedgas averaged 5.5 bcfd so far in September. That was the most in a month since May and was up for a second month in a row for the first time since hitting a record 8.7 bcfd in February as global gas prices rise, making U.S. gas more attractive. Cameron LNG's export plant in Louisiana, however, remained shut since Aug. 27 due to lingering power outages from Hurricane Laura. Sempra Energy, one of Cameron's partners, said it expects the facility will be in full operation in six weeks. 

U.S. natural gas exports have been declining since April - In 2017, the United States exported more natural gas than it imported on an annual basis for the first time in nearly 60 years, making it a net natural gas exporter. Since then, U.S. net natural gas exports have more than doubled every year: from 0.3 billion cubic feet per day (Bcf/d) in 2017 to 2 Bcf/d in 2018 and to 5.2 Bcf/d in 2019. Although growth in net natural gas exports continued in the first six months of 2020 (compared with the same period in 2019), net exports began declining in spring 2020 as a result of a global economic slowdown amid the spread of the coronavirus disease (COVID-19) and related containment efforts. Starting in April, U.S. natural gas traded as liquefied natural gas (LNG) and by pipelines declined significantly, according to the U.S. Energy Information Administration’s (EIA) recently released Natural Gas Monthly, which includes data through June 2020.The United States is a net exporter of LNG and natural gas by pipeline to Mexico and is a net importer of natural gas by pipeline from Canada. In the first half of 2020, net exports of natural gas averaged 7.3 Bcf/d, or nearly 80% (3.2 Bcf/d) more than during the same period last year. In the first six months of 2020, net LNG exports increased by almost 60% (2.4 Bcf/d), net pipeline exports to Mexico increased by 4% (0.2 Bcf/d), and net imports by pipeline from Canada declined by 12% (0.6 Bcf/d) compared with the first six months of 2019.Between 2017 and 2019, growth in LNG exports led the increase in net natural gas exports. Since the first LNG cargo was exported from the Lower 48 states in February 2016, both U.S. LNG export capacity and volumes have grown substantially. In 2020, U.S. LNG export capacity continued year-over-year growth as the third trains atFreeport LNG and Cameron LNG were placed in service. EIA estimates that U.S. LNG baseload operating liquefaction capacity currently stands at 8.9 Bcf/d (10.1 Bcf/d peak) across six LNG facilities with 14 full-size trains and 10 small-scale moveable modular liquefaction system trains.U.S. LNG exports continued to grow in the first three months of 2020, averaging 7.9 Bcf/d, a 3.9 Bcf/d (98%) increase compared with the same period last year. LNG exports started to decline in April amid global reduction in natural gas consumption and a decline in global natural gas and LNG prices. In June 2020, U.S. LNG exports averaged 3.6 Bcf/d, or less than half of January’s LNG exports, and they continued to decline in July to 3.1 Bcf/d. U.S. LNG imports in the first half of 2020 were similar to imports in the first half of 2019, averaging 0.2 Bcf/d. About one-half (56%) of LNG imported in the first six months of 2020 went to the Everett LNG terminal (located offshore from Boston, Massachusetts), primarily to meet New England’s winter space heating demand. Several LNG cargoes were also imported to Cove Point terminal in Maryland and Elba Island terminal in Georgia.

How Much Oil Did Hurricane Laura Spill? Answer Is Still Unknown, But Sheen Is Widespread - Hurricane Laura made landfall near more than 1,400 active and more than 480 orphaned oil wells on the Louisiana coast, and recent aerial photos show a sheen of oil spanning miles floating on top of the storm’s receding water. Louisiana’s Department of Natural Resources (DNR) spokesman Patrick Courreges says it’s too soon to tell how much oil spilled due to Hurricane Laura, as investigation continues into orphaned wells. Photographer Julie Dermansky joined David Levy, owner of Petrotechnologies and founder of the Free Iberian Press, on a flight to photograph the coast from above. Dermansky says that she photographed oil sheen along at least 20 miles of marsh and bayous of the Louisiana coast near the Texas border. As the storm approached, the DNR requested oil and gas industry operators to take preventative measures to reduce impacts and spills. The state can hold accountable any operators who failed to take appropriate action if environmental impacts later followed. However, Courreges explained, “If you are asking for a 100% infallible protection system that absolutely guarantees nothing can go wrong ever, even in the face of 150-plus mph winds and hurricane-grade storm surge, I don’t think any agency or policy can promise that. The state and the operators do what they can to prepare for such things, and to mitigate potential impacts, but total prevention of damage is probably not achievable.” The DNR makes orphaned sites a priority, and is now in the process of assessing each of the abandoned sites in Laura’s path. Courreges said it’s likely that no one other than the state will be checking on orphaned wells, as they no longer have an operator or owner to report leaks. The DNR also responds to active oil wells that have experienced issues as they’re reported. Langley clarified that while several spill reports have been filed, no major oil spills have been observed. According to a U.S. Environmental Protection Agency report reviewed by New Orleans Public Radio, the U.S. Coast Guard’s National Response Center had received 31 reports of oil and chemical spills related to Hurricane Laura by Aug. 29, most of which occurred in coastal waters. Two of those calls came from the BioLab Inc. chemical plant in Westlake, Louisiana, which caught fire and released chlorine gas into the air during the storm. Another report was made about a crude oil spill in Cameron Parish, in which an unknown quantity of crude oil was spilled into a marsh. The report detailed that the spill was blocked by “secondary containment,” so it didn’t spread further than the marsh. Langley said that cleanup entails containing each leak, assessing environmental impact and, if possible, identifying a responsible party. "If a responsible party is found, they are ordered to submit a cleanup plan and provide resources to carry out the plan. If there is not a responsible party, as with an orphan drum, one of the cleanup funds may be used to pay for the work," he explained. The low-lying Louisiana coastline is particularly vulnerable to the perils of climate change and rising sea levels. The state loses about a football field of coast per day according to a U.S. Geological Survey conducted in 2019. Louisiana is the ninth largest oil producer in the U.S., producing about 120,300 barrels per day.

U.S. oil producers, exporters tally damages from Hurricane Sally, begin restarts (Reuters) - Storm-tossed U.S. offshore energy producers and exporters began clearing debris on Thursday from Hurricane Sally and booting up idle Gulf of Mexico operations after hunkering down for five days. The storm toppled trees, flooded streets and left about 570,000 homes and businesses from Mississippi to Florida without power. Sally became a tropical storm and spread heavy rains overnight from Alabama to Georgia. Crews returned to at least 30 offshore oil and gas platforms. Chevron Corp began restaffing its Blind Faith and Petronius platforms in the Gulf of Mexico. The Louisiana Offshore Oil Port, a deepwater oil port that handles supertankers, reopened its marine terminal after suspending operations over the weekend. Sally had shut 508,000 barrels per day of oil production and 805 million cubic feet of natural gas, more than a quarter of U.S. Gulf of Mexico output, and halted petrochemical exports all along the Gulf Coast. About 1.1 million bpd of U.S. refining capacity were offline on Wednesday, according to the U.S. Energy Department, including two plants under repair since Laura and another halted by weak demand due to the COVID-19 pandemic.The storm helped lift U.S. oil and gasoline futures. U.S. crude rose more than 4% on Wednesday and gasoline gained nearly as much. Phillips 66, which shut its 255,600-bpd Alliance, Louisiana, oil refinery ahead of the storm, said it was advancing planned maintenance at the facility and would keep processing halted. Royal Dutch Shell’s Mobile, Alabama, chemical plant and refinery, reported no serious damage from an initial survey, the company said. Chevron said its Pascagoula, Mississippi, oil refinery operated normally through the storm.

Industry groups argue Fifth Circuit should reverse panel decision on coastal lawsuits – A federal appeals court should reverse a three-judge panel's decision that lawsuits seeking to make oil and gas companies pay for alleged environmental damage belong in state court, several industry groups argued in briefs filed Tuesday. Failing to do so could muddy the waters for future cases and undermine the “unique relationship” between the federal government and the oil industry, they said. In 2013, some local governments in Louisiana’s coastal region filed lawsuits against more than 200 oil and gas companies, seeking compensation for damage they say the companies caused to the region’s wetlands. Most local governments on the coast did not file lawsuits. Plaquemines Parish, one of the governments that did, in 2018 produced an expert report indicating at least some of the alleged damage dates back to World War II. At that time, the companies say they were under strict wartime regulation and essentially were acting as officers of the federal government. That raises a federal issue, which means the cases should be heard in federal court, they say. But a three-judge panel of the U.S. Court of Appeals for the Fifth Circuit unanimously ruled that the companies failed to make their argument in time. They said the relevant evidence had been included in court records long before the 2018 report. The companies contend that the older documents only referenced serial numbers for certain wells and didn’t identify when they were drilled. In a brief filed in support of the companies’ position, the U.S. Chamber of Commerce and the National Association of Manufacturers says that limited information doesn’t meet the court’s previously established standard of “unequivocally clear and certain” evidence for removal to federal court.

Cooper Urges Trump to Protect the NC Coast - Gov. Roy Cooper in a letter Tuesday urged President Donald Trump and his administration to include North Carolina in the recently announced moratorium on oil drilling for the next 10 years.The president Sept. 8 announced during an event in Jupiter, Florida, the presidential order to extend the moratorium on offshore drilling on Florida’s Gulf Coast and expanding it to Florida’s Atlantic Coast, as well as the coasts of Georgia and South Carolina. In 2018, Trump announced plans to open nearly all federal waters to offshore drilling in his draft five-year program for oil and gas development on the Outer Continental Shelf. He later granted Florida an exemption from that program after objections from Florida’s Republican Gov. Rick Scott, per a past report. “I am deeply concerned and disappointed that you did not include North Carolina in the moratorium,” Cooper wrote. “Offshore drilling threatens North Carolina’s coastal economy and environment and offers our state minimal economic benefit. Accepted science tells us that there is little, if any, oil worth drilling for off North Carolina’s coast, and the risks of offshore drilling far outweigh the benefits.”Cooper adds in the letter that knowing oil spills do not respect state lines and knowing the state’s history of hurricanes “should give us all pause before contemplating opening the waters off our coast to drilling, as the risk of storm damage to drilling and production equipment and subsequent spread of oil to other states on the Atlantic Coast is ever more likely, especially as climate change causes increasingly severe storms.” “Opposition to offshore drilling is bipartisan and widespread across our state,” he continued. Forty-five North Carolina communities have adopted formal resolutions opposing the expansion of drilling. Rep. Greg Murphy, R-N.C. said in an email response to Coastal Review Online, “Having spoken with my coastal constituents over the last year they are not in favor of seismic testing and offshore drilling. Unless the issue becomes one of national security, I will not support drilling off the shores of North Carolina.”

