oil prices rose for a 7th consecutive week this week, as the first covid vaccines began to be administered and plans to distribute a second vaccine were approved for next week...after increasing by less than 1% to $46.57 a barrel last week as traders looked past bearish news to the rollout of a new Covid vaccine, the contract price of US light sweet crude for January delivery opened higher on Monday amid hopes that the rollout of coronavirus vaccines would lift global fuel demand and closed up 42 cents, or 0.9%, at $46.99 a barrel even after sliding more than 1% earlier in the session after OPEC said global oil demand would rebound more slowly in 2021 than previously thought...oil prices then slipped early in Tuesday's trading on worries about falling demand as the Covid-19 lockdowns tightened, but recovered to settle 63 cents higher at $47.62 a barrel, finding support from signs of stronger demand from China, as the rollout of the US Covid-19 vaccine helped ease concerns about weak energy demand....oil prices were lower again early Wednesday after the American Petroleum Institute had reported a surprise gain in US crude inventories, but turned around to close 20 cents higher at $47.82 a barrel after the EIA reported a larger-than-expected U.S. crude stockpile draw....oil prices then opened higher on Thursday on record-breaking refinery demand in China and India and continued rising to post a gain of 54 cents at $48.36 a barrel as signs of progress toward another round of economic relief by U.S. lawmakers kept prices at their highest levels in more than nine months...oil prices moved higher for a 5th straight session on Friday as efforts to pass another U.S. virus relief package added to optimism that a second vaccine rollout would help provide a long-awaited boost to demand. and went on to finish 74 cents higher at a nine month high of $49.10 a barrel, thus finishing the week more than 5% higher as this week's decline in the value of the US dollar to a two and a half year low played a significant role in pushing the oil complex higher all week...
natural gas prices also rose this week as major winter storms moved through the eastern US population centers....after rising fractionally to $2.591 per mmBTU last week after the EIA reported the largest early December draw from storage in 13 years, the contract price of natural gas for January delivery opened 4% higher on Monday as forecasts for back-to-back snow storms mid-week drove up demand expectations in the Mid-Atlantic and Northeast, with the January contract closing 9.1 cents higher at $2.682 per mmBTU...but gas prices stalled and then finished unchanged on Tuesday on a dip in LNG demand, even as cash prices remained strong in the Northeast ahead of forecast "near-blizzard" conditions....natural gas prices were nearly flat again on Wednesday, closing a half-cent lower at $2.677 per mmBTU, as traders awaited the report of an expected much larger-than-normal storage withdrawal the next day...however, the report of a large addition to storage failed to sway traders on Thursday, as gas prices fell 4.1 cents to $2.636 per mmBTU on forecasts for milder weather and lower heating demand next week, even as natural gas prices in the Northeast rose to their highest in a year as a major winter storm battered the region...but January contract prices rebounded on Friday and rose 6.4 cents to a two-week high of $2.700 per mmBTU on forecasts for near record liquefied natural gas exports, colder weather and more heating demand in late December, and thus finished the week with a gain of 4.2%...
the natural gas storage report from the EIA for the week ending December 11th indicated that the quantity of natural gas held in underground storage in the US had decreased by 122 billion cubic feet to 3,726 billion cubic feet by the end of the week, which left our gas supplies 284 billion cubic feet, or still 8.3% higher than the 3,442 billion cubic feet that were in storage on December 11th of last year, and 243 billion cubic feet, or 7.0% above the five-year average of 3,483 billion cubic feet of natural gas that have been in storage as of the 11th of December in recent years....the 122 billion cubic feet that were drawn out of US natural gas storage this week was less than the average forecast from an S&P Global Platts survey of analysts who had expected a 127 billion cubic foot withdrawal, but was higher than the average withdrawal of 105 billion cubic feet of natural gas that have typically been pulled out of natural gas storage during the same week over the past 5 years, and the 97 billion cubic feet withdrawal from natural gas storage seen during the corresponding week of 2019....