Whitmer says Line 5 easement decision coming in ‘very near future’ -— An extensive state review of Canadian energy giant Enbridge’s compliance with easement requirements for its Line 5 pipeline under the Straits of Mackinac is wrapping up soon, according to Michigan Gov. Gretchen Whitmer.Whitmer said the Department of Natural Resources (DNR), which holds the easement title, is finishing its review during remarks to the Chicago-based Environmental Law & Policy Center, which held virtual gala on Thursday, Sept. 10.The DNR review has been pending since last summer.“We know a break in that pipeline would be an utter disaster,” Whitmer said. “As the DNR is wrapping up its easement review, I think it’s really very likely there will be a determination on that particular front in the very near future.”Whitmer added that she remains “aligned with the attorney general and the work that she’s doing because I want to get this pipeline out of the water at the earliest possible moment.”Whitmer has been criticized by environmental groups in Michigan for moving slowly to shut down Line 5. Pipeline opponents want her to revoke the 1953 easement that gives Enbridge authority to use the state-owned lake bottom to transport oil and gas.Mike Shriberg, regional director for the National Wildlife Federation, criticized Whitmer in a Bridge Magazine column this month for failing thus far to decommission the pipeline.“Governor Whitmer’s political legacy will be decided in part by Line 5,” wrote Shriberg, who served on a pipeline advisory board created by Gov. Rick Snyder. “The legal underbrush has largely been cleared and the time for studies has passed – it’s now time for a decision.”The DNR told MLive on Thursday that it’s “working with the governor’s office to finalize the review” but it did not have a definitive timeline for completion.Whitmer ordered the DNR in June 2019 to undertake a comprehensive review of Enbridge’s compliance with the 1953 easement. Environmental groups have argued for years that Enbridge has violated terms of the easement in the past by allowing, among other things, erosion to create large unsupported spans in the dual underwater line.A DNR recommendation that Michigan revoke the easement is seen as a crucial legal hurdle that would be necessary before Whitmer could move to shut the line down. Any attempt to revoke the easement is likely to be met by resistance in court from Enbridge, which maintains that the 67-year-old pipeline is safe even as itseeks permits necessary to build a tunnel under the straits that would house a new, replacement pipeline.

Editorial: We recommend Chrysta Castañeda for Railroad Commission – Houston Chronicle - Texas and Houston depend mightily on a thriving oil and gas industry, and that’s why it’s so important that the Railroad Commission of Texas be led by experienced, capable commissioners.Fortunately, as an engineer and a lawyer, Democrat Chrysta Castañeda has the combination of knowledge and experience to help the RRC shepherd the crucial industry through one of the most challenging economies in decades.As the founding law partner of the Castañeda Firm, which focuses on oil and gas litigation, she also understands the importance of crafting and enforcing regulations to protect the state’s environment.That is why we recommend Castañeda, 57, in the statewide Railroad Commission race in the Nov. 3 election. If elected, she would join two Republican commissioners who, like her opponent, can be counted on to give the industry’s needs top billing over environmental concerns. What’s really needed is a balance between helping the industry thrive and minimizing its harmful impacts.Republican Jim Wright, a South Texas rancher and oil field service company owner who knocked off Commissioner Ryan Sitton in the GOP primary, is also on the ballot, as is Libertarian candidate Matt Sterett, who runs a small software company based in Austin.While Wright also would bring experience to the job, it would be solely from the industry side. Texas needs at least one member of the Railroad Commission who takes to heart both the mandate that the commission promote the oil and gas industry and its charge to safeguard the water and air Texans drink or breathe.Castañeda will do just that. Launching her campaign with a focus on the wasteful and damaging practice of flaring — the burning of surplus gas from oil wells — she is better positioned to steer a course for the 21st century.

Chesapeake Energy to cut 200 from its workforce Friday, CEO's email states Chesapeake Energy Corp. plans to lay off 200 tomorrow. Employees were notified of the planned job cuts in an email sent Thursday afternoon. The cut amounts to about 15% of Chesapeake's current workforce, which numbers about 1,500. Doug Lawler, Chesapeake’s CEO, told employees in the email Chesapeake was forced to make the difficult decision to eliminate the positions because of a continued downturn in global oil markets. He said the layoffs will primarily affect the company’s Oklahoma City workforce. Employees in Oklahoma City affected by the reduction in force will be notified by phone, given the company’s campus remains closed, except for its child development center. Affected field employees were notified Thursday afternoon. All employees being let go, Lawler noted, would be eligible to receive a severance package that includes a cash payment and optional career transition assistance. “While Chesapeake is not alone in reducing staff during this challenging time, we recognize that does not dampen the disappointment in receiving this news,” Lawler wrote. Gordon Pennoyer, Chesapeake Energy’s spokesman, declined to get into specific details about the layoffs or Lawler’s email on Thursday afternoon. “We continue to prudently manage our business and staffing levels to adapt to challenging market conditions,” Pennoyer said.

BLM offers New Mexico public land for oil and gas -- As the federal Bureau of Land Management (BLM) prepares to lease about 6,000 acres of public land to the oil and gas industry for extraction operations next year, public comments on the sale were scheduled to be accepted through next week. The BLM opened public comments on Monday for its January 2021 lease sale and will accept the comments until Sept. 24. The period is intended to solicit feedback from local stakeholders and organizations to inform the final decision making for the parcels to be offered in the sale. The sale was planed for Jan. 14, 2021. As of Wednesday, the sale offered 33 parcels of land totaling in about 6,442 acres in Eddy and Lea County in New Mexico and in Wise County, Texas. Records show about 720 acres or 11 percent of the land offered in the sale was in Eddy County, while 5,223 acres or 81 percent of the land was offered in Lea County. A single, 500-acre parcel was offered in Wise County, Texas – about 8 percent of the sale. More: Permian Basin crude oil pipeline cancelled as market struggles to recover from COVID-19 States that offer public land in the sales receive 48 percent of the sale revenue, with the rest going to the U.S. Treasury, per a BLM news release. The states also receive half the revenue generated when oil and gas is produced on the leased land.  Through its Environmental Analysis (EA), the BLM reported it found the lease sale would not have a significant impact on air quality and emissions, greenhouse gases, surface and groundwater or threatened species in the area such as the dunes sagebrush lizard or the lesser prairie chicken.The BLM estimated the leases in Eddy and Lea counties would result in 32 horizontal wells and 144 acres of surface disturbance and about 5.4 million barrels of oil produced along with about 31.3 billion cubic feet of natural gas. The EA noted that “extensive” oil and gas development already exists in the area contributing to its local economy.

More call for pause as US weighs New Mexico drilling plan (AP) — Environmentalists want federal land managers to suspend efforts to amend a plan that would guide oil and gas development and other activities near Chaco Culture National Historical Park. They sent a letter Thursday to Interior Secretary David Bernhardt, saying the coronavirus pandemic has prevented meaningful in-person consultation with Native American tribes and others who would be affected by the decision. A coalition of more than 50 groups signed the letter. They argue that low-income and minority communities will be disproportionately harmed as they are located on the frontlines of oil and gas development in the San Juan Basin. “Environmental justice must be served,” the groups said in the letter. “In the midst of the public health and economic emergency caused by the COVID-19 crisis, we urge you to protect the most vulnerable New Mexicans from the dangers and insecurity that result from the public health crisis, not take advantage of our inability to engage in ... decision making.” Legislation that would make federal land within a 10-mile (16-kilometer) radius of the park off-limits is pending in Congress. New Mexico pueblos with ancestral links to the region around Chaco park have been outspoken about their desire to halt oil and gas drilling in the area, saying they fear culturally significant sites beyond the park boundaries would be at risk with added development. In recent years, they joined with environmentalists who have long been critical of drilling in northwestern New Mexico. Meanwhile, the Navajo Nation, which controls large swaths of land in the basin, has been more reserved with its stance on amending the resource management plan for the area. The tribe supports a smaller buffer around the park, as revenue from development on adjacent tribal land and parcels owned by individual Navajos account for a significant source of revenue for the impoverished area. The request from environmentalists for a pause in the process comes just weeks after a coalition of tribes and members of New Mexico’s congressional delegation asked federal officials for more time to consider the proposal.

Colorado could OK first-of-its-kind air-quality rule for oil, gas well sites - Colorado could once again lead the way on oil and gas regulations if the state approves proposals meant to control emissions from well sites earlier than is now required under a mandate to revamp rules.The Colorado Air Quality Control Commission opened a hearing Thursday on proposed rules, including ones that would require monitoring emissions and air quality from the start of construction of a well and over the first six months of production. The nearly continuous monitoring of so-called preproduction, a phase that can produce high emissions of chemicals and health complaints from the public, would be a new requirement..“Colorado, like it did in 2014, being the first to implement methane rules, now is once again at the head of the pack on figuring out ways to incentivize new technology and address oil and gas emissions. It’s a big deal,” said Jon Goldstein with the Environmental Defense Fund in Denver.In 2014, Colorado became the first state in the nation to pass regulations limiting methane emissions from oil and gas operations. A federal methane rule, which has been loosened by the Trump administration, was modeled on Colorado’s regulation.  Garry Kaufman, director of the state air pollution control division, said he’s not aware of any other state with the kind of monitoring program Colorado is considering.“These monitoring devices have been deployed in other states on a case by case basis, but it’s not something that’s been required of the whole industry, that I know of,” Kaufman said.The rule is part of the implementation of the Senate Bill 181, approved in 2019 to overhaul the regulation of oil and gas. The law changed the state’s mission from fostering oil and gas development to regulating it in a way that protects public health, safety and the environment.Both the air quality control commission and the Colorado Oil and Gas Conservation Commission are writing rules to carry out the new mandate. The air quality board proposal would require nearly continuous, or what Kaufman calls “high-frequency,” monitoring of oil and gas sites as soon as well construction starts. Monitoring would continue through drilling, hydraulic fracturing and what’s called flowback, which is when groundwater and fluids used in fracking are brought to the surface and disposed of.

DAPL court disputes could linger post-election - A federal judge overseeing a longstanding legal battle over the Dakota Access Pipeline isn’t likely to decide until late this year or early next year whether to order the flow of oil to cease. U.S. District Judge James Boasberg earlier this year issued a shutdown order that was overturned by a federal appeals court that concluded he hadn’t justified the move. American Indian tribes who sued over the pipeline four years ago are making a renewed push as the legal battle continues in both U.S. District Court and the U.S. Court of Appeals for the District of Columbia Circuit. Tribes want Boasberg to issue an "injunction on continued pipeline operations." An injunction is an order prohibiting something. In this case, it would stop pipeline developer Energy Transfer from operating the pipeline while the legal fight plays out. Attorneys for the tribes and the U.S. Department of Justice on Wednesday submitted a proposed schedule for briefs, or written arguments, that extends to Dec. 18, after which Boasberg would rule, should he sign off on the schedule. Much could happen before then. The U.S. Army Corps of Engineers, which permitted the pipeline, is expected to decide by mid-October whether to continue allowing Dakota Access to move oil. Boasberg in July invalidated the federal easement that allows the line to cross under the Missouri River just north of the Standing Rock Sioux Reservation. The means the pipeline is now considered an "encroachment" on federal property. Tribes don’t believe the Corps will order a shutdown, so they’ve turned to Boasberg. Meanwhile, the Corps last week launched an environmental review of the pipeline that Boasberg ordered in March. It’s expected to take more than a year. The Corps and Energy Transfer have asked the appeals court to reverse Boasberg's rulings ordering the study and revoking the easement during the review. They argued in court documents late last month that the risk of an oil spill feared by the tribes is low, and that Boasberg erred by giving too much weight to opposition of the $3.8 billion pipeline that moves North Dakota oil to a shipping point in Illinois. Tribes and environmentalists fear water pollution from a spill. Prolonged protests in 2016 and 2017 drew thousands of people to camps near the Missouri River crossing and resulted in hundreds of arrests. The tribes late Wednesday filed a response with the appeals court saying "the Corps failed to address the detailed technical critiques of its methods and assumptions that underpinned its conclusions regarding the risk of oil spills."

Docs: Trump aides pushed EPA for fewer methane checks -- Friday, September 18, 2020 -- EPA bowed to White House pressure during interagency review of an oil and gas emissions rule by reducing requirements for a segment of the natural gas supply chain to monitor and repair methane leaks.Correspondence released this week after the emissions rule was published in the Federal Register on Monday shows that officials from the White House pressed EPA staff to halve the frequency of the rule's monitoring requirements for well sites and natural gas compressor stations. It made that request in June as a rule easing restrictions on methane was being completed.The so-called technical rule EPA finalized last month rejected White House efforts to weaken the agency's proposal to have gas producers monitor their well sites once a year. But EPA changed its requirements related to monitoring and leak repair for compressor stations, which push natural gas from the well sites through pipelines.When the rule traveled to the Office of Management and Budget for review in late May, the measure required quarterly monitoring at compressor stations. When it was released to the public three months later, the requirement had been changed to twice annually."It's clear that politics supersede what policy analysis would indicate is the best way to fashion EPA regulations," said Amit Narang, a regulatory policy advocate at Public Citizen.In its written comments in June, the White House seemed determined that the final rule should differ from the Obama-era rule it was designed to replace."This cannot stay the same as the 2016 rule," insisted an unnamed White House official in correspondence released as part of the rule's docket.EPA had retained the Obama-era monitoring schedule for wellheads and compressor stations in the final draft of the rule it sent to OMB. Both rules required well sites that produce at least 15 barrels of oil equivalent per day to monitor for possible leaks twice a year. And they both required compressor stations to check for fugitive emissions quarterly.But the White House urged EPA to cut monitoring requirements for both source categories in half. That tracked with comments submitted to the rule's docket on July 1, 2019, by the Independent Petroleum Association of America. The trade group has long urged EPA to discard direct regulation of methane in favor of a more limited rule for volatile organic compounds (VOCs), to exclude transmission and storage from regulation, and to lighten monitoring requirements. But EPA's technical support document for the rule showed that the original monitoring requirement met EPA's standard for cost-effectiveness as measured by dollars per ton of a pollutant reduced.

A Secret Recording Reveals Oil Executives’ Private Views on Climate Change - The New York Times - Last summer, oil and gas-industry groups were lobbying to overturn federal rules on leaks of natural gas, a major contributor to climate change. Their message: The companies had emissions under control. In private, the lobbyists were saying something very different. At a discussion convened last year by the Independent Petroleum Association of America, a group that represents energy companies, participants worried that producers were intentionally flaring, or burning off, far too much natural gas, threatening the industry’s image, according to a recording of the meeting reviewed by The New York Times. “We’re just flaring a tremendous amount of gas,” said Ron Ness, president of the North Dakota Petroleum Council, at the June 2019 gathering, held in Colorado Springs. “This pesky natural gas,” he said. “The value of it is very minimal,” particularly to companies drilling mainly for oil. A well can produce both oil and natural gas, but oil commands far higher prices. Flaring it is an inexpensive way of getting rid of the gas. Yet the practice of burning it off, producing dramatic flares and attracting criticism, represented a “huge, huge threat” to the industry’s efforts to portray natural gas as a cleaner and more climate-friendly energy source, he said, and that was damaging the industry’s image, particularly among younger generations. “What’s our message going forward?” Mr. Ness said. “What’s going to stick with those young people and make them support oil and gas?” The recording runs 1 hour 22 minutes, opening with a moderator’s remarks and concluding with a panel discussion that covered a wide range of issues including job creation, the threats posed by solar and wind energy, and the federal leasing of oil and gas rights. The audio was provided by an organization dedicated to tracking climate policy that said the recording had been made by an industry official who attended the meeting.Neither the organization nor the official was willing to be identified, out of concerns for industry retaliation, but three people heard in the recording, including the event’s moderator, Ryan Ullman of the Independent Petroleum Association, said that it reflected their comments. Jennifer Pett Marsteller, an association spokeswoman, confirmed the meeting’s date, location and speakers’ list, which matched the recording. She declined to comment on the speakers’ remarks, saying there was no official recording.

California Dems Give Up On New Oil Safety Regulations  - Steve Horn - Big money from Big Oil and industry-tied unions has helped to kill a legislative effort to create environmental protections for communities living near oil and gas operations in California.On August 5, a 5-4 Senate committee vote struck down consideration of legislation calling for consideration of a 2,500-foot setback between future oil wells and homes, schools and playgrounds. Only one of those votes came from a Republican. It was the second time in as many years that the bill -- Assembly Bill 345 -- failed to pass, and it failed to do so even after several rounds of significant amendments had watered down the legislation. With that, a years-long activist-led legislative movement went up in smoke for 2020. And then came the historically large wildfires. Within a matter of days, the state’s northern half caught fire at an epic scale, wildfires made worse from climate change and fueled by unfettered fossil fuel drilling. California oil is some of the dirtiest, from a climate change perspective, in the United States.Drilling for oil in the state also has major public health repercussions, an impetus driving AB 345. Recent studies have linked oil drilling in California to health impacts, including low birth weight and small gestational age, as well as preterm births. Research has also linked higher levels of industrial pollution to higher contraction rates of COVID-19. Despite these impacts, the bill attracted a core group of Democratic legislators who ultimately oversaw the bill’s demise. Three of those who spoke out the most strongly against AB 345 at the Senate Committee on Natural Resources and Water hearing on August 5 before voting against it -- Sen. Ben Hueso, Sen. Andreas Borgeas and Senate Majority Leader Bob Hertzberg -- have received high dollar contributions and other support from oil interests that lobbied against AB 345. The lobbying and influence campaign efforts waged by the oil industry and labor against AB 345 illustrates the difficulty in crafting climate policy and environmental protections -- even in a state with a super-majority Democratic Party legislature that bills itself as a global leader on fighting climate change.  A big part of the difficulty is the contradiction of the center of it all: California is the sixth biggest oil producer nationwide and the largest west coast oil refiner.

Shell Offshore files plans to return to Alaska’s North Slope - Anchorage Daily News --A supermajor oil company is looking to advance its position on Alaska’s North Slope. Shell Offshore Inc. has applied to form the West Harrison Bay Unit in state waters just offshore from the National Petroleum Reserve-Alaska with plans to drill the area in search of oil in the coming years, according to documents submitted to the state Division of Oil and Gas.If the Dutch oil industry giant can secure a partner to share in the costs and risks of remote offshore North Slope exploration, it expects to drill exploration wells in the West Harrison Bay Unit with at least one sidetrack each in 2023 and 2024, Shell’s initial unit plan of exploration states. According the application, Shell has been trying to find a partner to work on the West Harrison Bay leases for at least a year, and the company was making progress towards that end before the coronavirus pandemic hit in late winter. As a result, Shell is asking the state for its exploration plan to be valid for five years, which would allow the company to secure a partner and better analyze the area’s development potential. Shell holds a 100 percent working interest in 18 leases covering more than 78,000 acres in the proposed unit. The wells would target the popular Nanushuk oil formation first pinpointed by the Repsol-Armstrong Energy partnership in the Pikka Unit. The shallow, conventional Nanushuk formation also forms the basis of ConocoPhillips' large Willow oil prospect to the south of Harrison Bay and is believed by many in the industry to be prolific across much of the western North Slope. Shell infamously spent more than $7 billion to drill the Burger J exploration well much further offshore in the Chukchi Sea before abandoning its domestic Arctic drilling program in 2015. The work was beset by legal challenges and protests where vessels and equipment were staged at Pacific Northwest ports, as well as the grounding of the Kulluk drilling rig near Kodiak Island in 2013 while being towed south from Unalaska.

Weekly Crude Inventory Data Shows Surprise Draw of 4.4 Million Barrels - U.S. crude oil refinery inputs averaged 13.5 million barrels per day during the week ending September 11, 2020 which was 0.7 million barrels per day more than the previous week’s average. Refineries operated at 75.8% of their operable capacity last week. Gasoline production decreased last week, averaging 8.8 million barrels per day. Distillate fuel production increased last week, averaging 4.4 million barrels per day. U.S. crude oil imports averaged 5.0 million barrels per day last week, down by 416,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 5.3 million barrels per day, 20.1% less than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 600,000 barrels per day, and distillate fuel imports averaged 112,000 barrels per day. U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 4.4 million barrels from the previous week. At 496.0 million barrels, U.S. crude oil inventories are about 14% above the five year average for this time of year. Total motor gasoline inventories decreased by 0.4 million barrels last week and are about 3% above the five year average for this time of year. Finished gasoline inventories decreased while blending components inventories increased last week. Distillate fuel inventories increased by 3.5 million barrels last week and are about 22% above the five year average for this time of year. Propane/propylene inventories decreased by 1.2 million barrels last week and are about 9% above the five year average for this time of year. Total commercial petroleum inventories increased by 4.3 million barrels last week. Total products supplied over the last four-week period averaged 18.1 million barrels a day, down by 15.5% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 8.7 million barrels a day, down by 8.7% from the same period last year. Distillate fuel product supplied averaged 3.6 million barrels a day over the past four weeks, down by 9.1% from the same period last year. Jet fuel product supplied was down 45.6% compared with the same four-week period last year.

Fuel demand rises as schools open, commuters shun public transport (Reuters) - Traffic picked up in cities across the globe as the summer season ended and schools opened, giving a boost to fuel demand, but the prospect of recovery remained weak as many commuters still worked from home and vehicle sales were down. The reliance on isolated forms of travel including private cars seemed to be the main factor boosting demand, analysts and traders said, as most people avoided public transport for fear of the coronavirus. Road traffic in New York, London and Paris was on a slow but steady recovery, data provided to Reuters by location technology company TomTom showed. In Moscow and Beijing, traffic was as high as pre-lockdowns levels.  Fuel demand usually falls in September as the summer driving season ends, but this year, analysts expect fuel demand in September to be almost on par with August. “Over the first 10 days of September road fuels demand has added 700,000 barrels per day (bpd) after remaining flat over the summer months. The acceleration is mostly visible in Europe,” said Artyom Tchen, senior oil market analyst at Rystad Energy. Traffic in some small European cities such as Geneva has even exceeded 2019 levels, TomTom data showed. Data provided to Reuters by the app Transit showed public transport in many cities making a much slower recovery in September compared to road traffic. People in the United Kingdom avoided public transport far more than French, data from Transit showed, while use of public transport in the United States remained low. (Graphic: How COVID-19 is disrupting public transport How COVID-19 is disrupting public transport, ) However, analysts and traders said they did not expect a significant rise in fuel consumption in the coming months, since short trips in cities do not burn as much fuel as long holiday journeys.