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending December 11th indicated that because of a big drop in our oil imports and big increase in our oil exports, we had to withdraw oil from our stored commercial supplies for the 14th time in the past twenty-one weeks and for the 20th time in the past forty-eight weeks ...our imports of crude oil fell by an average of 1,055,000 barrels per day to an average of 5,424,000 barrels per day, after rising by an average of 1,080,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 793,000 barrels per day to an average of 2,627,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,797,000 barrels of per day during the week ending December 11th, 1,848,000 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 100,000 barrels per day lower at 11,000,000 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 13,797,000 barrels per day during this reporting week...
meanwhile, US oil refineries reported they were processing 14,183,000 barrels of crude per day during the week ending December 11th, 253,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA's surveys indicated that a net total of 448,000 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 61,000 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 (-61,000) 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 balance sheet fudge factor that they label in their footnotes as "unaccounted for crude oil", thus suggesting that there must have been an error or errors of that size in the oil supply & demand figures that we have just transcribed....since last week's fudge factor was at +848,000 barrels per day, there was a 908,000 barrel per day balance sheet difference from a week ago, rendering the week over week supply and demand figures we have just transcribed unreliable...(for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....
further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 5,633,000 barrels per day last week, which was still 12.1% less than the 6,411,000 barrel per day average that we were importing over the same four-week period last year.....the 448,000 barrel per day net withdrawal from our total crude inventories was due to a 448,000 barrels per day withdrawal from our commercially available stocks of crude oil, while the oil supplies in our Strategic Petroleum Reserve remained unchanged....this week's crude oil production was reported to be 100,000 barrels per day lower at 11,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day lower at 10,500,000 barrels per day, while a 10,000 barrels per day decrease to 501,000 barrels per day in Alaska's oil production had no impact on the rounded national total...last year's US crude oil production for the week ending December 13th was rounded to 12,800,000 barrels per day, so this reporting week's rounded oil production figure was 14.1% below that of a year ago, yet still 30.5% 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 79.1% of their capacity while using 14,183,000 barrels of crude per day during the week ending December 11th, down from 79.9% of capacity during the prior week, and excluding the 2005, 2008, and 2017 hurricane-related refinery interruptions, one of the lowest refinery utilization rates of the past twenty-eight years....hence, the 14,183,000 barrels per day of oil that were refined this week were still 14.4% fewer barrels than the 16,562,000 barrels of crude that were being processed daily during the week ending December 13th of last year, when US refineries were operating at 90.6% of capacity...
even with the decrease in the amount of oil being refined, gasoline output from our refineries was higher for the first time in five weeks, increasing by 182,000 barrels per day to 8,522,000 barrels per day during the week ending December 11th, after our refineries' gasoline output had decreased by 244,000 barrels per day over the prior week...but since our gasoline production is still recovering from a multi-year low in the wake of this Spring's covid lockdown, this week's gasoline output was still 13.4% less than the 9,840,000 barrels of gasoline that were being produced daily over the same week of last year....at the same time, our refineries' production of distillate fuels (diesel fuel and heat oil) decreased by 67,000 barrels per day to 4,604,000 barrels per day, after our distillates output had increased by 84,000 barrels per day over the prior week....but since it's also just coming off a three year low, our distillates' production was still 9.2% less than the 5,072,000 barrels of distillates per day that were being produced during the week ending December 13th, 2019...
with the increase in our gasoline production, our supply of gasoline in storage at the end of the week increased for the 5th consecutive week and for 10th time in 24 weeks, rising by 1,020,000 barrels to 238,879,000 barrels during the week ending December 11th, after our gasoline inventories had increased by 4,221,000 barrels over the prior week...our gasoline supplies increased by less this week than last because the amount of gasoline supplied to US markets increased by 375,000 barrels per day to 7,975,000 barrels per day, and because our imports of gasoline fell by 178,000 barrels per day to 611,000 barrels per day while our exports of gasoline fell by 121,000 barrels per day to 784,000 barrels per day....after five increases now in a row, our gasoline supplies were 0.6% higher than last December 13th's gasoline inventories of 237,297,000 barrels, and about 4% above the five year average of our gasoline supplies for this time of the year...