Germany won't abandon its massive gas pipeline with Russia yet, analysts say - Germany has come under increasing pressure to pull the plug on its controversial giant gas pipeline project with Russia, following the suspected poisoning of Russian opposition politician Alexei Navalny. Experts say Berlin is unlikely to do so for now, however, given the Nord Stream 2 project is over 94% completed after almost a decade's construction, involves major German and European companies, and is necessary for the region's current and future energy needs. In this case, economic and commercial interests could trump political pressure to punish Russia. "I don't see Germany pulling out of the project just yet," Carsten Brzeski, chief economist for the euro zone and global head of macro at ING, told CNBC Thursday. "But the domestic debate of the last days has made it clear that patience is running low. Many are still in favor of it. But they will need Moscow to clearly demonstrate that pragmatic cooperation is possible and can actually bear fruit – for instance regarding managing the situation in Belarus," he said. Germany's Foreign Minister Heiko Maas hinted last Sunday that Russia had to play its part during the investigation into the attack on Navalny. A fierce critic of Russian President Vladimir Putin, Navalny was left critically ill after a suspected poisoning with a Novichok nerve agent. "I hope the Russians won't force us to change our position regarding the Nord Stream 2" pipeline, Germany's Foreign Minister Heiko Maas told the Bild am Sonntag newspaper. Germany has been reluctant to link the fate of its involvement with Nord Stream 2 to the Navalny incident so far, and Maas conceded that stopping the building of the pipeline would hurt not only Russia but German and European firms. "Anyone calling for the project to be halted needs to be aware of the consequences. Nord Stream 2 involves over 100 companies from twelve European countries, and about half of them from Germany," he said. Jane Rangel, a gas analyst at Energy Aspects, told CNBC Wednesday that she and her colleagues are "watching the situation because it's evolving" and noted that the Navalny poisoning "does put Germany in a tough position." "It's another challenge for the project to be finished and it certainly raises the risk that Germany could take action, one of the most obvious solutions could be Germany refusing to grant regulatory approval" for the pipeline, she added. German Chancellor Angela Merkel could opt to tell Bundesnetzagentur, the official body that's responsible for authorizing the pipeline, not to grant approval for the project, Rangel said. "At that point, we'd assume that Gazprom would bring it to court if it didn't get regulatory approval. Then the court could possibly overturn it and that means the German government scores its political point but the project eventually gets approved."

Nornickel says it collected more than 90% of fuel leaked by Arctic spill (Reuters) - Russia’s Norilsk Nickel (Nornickel) said on Friday that it had collected more than 90% of fuel leaked into rivers during its Arctic fuel spill earlier this year, or about 12,000 tonnes. The spill occurred on May 29 after a fuel tank lost pressure and released 21,000 tonnes of diesel into rivers and subsoil near the city of Norilsk in Siberia. Greenpeace has compared the incident to the 1989 Exxon Valdez oil spill off Alaska. “As of today, it can be assumed that what we have collected and separated is exactly the (amount of) fuel that got into the water,” Nornickel first vice-president Sergey Dyachenko told reporters. Some environmental campaigners have said they doubt Nornickel’s assertions that it has been able to recover 90% of the leaked diesel, citing similar clean-ups in the past around the world. Earlier this week, Russia’s state environment watchdog, Rosprirodnadzor filed a lawsuit against a power business owned by Nornickel, the $41-billion mining giant, to claim $2 billion for environmental damage caused by the leak. Nornickel disagrees with a formula used by the watchdog to estimate the $2 billion damage from the spill, which, Nornickel said, was based on more than 19,000 tonnes of fuel leaked into the rivers, Dyachenko said. Nornickel believes that filing the lawsuit was premature as it was hoping for an out-of-court settlement. It had already set aside $2 billion in reserves, which caused a slump in its first-half net profit. The size of the damages claim is unprecedented both for Russia and emerging markets. For Russia, money from this claim would help the state budget amid the coronavirus pandemic and send a message to other companies that underinvestment in maintenance is unacceptable, analysts have said. Fitch ratings agency said earlier this week that the damage claimed from Nornickel indicates growing financial exposure of commodity companies operating in emerging markets to environmental, social and governance (ESG) factors.

Venezuela's PDVSA confirms oil leak into sea – Venezuela's state-owned oil company PDVSA on Saturday confirmed an oil leak from an oil line and a gas pipeline into the Caribbean Sea near the largest refining center in the country, but said it had begun repair and cleanup efforts. PDVSA discovered the spill in the Golfete de Coro area in Falcon state during an aerial inspection, a statement from the company said, adding that despite the leak it guaranteed it will continue to supply crude to the Paraguana Refining Complex (CRP), which includes the Amuay and Cardon refineries. Both Amuay and Cardon have experienced multiple outages in recent years that the opposition blames on mismanagement and lack of maintenance. In recent days fishermen and experts had sounded the alarm about a slick in the Golfete area, known for pristine beaches and nature preserves in the northwest of the country. The incident comes a month after a spill covered swathes of Morrocoy National Park. Authorities say they addressed that oil slick, but have given no details about its size or origin. Carlos Carmona, a researcher and member of the Venezuelan Ecology Society, said dead fish were found where the Golfete slick was discovered in an area that is home to shorebirds, nesting sea turtles and a black mangrove reserve. Hit by U.S. sanctions that have exacerbated an acute fuel shortage crisis, Venezuela's government on Friday announced a new fuel distribution initiative and said it was planning new refining projects, without providing further details.

Shell recorded 46.6 per cent reduction in oil spills in 2019 - Shell Petroleum Development Company of Nigeria Limited (SPDC) has said it reduced operational spills to the lowest levels in 2019. Records made available by SPDC show that ‎only seven operational spills were reported in 2019, a 46.6 per cent decrease over the previous year, 2018, when the company recorded 15 operational spills. The company also reported a significant reduction in breaches from wellhead, and clean-up of more spill sites than ever before, in 2019. ‎However, there was an increase in cases of theft and sabotage in 2019, according to records made available by the company. SPDC said identified leaks were cleaned promptly, adding that it was working towards totally eliminating spills from its operations. ‎”The data available showed that in 2019, theft and sabotage resulted in 156 spills. In 2018, the figure was 109. The SPDC JV has a policy that when a leak is identified, the team responds to contain any spilled oil and clean up. In 2019, SPDC JV remediated 130 sites. “The SPDC JV is working to eliminate spills from its operational activities, remediate past spills and prevent spills caused by crude oil theft, sabotage of pipelines or illegal oil refining. “While SPDC operates to the same technical standards as other Shell companies globally, illegal activities continue to inhibit a normal operating environment. “Past spills from operational and illegal activities have been well documented, resulting in a clean-up programme and, where appropriate, compensation,” the company added. SPDC, in the same vein, noted that there is still much work to do to get the company to its target of ‘Goal Zero’ in all spills, including those arising from operational and third-party vandalism. “But through a solid strategy, active partnerships, closer community engagements, bold security and new surveillance equipment, the company is steadily making good progress,” ‎the company said. Specifically, SPDC said it has made progress in areas such as improving performance, ‎preventing illegal activity,‎ response and investigation, ‎improving remediation and ‎clean-up in Ogoniland. SPDC disclosed that it was working with the relevant stakeholders to implement the 2011 United Nations Environmental Programme (UNEP) Report on Ogoniland. According to the company, over the last eight years, it has taken action on all, and completed most, of the UNEP recommendations addressed specifically to it as operator of the joint venture. 

Shipping authority lists causes of Mauritius oil spill - A shipping authority on Friday released a list of factors that caused a Japanese bulk carrier to hit a coral reef and cause an oil spill off Mauritius' coast last month. The MV Wakashio was owned by a Japanese company but Panama-flagged. The Panama Maritime Authority said that the lack of supervision and control of navigation equipment, and "overconfidence" caused the ship to run aground, according to local daily Le Mauricien. The crew told investigators that the ship deviated from its planned course and that a birthday celebration was being held on board when it ran aground. “Appropriate analysis of the situation would have made it possible to take the necessary measures to correct the direction and avoid the accident, the wrong electronic nautical chart was used and with the wrong scale, which made it impossible to correctly verify the approach to the coast and shallow water,” local daily Le Mauricien quoted the Panama Maritime Authority as saying. Speaking on Friday at a press conference Junichiro Ikeda, CEO of Mitsui OSK Lines Ltd, the company that charted the ship, said that the ship was using the wrong nautical charts just as outlined in the Panama Maritime Authority report. Ikeda who blamed the lack of awareness of the crew for the accident announced funding of 1 billion yen (roughly $9.4 million) to help the East African island nation in the cleaning processes. In Mauritius, thousands of people will hold a march on Saturday to highlight the harmful effects on marine life due to the oil spill. Meanwhile, the government has put a ban on seafood caught at Pointe-d'Esny and Deux-Frères regions after a test carried out on the fish found traces of hydrocarbons.

Thousands march in Mauritius to protest disastrous oil spill— Thousands of people protested in Mauritius again Saturday over the government’s handling of an offshore oil spill that has become the Indian Ocean island nation’s worst environmental disaster in years. New details indicate the Japanese ship that struck a coral reef in late July and leaked some 1,000 tons of fuel oil near protected coastal areas had strayed miles off course because the captain wanted to move closer to shore so crew members could get a mobile phone signal to call their families. “The change of course could be related to the birthday celebration of one of the crew members,” said a report this week by the maritime authority of Panama, where the MV Wakashio is registered. It said preliminary investigations also suggested that a navigation system and a nautical chart were mishandled. Last month, nearly one-tenth of the population of Mauritius marched peacefully in the capital, Port Louis, expressing outrage over the disaster and the discovery of dozens of dead dolphins weeks after the spill. It is not immediately clear what killed the dolphins, but some experts say water-soluble chemicals in the fuel might have been to blame. The government has called it a “sad coincidence.” Protesters have called for top officials to step down. Saturday’s march took place in Mahebourg, one of the most affected coastal villages. The island nation of 1.3 million people relies heavily on tourism and already had taken a severe hit due to travel restrictions during the coronavirus pandemic. On Friday, the Japanese operator of the bulk carrier said it will provide 1 billion yen ($9 million) to fund environmental projects and support the local fishing community. Mitsui O.S.K. Lines said the Mauritius Natural Environment Recovery Fund will be used for mangrove protection, coral reef recovery, protection of seabirds and rare species, and research by private and governmental groups.

Japanese ship operator to put $9.4m toward Mauritius - The operator of a Japanese-owned bulk carrier that crashed into a reef in late July, causing a widespread oil spill in Mauritius, will pay at least $9.4 million over several years to fund environmental projects and support local fishing communities. The spill took place near the coastal areas of southeast Mauritius, an area of international importance because of its environmentally protected ecosystems and wetlands. Experts say about 1,000 tons of fuel leaked from the ship into the surrounding blue lagoons — a favorite location for the filming of numerous Bollywood movies because of its turquoise waters, which now are stained black. Mauritius previously asked Japan to provide at least $34 million to assist with the lasting ramifications of the spill. Mitsui O.S.K. Lines said Friday that the Mauritius Natural Environment Recovery Fund would be used to support mangrove protection, coral reef restoration, and the protection of seabirds and rare species. In addition, the company said, it will continue to support local fishing and tourism, though details of that support have not been announced. The Mauritius government has estimated the country has sustained $30 million in damage as a result of the spill. Early this week, the maritime authority of Panama, where the ship is registered, announced it was in the early stages of an investigation into the spill and suggested human error caused the accident. The ship's captain and first officer have been arrested and charged with endangering safe navigation. Recently, tens of thousands of individuals protested in Mauritius over the government's slow response to the spill and the discovery of dozens of dead dolphins, whose cause of death has not yet been determined.

Japan sending team to probe Mauritius ship grounding (Reuters) - Japan said on Friday it will send a five-person team to Mauritius to investigate the grounding of a Japanese-owned ship off the country’s coast that led to an environmental crisis. A bulk carrier owned by Japan’s Nagashiki Shipping and chartered by Mitsui OSK ran aground on a reef off Mauritius on July 25 and later began leaking oil into the pristine waters around the Indian Ocean island. The Japanese government said in a statement that it would send a team of five people to Mauritius on Sept. 20. Japan previously told Mauritius it would offer support on an “unprecedented scale.” The Panamanian-flagged MV Wakashio began spilling fuel oil on Aug. 6, prompting the Mauritian government to announce an environmental emergency. The captain and another member of the crew have been arrested by Mauritius police. Scientists say the full impact of the spill is still unfolding but the damage could affect Mauritius and its tourism-dependent economy for decades. Mitsui OSK last week said it would contribute about 1 billion yen ($9.4 million) to help Mauritius.

MbPT to upgrade its oil spill contingency plan for Mumbai - Following the devastating oil spill in Mauritius, called the country’s worst ecological disaster, authorities in Mumbai are also looking at preparing and upgrading a comprehensive oil spill contingency plan that can be put into effect, in case of an emergency in the city. The Mumbai Port Trust (MbPT), which owns the eastern waterfront area in Mumbai, has floated a tender to appoint an agency to create a Tier-1 oil spill response facility for Mumbai and the Jawaharlal Nehru Port Trust (JNPT) harbour. According to the tender details accessed by HT, the consultant will be asked to carry out a quality risk assessment of oil spill, assess the oil spill trajectory in the worst-case scenario given different weather and sea conditions, carry out sensitivity mapping of the areas most likely to be affected, do a gap analysis of the required and available sources among various other parameters. The consultant will also be asked to prepare a contingency plan with the specific role and functions of the agencies involved. Captain Bhabatosh Chand, deputy conservator, head of marine department, MbPT, said, “We have a plan in place in case of an oil spill for the past five years. As the contract is ending, we are looking for a new agency. We are looking to upgrade it [the plan] and looking at new technology. A ready plan will aid us to control the situation in case of an emergency.” Recently, a Japanese bulk carrier ran aground on a reef on the south-east coast of Mauritius. MV Wakashio struck a coral reef on July 25, spilling about 1,000 tonnes of fuel and endangering corals, fish and other marine life in what some scientists have called the country’s worst ecological disaster. India has also sent equipment and personnel to help Mauritius contain the oil spill.

IEA says oil demand recovery set to slow for rest of 2020 -(Reuters) - The International Energy Agency (IEA) trimmed its 2020 oil demand forecast on Tuesday, citing caution about the pace of economic recovery from the pandemic. The Paris-based IEA cut its 2020 outlook by 200,000 barrels per day (bpd) to 91.7 million bpd in its second downgrade in as many months. “We expect the recovery in oil demand to decelerate markedly in the second half of 2020, with most of the easy gains already achieved,” the IEA said in its monthly report. “The economic slowdown will take months to reverse completely ... in addition, there is the potential that a second wave of the virus (already visible in Europe) could cut mobility once again.” Renewed rises in COVID-19 cases in many countries and related lockdown measures, continued remote working and a still weak aviation sector are all hurting demand, the IEA said. China - which emerged from lockdown sooner than other major economies and provided a strong prop to global demand - continues a strong recovery, while a virus upsurge in India contributed to the biggest demand drop since April, the IEA said. Increasing global oil output and the downgraded demand outlook also mean a slower draw on crude oil stocks which piled up at the height of lockdown measures, it added. The agency now predicts implied stock draws in the second half of the year of about 3.4 million barrels per day, nearly one million bpd less than it predicted last month, with July storage levels in developed countries again reaching record highs. However, preliminary data for August showed industry crude oil stocks fell in the United States, Europe and Japan. As output cuts eased among producers from the Organization of the Petroleum Exporting Countries (OPEC) and allies such as Russia, global oil supply rose by 1.1. million bpd in August.

IEA cuts 2020 oil demand forecast, sees 'treacherous' path ahead with rising coronavirus cases — The International Energy Agency on Tuesday cut its forecast for 2020 oil demand growth, citing a "treacherous" path ahead amid weakening market sentiment and an upsurge in the number of coronavirus cases reported across the globe. In a closely-watched monthly report, the IEA trimmed its outlook for worldwide oil demand growth to 91.7 million barrels per day. That marks a contraction of 8.4 million bpd year-on-year, more than the 8.1 million bpd contraction predicted in the Paris-based energy agency's August report. "We expect the recovery in oil demand to decelerate markedly in the second half of 2020, with most of the easy gains already achieved," the IEA said. "The economic slowdown will take months to reverse completely, while certain sectors such as aviation are unlikely to return to their pre-pandemic levels of consumption even next year." International benchmark Brent crude traded at $40.21 a barrel on Tuesday morning, up around 1.5%, while U.S. West Texas Intermediate crude (WTI) stood at $37.90, roughly 1.7% higher. Oil prices have dropped around 40% since the start of the year. "I think the main message that we put across in the report is that sentiment seems to be weakening," Neil Atkinson, head of the oil industry and markets division at IEA, told CNBC's "Street Signs Europe" on Tuesday. "We have seen oil prices very, very range-bound since roughly the middle to the later part of June, between $40 and $45 a barrel for Brent. But, just recently we have seen $40 a barrel tested and it does look as if the rebound in recovery is beginning to stall." Atkinson said the upsurge of coronavirus cases across Europe, in particular, reflected "a cause for concern," before adding: "It does look as if we are not out of the woods yet." Renewed weakness The report comes shortly after OPEC cut its forecast for oil demand growth in 2020, citing a weaker-than-expected recovery in India and other Asian countries. The oil-producing group also warned on Monday that risks would remain "elevated and skewed to the downside" for the first half of 2021. The IEA echoed this sentiment on Tuesday, saying "renewed weakness" in India reflected a cause for concern. However, China, which emerged from lockdown sooner than other major economies, continued to recover "strongly," the group said. Energy market participants have become increasingly anxious about a faltering economic recovery and stumbling fuel demand in the wake of the coronavirus pandemic. The global health crisis has coincided with an unparalleled energy demand shock this year, with the IEA previously warning the fall in oil demand growth in 2020 could be the largest in history. Looking ahead, the IEA said it expected worldwide oil demand to grow by around 5.5 million bpd next year, climbing to an average of 97.1 million bpd in 2021.

Oil could see another demand shock, adding to the 'extraordinary' destruction this year - — The next big shock to the oil industry could be yet another hit to demand, analysts said. That would add to the destruction already seen this year as measures taken to combat the pandemic prevented people from commuting and traveling – drastically reducing oil usage. Speaking at S&P Global Platts' Platts Asia Pacific Petroleum Virtual Conference (APPEC) 2020 on Monday, analysts pointed to the possibility of a second wave of Covid-19. "A lot of us, we're talking about another demand shock. It's like fighting the last battle," said Ed Morse, managing director and global head of commodities research at Citi. During a panel discussion at the conference, he warned that oil producing countries could experience a big setback. "We're seeing countries that are overly dependent on oil earnings, that can't pay for the civil service, can't pay for healthcare…education…security," Morse said. "The rate of concern we're going to see … dipped in demand and the gigantic build in inventories … I think the biggest worry is what happens to the fragility of the oil producing countries." Earlier this year, the May contract for U.S. benchmark West Texas Intermediate crude dived deep into negative territory for the first time in its history, amid lockdowns and a lack of storage as oil inventory rapidly built up. "I think it is still all about the demand, the demand destruction this year has been extraordinary," Martin Fraenkel, president of S&P Global Platts, which projected that the contraction in global oil demand will be 8 million barrels a day by the end of this year. "That's a huge contraction year-on-year in a typical year …. Now we've come off the summer driving season in the U.S., we're expecting that demand to taper off a little bit, and of course we're seeing an uptick in infections of Covid-19 in many parts of the world … and that is a concern," he said. "By the end of 2021, oil demand will still be below where the world was in 2019," Fraenkel added, speaking to CNBC on Monday. OPEC+ has a "delicate maneuvering act" if demand does not bounce back, Fraenkel added, referring to the Organization of the Petroleum Exporting Countries (OPEC) and its allies.In July, OPEC+ put in place historic supply curbs of 10 million barrels a day, but agreed to ease them to 7.7 million barrels a day from August."If demand doesn't come back, how long is OPEC+ going to be able to sustain cohesion to keep supply under control when prices are hovering around $40 per barrel? While we think prices can go up in 2021 modestly, (will) demand growth keep coming back? It's by no means an assured route," he said.

Global oil demand may have passed peak, says BP energy report  BP has called time on the world’s rising demand for fossil fuels after finding that demand for oil may have already reached its peak and faces an unprecedented decades-long decline. Demand for oil may never fully recover from the impact of the coronavirus pandemic, according to the oil firm, and may begin falling in absolute terms for the first time in modern history. BP’s influential annual report on the future of energy, published on Monday, says oil will be replaced by clean electricity from windfarms, solar panels and hydropower plants as renewable energy emerges as the fastest-growing energy source on record. Spencer Dale, BP’s chief economist, said the company’s vision of the world’s energy future had become greener due to a combination of the Covid-19 pandemic and the quickening pace of climate action, which has hastened “peak oil”. The report in effect sounds a death-knell for the growth of global oil demand after two of the report’s three energy scenarios for the next 30 years found that demand reached a peak in 2019. In BP’s third scenario, showing a world in which climate action does not accelerate, oil demand plateaus at similar levels seen in 2019 through the 2020s before declining from 2035. The report has confirmed a chorus of warnings from independent energy economists that the impact of coronavirus will bring forward the start of the oil industry’s terminal decline from the end of the decade. BP’s chief executive, Bernard Looney, said the findings would help the company to “better understand the changing energy landscape” and would be instrumental in helping it develop its plans to become a net zero energy company by 2050. He admitted earlier this year that he would “not write off” the possibility that coronavirus had brought forward the global peak in oil demand, and was “more convinced than ever” BP must embrace a low-carbon future.

Oil Demand May Have Peaked in 2019, BP Report Says - We may have already passed peak demand for oil. This suggestion comes from an unlikely source: fossil-fuel giant BP. The company released its annual Energy Outlook report Monday, and found that oil demand may have already peaked in 2019, as the rise inrenewable energy intersects with the impact of the coronavirus pandemic, The Guardian reported. "(The energy transition) would be an unprecedented event," BP chief economist Spencer Dale told journalists, as Reuters reported. "Never in modern history has the demand for any traded fuel declined in absolute terms." The report outlines three possible energy scenarios for the next 30 years.

1. The Rapid Transition Scenario (Rapid): This envisions a scenario in which energy-based greenhouse-gas emissions decline 70 percent by 2050, in line with limiting global warming to well below two degrees Celsius above pre-industrial levels by 2100.
2. The Net-Zero Scenario (Net Zero): This scenario imagines the policies adapted in the Rapid scenario are augmented by widespread lifestyle changes, and energy emissions decline by more than 95 percent by 2050, limiting warming to 1.5 degrees Celsius above pre-industrial levels.
3. The Business-as-Usual Scenario (BAU): This imagines that climate policies continue at a pace consistent with the past several years, and emissions only decline to less than 10 percent of 2018 levels by 2050.