meanwhile, with the modest decrease in our distillates production, our supplies of distillate fuels increased for the 3rd time in 13 weeks, for the 21st time in 37 weeks and for the 22rd time in the past year, rising by 167,000 barrels to 151,092,000 barrels during the week ending December 11th, after our distillates supplies had increased by 5,222,000 barrels during the prior week....our distillates supplies rose by so much less this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, jumped by 613,000 barrels per day to 4,002,000 barrels per day, and because our exports of distillates rose by 255,000 barrels per day to 1,070,000 barrels per day, while our imports of distillates rose by 213,000 barrels per day to 492,000 barrels per day....after this week's modest inventory increase, our distillate supplies at the end of the week were 20.9% above the 125,096,000 barrels of distillates that we had in storage on December 13th, 2019, and about 11% above the five year average of distillates stocks for this time of the year...
finally, with the drop in our oil imports and the big increase in our oil exports, our commercial supplies of crude oil in storage (not including the commercial oil in the SPR) fell for the 16th time in the past twenty-seven weeks and for the 20th time in the past year, decreasing by 3,135,000 barrels, from 503,231,000 barrels on December 4th to 500,096,000 barrels on December 11th....but even after that decrease, our commercial crude oil inventories were still more than 10% above the five-year average of crude oil supplies for this time of year, and almost 49% above the prior 5 year (2010 - 2014) average of our crude oil stocks as of the second weekend of December, with the disparity between those comparisons arising because it wasn't until early 2015 that our oil inventories first topped 400 million barrels....since our crude oil inventories had generally been rising over the past two years, except for this autumn and during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of December 11th were 11.9% above the 446,833,000 barrels of oil we had in commercial storage on December 13th of 2019, 13.3% more than the 441,457,000 barrels of oil that we had in storage on December 14th of 2018, and 12.9% above the 442,986,000 barrels of oil we had in commercial storage on December 8th of 2017...
OPEC's Monthly Oil Market Report
Monday of this past week saw the release of OPEC's December Oil Market Report, which covers OPEC & global oil data for November, and hence it gives us a picture of the global oil supply & demand situation over the fourth month of the extended agreement between OPEC, the Russians, and other oil producers, wherein they have agreed to cut production by 7.7 million barrels a day from the 2018 peak, reduced from the 9.7 million barrels a day cuts they had imposed on themselves during May, June and July....before we look at what this month's report shows us, we should again caution that estimating oil demand while the course of the Covid-19 pandemic remains uncertain is pretty speculative, and hence the demand estimates we'll be reporting this month should again be considered as having a much larger margin of error than we'd expect from this report during stable and hence more predictable periods..
the first table from this monthly report that we'll check is from the page numbered 49 of this month's report (pdf page 58), 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 thereby avert any potential disputes that could arise if each member reported their own figures...
as we can see from the above table of their oil production data, OPEC's oil output increased by 707,000 barrels per day to 25,109,000 barrels per day during November, from their revised October production total of 24,402,000 barrels per day...however, that October output figure was originally reported as 24,386,000 barrels per day, which thus means that OPEC's October production was revised 16,000 barrels per day higher with this report, and hence November's production was, in effect, a rounded 723,000 barrel per day increase from the previously reported OPEC production figure (for your reference, here is the table of the official October OPEC output figures as reported a month ago, before this month's revisions)...
from the above table, we can also see that the Libyan production increase of 656,000 barrels per day was the major reason for OPEC's November output increase, while the production increase of 75,000 barrels per day from the Emirates was offset by decrease of 76,000 barrels per day in Iraq's output, which you may recall were the two major producers who objected to the extension of the current production cuts in meetings earlier this month....also recall that this year's 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 for August and subsequent months, which is thus the agreement that covers OPEC's output in this month's report...however, war torn Libya and US sanctioned OPEC members Iran and Venezuela were exempt from the production cuts imposed by that agreement, and as you can see above, together those exempt members account for this month's production increase...