In the first two scenarios, BP concluded oil demand would already have peaked in 2019, according to The Guardian. In the third, it would plateau after 2019 and peak sometime in the mid-2020s, according to BP.  However, all three scenarios show oil and gas on the wane and renewable energy on the rise, Reuters reported. They show fossil fuels falling from 85 percent of energy demand in 2018 to 20 to 65 percent by 2050. Meanwhile, they show renewable technologies like wind and solar expanding from five percent of energy demand in 2018 to 20 to 60 percent by 2050, according to Reuters and The Guardian.  "In all three of these scenarios the share of renewable energy grows more quickly than any energy fuel ever seen in history," Dale told The Guardian.

Lost in transition: Big Oil searches for purpose as peak demand looms - The oil industry is about to enter its final phase: managed decline. Even if there is a strong post-pandemic economic recovery that boosts oil prices at some in the 2020s, it will be Big Oil’s ‘last hurrah’ before global demand peaks definitively and gradually tapers off. Some say this might have happened already thanks to Covid-19, while others see the tide turning between now and 2030.Either way, it is coming, and some oil companies are finally starting to wake up. BP acknowledged peak demand by committing to reduce its oil production by 40% within ten years, in a landmark new 2030 strategy that stole the headlines last week.The British oil major, unlike many of its peers, has realised that doubling down and chasing market share in a declining commodity is a road to ruin. Instead, it will focus only on the cheapest, least carbon-intensive barrels in its portfolio, and sell the rest—even if prices pick up in the near-term.In the first half of 2020, BP wrote off USD 9.7 billion in exploration expenditures after lowering its forward oil price assumptions by around 30% and concluding that a large chunk of its undeveloped acreage will never be commercially viable.BP previously valued its exploration intangibles at USD 14.2 billion, so the company has effectively written off almost 70% of its exploration portfolio. The write-offs were spread across Angola, Brazil, Canada, Egypt, India and the US Gulf of Mexico.On top of this, lower price assumptions prompted BP to write down the carrying value of upstream assets to the tune of USD 12 billion. And the company has identified another USD 43 billion of assets at risk of further impairment if assumed forward prices change again within the next financial year.In the meantime, BP is aiming to sell USD 25 billion of out-of-the-money assets by 2025, and is laying off some 10,000 people from its global workforce. Even for a company with a total marketcapitalisation of USD 58 billion, these are big moves.    BP realises that thereafter, the risk of such assets becoming stranded increases significantly with anticipated higher carbon taxes, waning demand and softening prices as the world shifts inexorably towards cleaner fuels. The clock is already ticking, even for cleaner-burning natural gas—Big Oil’s much-heralded ‘bridge’ fuel to a net zero emissions future.

Oil Demand Has Collapsed, And It Won’t Come Back Any Time Soon - 2020 is shaping up to be an extraordinarily bad year for oil. In the spring, pandemic lockdowns sent oil demand plummeting and markets into a tailspin. At one point, U.S. oil prices even turned negative for the first time in history. But summer brought new optimism to the industry, with hopes rising for a controlled pandemic, a recovering economy and resurgent oil demand. Those hopes are now fading. In a report Tuesday, the influential advisory body called the International Energy Agency revised its forecasts for global oil consumption downward, warning that the market outlook is "even more fragile" than expected and that "the path ahead is treacherous." It's the latest in a flurry of diminished forecasts from major energy players. On Monday, oil cartel OPEC slashed its expectations of oil demand, just as Trafigura, a large oil trading company, warned that another large oil glut is building. And energy giant BP, which has grabbed headlines with its new carbon-neutral commitments, raised the possibility that the world might never again use as much oil as it did before the pandemic. A pair of recent OPEC reports reflect the rapid shift in mood. Its August oil forecast assumed that by 2021, "COVID-19 will largely be contained globally with no major disruptions to the global economy." OPEC also predicted that economic activity would be rebounding steadily and oil demand would be recovering. But on Monday, OPEC released a much grimmer forecast. "[S]tructural changes to the global economy are forecast to persist," the oil cartel wrote. Travel and tourism "are not expected to achieve pre-COVID-19 levels of activity before the end of 2021." The IEA, a well-regarded source of global energy data, agreed with the oil cartel's latest assessment, writing that "it is becoming increasingly apparent that COVID-19 will stay with us for some time." "There's some negative vibes out there," said Neil Atkinson, the head of Oil Industry and Markets Division at the IEA. "It just doesn't appear to be a simple case of this horrible thing comes along in the first six months of the year and then mercifully goes away again and we can all go back to normal. It's just not happening like that."

Oil mixed as storm threatens U.S. gulf production - Oil prices were mixed on Monday with U.S. crude rising as a tropical storm in the Gulf of Mexico forced rigs to shut down, but the gains were kept in check by wider concerns about excess supply and falling demand for fuels. U.S. West Texas Intermediate crude futures were up 9 cents, or 0.2%, at $37.42 a barrel by around 0050 GMT. Brent crude was down 3 cents at $39.80 a barrel. Both contracts ended last week lower, a second consecutive week of declines. Tropical Storm Sally gained in strength in the Gulf of Mexico west of Florida on Sunday and was poised to become a category 2 hurricane. The storm is disrupting oil production for the second time in less than a month after hurricane Laura swept through the region. Typically oil rises when production is shut but with the coronavirus pandemic getting worse demand concerns are to the fore, while global supplies continue to rise. "A lackluster driving season in the U.S. has seen the market reassess its view of U.S. demand," ANZ Research said in a note. Also "with U.S. refiners now shutting down for maintenance, crude demand is likely to remain soft." The U.S. is the world's biggest oil consumer and producer. BP Plc and Equinor ASA evacuated staff from some offshore platforms on Sunday after similar moves by Chevron Corp and Murphy Oil Corp the day before. In Libya, commander Khalifa Haftar committed to ending a months-long blockade of oil facilities, a move that would add more supplies to the market, although it was unclear if oil fields and ports would begin operations.

Oil edges lower, shrugging off Gulf of Mexico shut-ins (Reuters) - Oil prices slipped slightly on Monday amid concerns about a stalled global economic recovery and with Libya poised to resume production, and failed to get support from an impending storm which has disrupted U.S. output. Brent crude settled down 22 cents, or 0.6%, at $39.61 a barrel while U.S. West Texas Intermediate (WTI) crude futures CLc1 were down 7 cents, or 0.2%, at $37.26 a barrel. Both contracts ended last week lower, falling for a second week in a row. “The storm is taking production offline in the Gulf of Mexico, and the market doesn’t care - that shows just how bad the situation is,” said Bob Yawger, director of energy futures for Mizuho in New York. Hurricane Sally gained in strength in the Gulf of Mexico, west of Florida on Sunday and was poised to become a category 2 hurricane. The storm forced energy firms to shut 21.4%, or 395,790 barrels per day (bpd), of offshore crude oil production in the northern Gulf of Mexico, the U.S. government said on Monday. The storm is disrupting oil production for the second time in less than a month after Hurricane Laura swept through the region. Typically oil prices rise when production is shut down, but with the coronavirus pandemic getting worse, demand concerns are to the fore, while global supplies continue to rise. The path towards global fuel demand recovery is likely to be rocky, several senior industry executives said. “(Coronavirus) infection rates are on the rise again, there are localized lockdowns introduced in a growing number of countries hindering regional economic growth and the number of unemployed is failing to fall significantly,” oil broker PVM’s Tamas Varga said. “This leads to dismal oil demand growth.”The Organization of the Petroleum Exporting Countries said on Monday that world oil demand would tumble by 9.46 million barrels per day (bpd) this year, a sharper decline than it predicted in a report a month ago.

Oil edges higher but bleaker demand outlook weighs - Oil prices edged slightly higher on Tuesday, but forecasts of a slower than expected recovery in global fuel demand due to the coronavirus pandemic weighed. Brent crude was up 55 cents, or 1.4%, at $40.16 a barrel, while West Texas Intermediate crude futures were up 61 cents, or 1.6%, at $37.87 a barrel. Both contracts fell on Monday. The International Energy Agency (IEA) on Tuesday trimmed its 2020 outlook by 200,000 barrels per day (bpd) to 91.7 million bpd, citing caution about the pace of economic recovery. "We expect the recovery in oil demand to decelerate markedly in the second half of 2020, with most of the easy gains already achieved," the IEA said in its monthly report. Its revision chimes with forecasts from major oil industry producers and traders, with OPEC downgrading its oil demand forecast and BP saying demand might have peaked in 2019. World oil demand will tumble by 9.46 million bpd this year, the Organization of the Petroleum Exporting Countries said in a monthly report on Monday, more than the 9.06 million bpd decline OPEC expected a month ago. Still, a meeting of the OPEC+ joint ministerial committee on Thursday is not expected to make recommendations for deeper output cuts, but rather focus on compliance and compensation mechanisms for its current cuts, sources told Reuters. Concerns over supply disruptions in the United States from Hurricane Sally provided some price support. Energy companies, ports and refiners raced on Monday to shut down as Hurricane Sally grew stronger on its approach to the central U.S. Gulf Coast, the second significant hurricane to shutter oil and gas activity in the past month. Meanwhile, China's crude oil throughput in August rose from a year ago, reaching its second-highest level on record, as refineries worked to digest record imports earlier this year.

Oil prices climb as Hurricane Sally nears Mississippi - Oil prices climbed Tuesday as Hurricane Sally bore down on the Mississippi coast as a Category 1 storm. West Texas Intermediate crude oil was trading up 60 cents at $37.86 per barrel while RBOB Gasoline edged up 0.82 cents to $1.115 per gallon. “Hurricane Sally is a powerful slow-moving storm that can prove to be a nightmare for the U.S. energy Infrastructure,” Hurricane Sally, which has sustained winds of 85 miles per hour, down from 110 miles per hour, is expected to make landfall in the area east of Gulfport, Miss. Sally’s path is similar to that of Hurricane Laura, which hit Louisiana as a Category 4 storm last month and took about 80% of U.S. production offline. In preparation for the storm, U.S. refineries and offshore production facilities have begun shutting down. Phillips 66 Co. on Monday shut its 255,600 barrel per day refinery in Alliance, La., while Chevron Corp. and Royal Dutch Shell plc were among the companies that idled facilities in the Gulf of Mexico. About 16% of U.S. refinery capacity, or about 3.1 million barrels per day, are in the path of the storm. “The possibility of damaging flash floods will put pipelines and refineries in jeopardy and of course will also stop imports and exports in the Gulf Of Mexico,” A refinery takes one to two weeks to return to full capacity so long as there is no flooding nor power outages. U.S. gasoline and diesel inventories are well stocked ahead of the storm due to the demand destruction caused by lockdowns aimed at slowing the spread of COVID-19. Gasoline inventories are up 1% to 2% from a year ago while diesel stockpiles are higher by 30%, according to Andrew Lipow, president of the Houston-based oil consulting firm Lipow Associates.

Oil rises over 2% as U.S. Gulf Coast braces for hurricane (Reuters) - Oil prices rose more than 2% on Tuesday, supported by hurricane supply disruptions in the United States, but demand concerns loomed as energy industry forecasters predicted a slower-than-expected recovery from the pandemic. Brent crude gained 92 cents, or 2.3%, to settle at $40.53 a barrel, while U.S. West Texas Intermediate (WTI) crude futures rose $1.02, or 2.7%, to settle at $38.28 a barrel. Both contracts fell on Monday. Futures gained ahead of Hurricane Sally’s expected landfall on the U.S. Gulf Coast. More than a quarter of U.S. offshore oil and gas production was shut and key exporting ports were closed as the storm’s trajectory shifted east toward western Alabama, sparing some Gulf Coast refineries from high winds. “Harsh weather events in the U.S. cause some unpredictability about its oil production and that’s always good news for prices,” said Bjornar Tonhaugen, Rystad Energy’s head of oil markets. The outlook for oil demand remained weak, capping price gains. The International Energy Agency (IEA) trimmed its 2020 outlook by 200,000 barrels per day (bpd) to 91.7 million bpd, citing caution about the pace of economic recovery. “We expect the recovery in oil demand to decelerate markedly in the second half of 2020, with most of the easy gains already achieved,” the IEA said in its monthly report. The agency said commercial oil stocks in the developed world hit an all-time high of 3.225 billion barrels in July, and cut its forecast for implied stock draws for the second half of the year. The IEA's demand revision aligns with forecasts from major oil industry producers and traders. OPEC downgraded its oil demand forecast and BP BP.L said demand might have peaked in 2019. World oil demand will tumble by 9.46 million bpd this year, the Organization of the Petroleum Exporting Countries said in a monthly report on Monday, more than the 9.06 million bpd decline OPEC expected a month ago. Still, a meeting of the OPEC+ joint ministerial committee on Thursday is not expected to make recommendations for deeper output cuts, but focus rather on compliance and compensation mechanisms for its current cuts, sources told Reuters. Meanwhile, China’s crude oil throughput in August rose from a year ago, reaching its second-highest level on record, as refineries worked to digest record imports earlier this year.

Oil gains as hurricane shuts U.S. output, stockpiles fall - Oil prices rose on Wednesday, extending gains from the previous session, as a hurricane disrupted U.S. offshore oil and gas production and an industry report showed a big drop in U.S. crude stockpiles. Brent crude was trading up 15 cents, or 0.4%, at $40.68 a barrel by 0055 GMT, while U.S. crude gained 18 cents, or 0.5%, to $38.46 a barrel. Both contracts rose by more than 2% on Tuesday. More than 25% of U.S. offshore oil and gas output was shut and export ports were closed on Tuesday as Hurricane Sally sat just off the U.S. Gulf Coast. "Our current estimate for the total outage associated with the Sally weather system is between 3 million and 6 million barrels of oil over approximately 11 days," Rystad Energy said in a note. That is likely to help reduce stockpiles although refineries were also shut down, cutting demand for oil. U.S. crude oil inventories fell by 9.5 million barrels last week, although gasoline inventories increased, data from industry group the American Petroleum Institute showed on Tuesday. Analysts had expected oil stocks to increase by 1.3 million barrels. Official data on U.S. stockpiles is due out later on Wednesday and often conflicts with the industry figures. Meanwhile, oil producers and traders are painting a bleak picture for a recovery in fuel demand globally as the Covid-19 pandemic rages on, hammering economies.

Oil Jumps On Sally and Surprise Stock Draw, But Analysts Continue Bearish Stance -  Hurricane Sally may be destructive, but she worked her magic on oil prices for a second session on Wednesday, causing them to jump nearly 5 percent, supported by a surprise decline in U.S. inventories that further discredits the analytical conviction of demand declining in a Covid-19 world. Nearly 500,000 barrels per day (bpd) of offshore production has been taken offline due to the Category 2 hurricane, and this caused Brent to rise $1.69, or 4.17 percent, to $42.22 per barrel; West Texas Intermediate jumped $1.88, or 4.9 percent, to settle at $40.16 per barrel. Analysts previously convinced that rising Covid infections were causing demand destruction were jubilant when the U.S. Energy Information Administration on Wednesday reported a stock draw of 4.4 million barrels last week to 496 million barrels, compared to expectations for a 1.3 million barrel rise. Phil Flynn, senior market analyst at Price Futures Group Inc., said, "The inventory numbers are significant - refineries seemed to jump back to activity, gasoline demand jumped back, so that's definitely positive. "It seems that we're back on the track of the drawdown on supplies." Still, worry persisted over demand during the pandemic, and Reuters on Wednesday published a list of oil companies - including BP, and Exxon Mobil Corp - that were either trying to maintain, considering closing, or were permanently shutting certain operations.  The news agency wrote, "Consumption has not returned to pre-pandemic levels, and lower travel may be here to stay." Concern was also expressed on Wednesday that stockpiles of diesel and jet fuel are continuing to swell and impacting profit margins, giving refiners little incentive to run their plants harder: "If they don't crank up the run rate, they will never burn off the crude oil overhang already in storage," said Bob Yawger, director of the future division at Mizuho Securities USA. As is rapidly becoming the norm, despite analytical hand-wringing the global economic recovery as well as a prospective end to the pandemic continued to show promise on Wednesday, with markets responding strongly to the U.S. Federal Reserve's vow to keep interest rates near zero - a spur to economic activity - until at least 2023.

Oil jumps nearly 5% in best day since June as inventories fall, hurricane hits output - Oil prices jumped more than 4% on Wednesday, following a drawdown in U.S. crude and gasoline inventories and as Hurricane Sally forced a swath of U.S. offshore production to shut. Brent crude rose $1.69, or 4.17%, to $42.22 a barrel, while West Texas Intermediate crude gained $1.88, or 4.9%, to settle at $40.16. U.S. crude stocks fell 4.4 million barrels last week to 496 million barrels, their lowest since April, the U.S. Energy Information Administration said, compared with analysts' expectations in a Reuters poll for a 1.3 million-barrel rise, U.S. gasoline stocks fell 400,000 barrels, the EIA said, more than double the draw forecast, despite a 4 percentage point hike in refining utilization rates. "The inventory numbers are significant - refineries seemed to jump back to activity, gasoline demand jumped back so that's definitely positive," said Phil Flynn, senior analyst at Price Futures Group in Chicago. "It seems that we're back on the track of the drawdown on supplies." Sally, which made landfall on the U.S. Gulf Coast as a Category 2 hurricane, also boosted oil prices as more than a fourth of offshore output shut due to the storm. Nearly 500,000 barrels per day (bpd) of offshore crude oil production was taken offline in the U.S. Gulf of Mexico, according to the U.S. Interior Department, roughly a third of the shut-ins caused by Hurricane Laura, which landed farther west in August. Oil collapsed to historic lows as the coronavirus crisis hit demand. A record supply cut by OPEC and its allies, a grouping known as OPEC+, and an easing of lockdowns have helped Brent recover from a 21-year low below $16 in April. Prices have sunk in September, pressured by rising coronavirus cases and concerns about demand. The Organization of the Petroleum Exporting Countries and International Energy Agency both cut their demand outlooks this week. A panel of OPEC+ oil ministers meets to review the supply pact on Thursday and is unlikely to recommend further output curbs despite the price drop, sources told Reuters.

Oil reverses losses to gain 2% as OPEC urges compliance with production cuts -Oil prices rose about 2% on Thursday, turning positive as OPEC and its allies said the producer group would crack down on countries that failed to comply with output cuts and planned to hold an extraordinary meeting in October if oil markets weaken further. Brent oil futures extended their gains to trade up 2.3% at $43.21 a barrel. U.S. crude futures settled 81 cents, or 2%, higher at $40.97 per barrel. Both contracts rose more than 4% on Wednesday. The panel of major producers, including Saudi Arabia and Russia, did not recommend any changes to their current output reduction target of 7.7 million barrels per day (bpd), or around 8% of global demand, according to a draft press release and an internal report. The panel pressed laggards such as Iraq, Nigeria and the United Arab Emirates to cut more barrels to compensate for overproduction in May-July, while extending the compensation period from September to the end of December, according to three OPEC+ sources. "They were coming down hard on the UAE," said Phil Flynn, senior analyst at Price Futures Group in New York. The expectation that output could fall as the UAE and others trim production bolstered prices, he said. The OPEC news overshadowed the restart of U.S. offshore production after Hurricane Sally passed through the Gulf of Mexico and bearish U.S. economic news. U.S. energy companies were starting to return crews to offshore oil platforms in the Gulf of Mexico after Sally halted operations for five days, shutting down nearly 500,000 bpd of output. Prices were also under pressure from the slow economic recovery from the pandemic. Global coronavirus cases are expected to pass 30 million on Thursday, according to a Reuters tally. The U.S. Labor Department's report showed the number of Americans filing new claims for unemployment benefits fell last week, but remained at extremely high levels as the labor market recovery shifts into low gear and consumer spending cools. Even OPEC+ cautioned that the pandemic could continue to curb demand. An OPEC+ technical panel warned that a rise in coronavirus cases in some countries may curb oil demand despite signs of economic recovery and initial indications of a decline in oil stocks, according to an internal document seen by Reuters.

Oil jumps more than 10% for the week following OPEC meeting, decline in U.S. inventory - Oil prices were mixed on Friday, weighed after a Libyan commander said a blockade on the country’s oil exports would be lifted for a month, while supportive signals from an OPEC+ meeting lifted futures. Both the U.S. and Brent crude benchmarks posted weekly gains after Saudi Arabia pressed allies to stick to production quotas, Hurricane Sally cut U.S. production, and banks including Goldman Sachs predicted a supply deficit. Brent fell 15 cents to settle at $43.15 a barrel, but rose 8.3% for the week. U.S. oil futures rose 14 cents to settle at $41.11 a barrel, and gained 10.1% for the week. Market sentiment fell on Friday after eastern Libyan commander Khalifa Haftar announced he would lift his blockade of oil output for one month. The blockade slashed Libyan production to just over 100,000 barrels per day now from around 1.2 million bpd previously. It was unclear how quickly Libya could ramp up production. Oil futures also tracked U.S. stock indexes, which broadly fell. “A risk-off mentality is sprinkling down to oil. There are still concerns demand might get worse,” said Phil Flynn, analyst at Price Futures Group in Chicago. On Thursday, though, the key panel for the Organization of the Petroleum Exporting Countries and its allies pressed for better compliance with oil output cuts against the backdrop of falling crude prices. Saudi Arabia’s Prince Abdulaziz bin Salman told a gathering on Thursday that the OPEC+ producer group could hold an extraordinary meeting in October if the oil market soured because of weak demand and rising coronavirus cases, according to an OPEC+ source. “The alliance showed strength and reassured the market that if further action will be needed to discipline sub-compliers and balance the market, it would be taken,” said Bjornar Tonhaugen, Rystad Energy’s head of oil markets. Goldman Sachs predicted a market deficit of 3 million bpd by the fourth quarter and reiterated its target for Brent to reach $49 by year end and $65 by the third quarter of 2021.