since there has never seemed to be a published table or listing available of how much each OPEC member was expected to produce under the eased production cuts of August through December, we've been including the table that 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...from the following table, we can easily compute the production quotas that each of the OPEC members was expected to hold to in November:
the above table shows the oil production baseline in thousands of barrel per day from which each of the oil producers was to cut from in the first column, a figure which is based on each of the producer's October 2018 oil output, ie., a date before the past year's and this year's output cuts took effect, and coincidently the highest production of the era for most of the producers party to these cuts; the second column shows how much each participant had originally committed to cut during May and June 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 through the end of this year amends the above such that each member would be allowed to increase their production cut shown above (ie, the "voluntary adjustment" shown above) by 20%...for example, Algeria's "cut" was expected to be 241,000 barrels per day from May thru July, which would reduce their oil production to 816,000 barrels per day over that period...under the new agreement for August and the following months, Algeria would reduce their "cut" by 20%, or to 193,000 barrels per day, thus allowing them to produce 864,000 barrels per day during November...offhand, by comparing this table's allocation +20% to the initial OPEC production table above, it appears that only the Congo has slightly exceeded their production quota for November, and not by any consequential amount...
the next graphic from this month's report that we'll highlight shows us both OPEC and world oil production monthly on the same graph, over the period from December 2018 to November 2020, and it comes from page 50 (pdf page 59) of the November OPEC Monthly Oil Market Report....on this graph, the cerulean blue bars represent OPEC's monthly oil production in millions of barrels per day as shown on the left scale, while the purple graph represents global oil production in millions of barrels per day, with the metrics for global output shown on the right scale....
after the reported 707,000 barrel per day increase in OPEC's production from what they produced a month earlier, OPEC's preliminary estimate indicates that total global liquids production increased by a rounded 1.62 million barrels per day to average 92.53 million barrels per day in November, a reported increase which apparently came after October's total global output figure was revised down by 280,000 barrels per day from the 91.17 million barrels per day of global oil output that was reported a month ago, as non-OPEC oil production rose by a rounded 910,000 barrels per day in November after that revision, with oil production increases by Canada, Norway and the US driving the non-OPEC production increase in November... after that increase in November's global output, the 92.53 million barrels of oil per day that were produced globally in November were 8.78 million barrels per day, or 8.7% less than the revised 101.31 million barrels of oil per day that were being produced globally in November a year ago, which was the 11th month of OPECs first round of production cuts (see the December 2019 OPEC report (online pdf) for the originally reported November 2019 details)...with this month's increase in OPEC's output, their November oil production of 25,109,000 barrels per day was at 27.1% of what was produced globally during the month, up from their revised 26.8% share of the global total in October.... OPEC's November 2019 production, which included 530,000 barrels per day from former OPEC member Ecuador, was reported at 29,551,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 3,912,000, or 13.5% fewer barrels per day of oil this November than what they produced a year ago, when they accounted for 29.6% of global output...
However, even after 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 26 of the December OPEC Monthly Oil Market Report (pdf page 35), and it shows regional and total oil demand estimates in millions of barrels per day for 2019 in the first column, and OPEC's estimate of oil demand by region and globally quarterly over 2020 over the rest of the table...on the "Total world" line in the fifth column, we've circled in blue the figure that's relevant for November, which is their estimate of global oil demand during the fourth quarter of 2020...
OPEC is estimating that during the 4th quarter of this year, all oil consuming regions of the globe will be using an average of 93.47 million barrels of oil per day, which is a 200,000 barrels per day downward revision from the 93.67 million barrels of oil per day they were estimating for the 4th quarter a month ago (note that we have encircled this month's revisions in green), reflecting quite a bit of coronavirus related demand destruction compared to 2019, when 4th quarter global demand averaged 100.95 million barrels per day....but as OPEC showed us in the oil supply section of this report and the summary supply graph above, OPEC and the rest of the world's oil producers were producing just 92.53 million barrels million barrels per day during November, which would imply that there was a shortage of around 940,000 barrels per day in global oil production in November when compared to the demand estimated for the month...