Oil sector could face more distress during coronavirus crisis as it struggles to draw investments— Oil prices have plunged during the pandemic and the sector's crisis could get worse as new investments are unlikely to flow in, experts said at an energy conference this week. Pandemic-related movement restrictions stopped people from commuting and traveling, drastically reducing oil usage. Earlier this year, the May contract for U.S. benchmark West Texas Intermediate crude plunged deep into negative territory for the first time in its history. Overall, oil prices have dropped around 40% since the start of the year. With the poor performance across the industry, analysts at the S&P Global Platts' Platts Asia Pacific Petroleum Virtual Conference (APPEC) 2020 this week flagged that drawing investment to the sector would be a problem. Who is going to fund our next investment cycle? Indeed, is anyone going to be incentivized to fund us? Returns on the E&P companies as an investment have been poor. Ben Luckock, co-head of oil trading at commodity trading company Trafigura, said that it might be "hard to see where the investment comes from." Speaking at the APPEC conference, he pointed out that, as a result of the fall in oil prices and corporate valuations, capital expenditure in exploration and production (E&P) companies in the energy sector have plummeted. Such companies are involved in the early stages of energy production, which includes searching and extracting oil and gas. "Who is going to fund our next investment cycle? Indeed, is anyone going to be incentivized to fund us? Returns on the E&P companies as an investment have been poor," Luckock said. While returns on the S&P 500 have boasted a 70% increase since 2015, he pointed out returns of E&P companies fell by 70% over the same period.  "From a funding perspective, the energy sector in general faces two key problems. One is the relatively low shareholder return, and the second is the squeezed margins across the value chain,"  "This phenomena in the energy sector … poses key challenges for where financing is going to come from, and particularly so in a period of acute crisis." In a report earlier this year, research firm Rystad Energy projected that E&P companies could lose as much as $1 trillion in revenues this year — a 40% decline year on year. Last year, the industry made $2.47 trillion in revenues. "It doesn't bear comparison, people don't want to put their money into the E&Ps with good reason. That still leaves the world with a major problem," Luckock said. "Regardless of when peak demand happens, which is now harder to forecast than ever, we'll still need tens of millions of barrels of oil a day for years to come. And we need to see investment happen in order to find, develop and produce those barrels," he concluded.

OPEC and non-OPEC allies to review oil production cuts after dire demand warnings — A group of some of the world's most powerful oil-producing nations on Thursday met to review production policy, amid a faltering recovery from the pandemic-driven rout and a bleak outlook for energy demand. During the meeting between OPEC and non-OPEC allies, sometimes referred to as OPEC+, ongoing flexibility was emphasized as oil prices continue to trade at depressed levels. "The JMMC [Joint Ministerial Monitoring Committee] observed that the recovery has not been even across the world and an increase in COVID-19 cases has appeared in some countries," a statement from OPEC read. "In the current environment, the JMMC emphasised the importance of being pro-active and pre-emptive and recommended that participating countries should be willing to take further necessary measures when needed." OPEC+ did not announce additional output cuts at Thursday's meeting, which was in-line with analyst expectations. The energy alliance agreed in July to cut output by 7.7 million barrels per day from August through to December, in an effort to prop up oil prices by limiting supply. Iraq and others also pledged to pump below their quotas in September to offset overproduction earlier in the year. "The JMMC reiterated the critical importance of adhering to full conformity and compensating overproduced volumes as soon as possible," OPEC officials said. OPEC kingpin Saudi Arabia and non-OPEC leader Russia, the two biggest producers in the alliance, have both pushed for full conformity in recent months. Saudi Arabia's Energy Minister Prince Abdulaziz bin Salman has previously used OPEC meetings to publicly press recalcitrant members to stick to the pledged output cuts. International benchmark Brent crude advanced nearly 3% to $43.46 a barrel on Thursday afternoon, while U.S. West Texas Intermediate crude stood at $41.12, for a gain of 2.4% Oil prices have dropped more than 35% since the start of the year. "I do not believe we should expect any material change of course out of the OPEC meeting this week when they review market fundamentals, in part because compliance with previously agreed production cuts has been high," Tim Bray, senior portfolio manager at GuideStone Capital Management, told CNBC via email.

Sanctions against Turkey over Mediterranean gas drilling wouldn't achieve much, former EU ambassador says - — The European Union will not go as far as to impose sanctions on Turkey, one regional expert told CNBC, despite Ankara's controversial activity in the Mediterranean Sea. Turkey, Greece and Cyprus have been at odds over the former's exploration of energy resources in parts of Eastern Mediterranean waters that both Athens and Nicosia claim are part of their own territory. The countries and territories of this region include Greece, Turkey, Cyprus, Syria, Lebanon, Jordan, Israel, Palestine, Egypt and Libya. The dispute, which goes back over four decades, has escalated in recent weeks. Turkey's pursuit to expand its oil and gas resources in the Eastern Mediterranean even resulted in a minor collision between two frigates last month. Greece, increasingly angry at what it describes as "illegal" activity by Turkey, has called on its EU partners to impose "tough sanctions" on Ankara. EU leaders will be discussing the standoff between NATO members at an emergency meeting in two weeks' time. For its part, Turkey has claimed it has every right to prospect in the contested waters and accuses Greece of trying to grab an unfair share of maritime resources. "Leaders cannot do anything else but reinstate their solidarity with Greece," Marc Pierini, a former EU ambassador to Turkey, told CNBC earlier this month. "Sanctions would not give much result here," he said. Turkey's economy has struggled in recent years and the global recession has added further pressure to the embattled nation. In addition, the political party of President Recep Tayyip Erdogan has lost its traditional dominance in the country. Vassilis Ntousas, a policy expert at Chatham House, told CNBC that Erdogan was looking to "cement" his legacy by adopting a more assertive regional policy. He added that Turkey was looking "to play a stronger role in the region and it is willing to play hard ball."

Greece buys billions in French arms amid war tensions with Turkey - On Saturday, conservative Greek Prime Minister Kyriakos Mitsotakis announced a purchase of billions of euros in French weaponry and a large increase in the size of the Greek military. This massive increase in military spending, by a country which the European Union (EU) has devastated with billions of euros in draconian cuts to social spending over the last decade, marks a major escalation in Greece’s ongoing military standoff with Turkey. Mitsotakis indicated that Greece will purchase 18 Rafale fighter jets, four French naval frigates with naval helicopters, and a large supply of anti-tank weapons, torpedoes and missiles. It will also ask French firms to upgrade four Greek frigates that are already in service. Finally, Mitsotakis said that 15,000 more soldiers would be recruited to the Greek armed forces. “The time has come to reinforce our armed forces. … This is an important program that will form a national shield,” Mitsotakis declared in a speech in Thessaloniki. The sale comes after months of escalating threats and one direct collision last month between Greek and Turkish warships in the eastern Mediterranean, as Athens and Ankara lay competing claims to territorial waters and oil-rich seabeds in the region. In this dispute, Paris has aggressively backed Athens, sending several warships and fighter jets to the eastern Mediterranean to counterbalance Turkey’s numerical superiority over Greece. Paris also is seeking to undercut Turkey’s position in Africa and specifically in Libya, where French President Emmanuel Macron backs warlord Khalifa Haftar and Turkish President Recep Tayyip Erdoğan backs the Government of National Accord (GNA). Haftar and the GNA currently lead the two main factions in the decade-long civil war in Libya triggered by NATO’s war against the country in 2011. On Thursday, Macron had met other southern European heads of state in a so-called Med7 summit (with Italy, Spain, Portugal, Greece, Malta and Cyprus) in the Corsican city of Ajaccio. Beyond discussing the COVID-19 pandemic, which has seen the southern European powers seek new EU bailout funding, they pledged to renew France’s plans for a Union of the Mediterranean, vetoed by Berlin a decade ago. They also issued joint criticisms of Turkey’s maritime claims in waters also claimed by Greece or Cyprus. The Med7 states adopted a statement calling to “renew the southern partnership between the European Union, its member states and our southern neighbors. We await with interest the November 27 regional forum of the Union of the Mediterranean.” They also pledged to coordinate policy in the Sahel, where they aim to prevent African refugees from reaching Europe and to assist France’s ongoing bloody war in Mali.

Large Number Of Russian Warships Seen Deployed Between Syria & Cyprus -A large number of Russian warships were recently tracked off the coasts of Syria and Cyprus in the eastern Mediterranean region, the Russian publication Avia.Pro reported Thursday. According to the online publication, “experts are seriously concerned about the presence of at least 15 Russian warships and submarines off the coast of Syria. This is the first time such a large military formation has been seen here, which raises suspicions about whether Russia plans to engage in a military special operation against jihadists using the navy.In a maritime tracking image shared on their site, the 15 Russian warships and submarines can be seen positioned between the island nation of Cyprus and nearby Syria, along with some ships north of Egypt and another near the central part of the Mediterranean.According to the Telegram channel, Hunter Notes, “one of the last to appear off the coast of Syria was the tanker of the Northern Fleet of the Russian Navy ‘Akademik Pashin’; boats, and, obviously, this is far from the final number of ships of the Russian Navy located in the eastern part of the Mediterranean Sea.”This Russian naval buildup also comes at a time of increased tension between Turkey, Cyprus and Greece in the eastern Mediterranean, as the latter two countries have accused Ankara of encroaching on their territorial waters. Turkey's Erdogan has recently threatened external countries, warning them not to hinder Turkish hydrocarbon exploration vessels operating off Cyprus.

The Bahrain-Israel Mutual Recognition - This freshly announced mutual recognition follows the one between the UAE and Israel, which set a new pattern, with Bahrain and possibly others (Oman?) predicted to follow. I see three reasons why Bahrain was most likely to be next, although there are really two fundamental ones with the third arising from those. The most fundamental one is that of the 6 members of the Gulf Cooperation Council (GCC), now largely in shatters due to the sanctions on one of them (Qatar) by several others (Saudi Arabia (KSA), UAE, and Bahrain), is the only one where a Sunni minority is ruling over a Shia majority, with the Sunni-Shia conflict a central part of the conflict with Iran that many of them have, with Iran run by Shia, of course, where they are a majority. The Shia of Bahrain have been restive and rose up against King Hamad during the Arab Spring that began in 2011, only to be violently put down. But, unsurprisingly, the king and those around him are especially worried about the Shia and have strongly supported the anti-Iran coalition, which includes Israel. It is this alliance that is at the heart of the new round of recognitions, with UAE leader, Prince Zayed, arguably the leader of the anti-Iran group in the GCC, along with KSA Crown Prince, MbS, although due to opposition of the Saudi religious leaders who are concerned about the Palesrtinians, MbS himself is not seen as likely to follow UAE and Bahrain to recognize Israel, although there is clearly a de facto alliance against Iran between them.A second reason Bahrain was more likely to be next is that it is more subject to US pressure as it hosts the home base in the Persian Gulf of the US Navy’s 5th fleets, something rarely mentioned in the media, and has been since the 1950s. That dates back to when what is now the UAE was still being ruled by UK as the Trucial States. On top of that Bahrain is the smallest of the GCC members and also is the one that has been running out of oil more than the others (all of them produce at least some oil). In short, King Hamad is much more susceptible to US pressure to recognize Israel, although given his unhappiness with his Shia population and support for the anti-Iran coalition, he has been more inclined to go along anyway. Another reason, which basically follows these others, is that Bahrain is indeed part of the GCC group that is sanctioning/boycotting fellow GCC member, Qatar, for its apparent unwillingness to join the anti-Iran coalition. Indeed, Qatar and Iran have a joint deal for managing certain natural gas fields in the Gulf, and Qatar, which has the world’s highest per capita income, also hosts al=Jazeera, which has reported on dissident movements in several of its GCC partners, another source of anger. Of course, while Trump initially forgot about this as MbS and Jared Kushner pushed him into supporting the anti-Qatar sanctions, Qatar hosts a major US air base, so the US military did manage to get to Trump to back off overtly supporting the anti-Qatar boycott, although the US has failed to bring that conflict to a conclusion.