In addition to figuring November's global oil supply shortfall that's evident in this report, the downward revision of 280,000 barrels per day to October's global oil output that's implied in this report, partly offset by the 200,000 barrels per day downward revision to fourth quarter demand noted above, means that the 2,500,000 barrels per day global oil output shortage we had previously figured for October would now be revised to a shortage of 2,420,000 barrels per day...
However, note that in green we've also circled an upward revision of 160,000 barrels per day to third quarter demand, a quarter when there was already a shortage of oil production as compared to demand....that upward revision to demand means that the 440,000 barrels per day global oil output shortage we had previously figured for September would now be revised to a shortage of 600,000 barrels per day, that the 1,570,000 barrels per day global oil output shortage we had previously figured for August would now be revised to a shortage of 1,730,000 barrels per day, and that the 2,890,000 barrels per day global oil output shortage we had previously figured for July would now be revised to an estimated shortage of 3,050,000 barrels per day...
Note that we've also circled a downward revision of 30,000 barrels per day to second quarter demand, a quarter when there was a large excess of oil production due to coronavirus related lockdowns...based on that downward revision to demand, our previous estimate that there was a surplus of 4,870,000 barrels per day in June would now be revised up to a 4,900,000 barrels per day surplus, that the oil surplus of 7,650,000 barrels per day that we had previously figured for May would have to be revised to a surplus of 7,680,000 barrels per day, and that the 16,400,000 barrels per day surplus that we had previously figured for April would have to be revised to a surplus of 16,430,000 barrels per day...
Meanwhile, with no revisions impacting previously published first quarter figures, the record global oil surplus of 17,750,000 barrels per day we had previously figured for March would remain unchanged. as would the 1,970,000 barrel per day global oil production surplus we had for February and the 900,000 barrel per day global oil output surplus we had for January...so despite the shortage of oil that has developed in the second half of this year, 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 13th time in the past fourteen weeks during the week ending December 18th, but for just the 15th time in the past 40 weeks, and hence it is still down by 56.4% over that thirty-eight week period....Baker Hughes reported that the total count of rotary rigs running in the US rose by 8 to 346 rigs this past week, which was still down by 467 rigs from the 813 rigs that were in use as of the December 20th report of 2019, and was also still 58 fewer rigs than the all time low rig count prior to this year, and 1,583 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business....
The number of rigs drilling for oil increased by 5 rigs to 263 oil rigs this week, after rising by 12 oil rigs the prior week, leaving us with 422 fewer oil rigs than were running a year ago, and still less than a sixth of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014....at the same time, the number of drilling rigs targeting natural gas bearing formations increased by 2 to 81 natural gas rigs, which was still down by 44 natural gas rigs from the 125 natural gas rigs that were drilling a year ago, and just 5% 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, two rigs classified as 'miscellaneous' were drilling this week; one in Lake County, California, and a new one in the Permian basin in Reagan county Texas, while a year ago there were three such "miscellaneous" rigs deployed...
The Gulf of Mexico rig count increased by 3 to 16 rigs this week, with 13 of those rigs drilling for oil in Louisiana's offshore waters and three drilling for oil offshore from Texas...that was still 8 fewer Gulf rigs than the 24 rigs drilling in the Gulf a year ago, when 22 Gulf rigs were drilling for oil offshore from Louisiana, one rig was drilling for natural gas in the Mississippi Canyon offshore from Louisiana, and one oil rig was deployed offshore from Texas...since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week's national offshore rig figure are equal to the Gulf rig counts....however, in addition to those rigs offshore, two rigs continue to drill through inland bodies of water this week, one in St Mary parish in southern Louisiana and the other in Chambers County, Texas, just east of Houston, while a year ago there were no such rigs drilling on US inland waters..
The count of active horizontal drilling rigs was up by 2 to 308 horizontal rigs this week, which was still 398 fewer horizontal rigs than the 706 horizontal rigs that were in use in the US on December 20th of last year, and less than a quarter of the record of 1372 horizontal rigs that were deployed on November 21st of 2014....in addition, the vertical rig count was up by 2 to 17 vertical rigs this week, but those were still down by 39 from the 56 vertical rigs that were operating during the same week of last year....at the same time, the directional rig count was up by 4 to 21 directional rigs this week, and those were also still down by 30 from the 51 directional rigs that were in use on December 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 December 18th, the second column shows the change in the number of working rigs between last week's count (December 11th) and this week's (December 18th) count, the third column shows last week's December 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 December, 2019...
after last week's rather widespread activity, rig changes this past week were again concentrated in the Permian basin....checking first for the details on the Permian in Texas, we find that one rig was added in Texas Oil District 8, which corresponds to the core Permian Delaware, while one rig was pulled out of Texas Oil District 8A, which roughly corresponds to the northern part of the Permian Midland, which means that the net Permian rig count in Texas was unchanged...since the Permian basin rig count was up by six rigs nationally, that means that all six rigs that were added in New Mexico must have been added in the farthest west reaches of the Permian Delaware, to account for the national Permian increase (however, note that since a miscellaneous rig was added in the Permian on the Edwards Plateau in Reagan county, Texas this week, which is inTexas Oil District 7C, an oil rig must have been shut down in that District at the same time, and hence the Permian only accounts for an increase of 5 oil rigs this week)...elsewhere in Texas, we have the two rigs that were added offshore, and a rig that was added in Texas Oil District 6, which is in the area of the Haynesville shale but apparently not targetting it....meanwhile, in Oklahoma we have a rig pulled out of the Cana-Woodford despite no change in the state, which mean that an Oklahoma rig was added in an "other" basin that Baker Hughes does not track...on the other hand, in Wyoming, there was a rig pulled out of the Denver-Julesburg Niobrara chalk, which means that the 4 rig remaining in Wyoming are also deployed in basins that Baker Hughes does not track..meanwhile, to arrivie at the 2 rigs increase of rig targeting natural gas, we had a natural gas rig added in the Eagle Ford of southeast Texas while an Eagle Ford oil rig was pulled out at the same time, and another gas rig added in a basin that Baker Hughes does not track, which appears to be the rig that was added in Angelina county Texas, in Texas Oil District 6...
DUC well report for November
Monday of this past week saw the release of the EIA's Drilling Productivity Report for December, which includes the EIA's November data for drilled but uncompleted oil and gas wells in the 7 most productive shale regions....that data showed a decrease in uncompleted wells nationally for the 17th time in the past twenty-one months in November, as completions of drilled wells and drilling of new wells both increased, but remained subued....for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 144 wells, falling from 7,474 DUC wells in October to 7,330 DUC wells in November, which was also 7.3% fewer DUCs than the 7,907 wells that had been drilled but remained uncompleted as of the end of November of a year ago...this month's DUC decrease occurred as 334 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during November, up from the 316 wells that were drilled in October, while 478 wells were completed and brought into production by fracking, up from the 446 completions seen in October, but down by 59.2% from the 1,172 completions seen in November of last year....at the November completion rate, the 7,330 drilled but uncompleted wells left at the end of the month represents a 15.3 month backlog of wells that have been drilled but are not yet fracked, down from the 18.8 month DUC well backlog of a month ago, with the understanding that this normally indicative backlog ratio is being skewed by completions that are one-third of the previous norm...
both oil producing regions and natural gas producing regions saw DUC well decreases in November, while no basins reported a DUC increase...the number of uncompleted wells remaining in the Niobrara chalk of the Rockies' front range fell by 41, decreasing from 497 at the end of October to 456 DUC wells at the end of November, as 23 wells were drilled into the Niobrara chalk during October, while 64 Niobrara wells were being fracked....at the same time, DUC wells in the Eagle Ford of south Texas decreased by 32, from 1,063 DUC wells at the end of October to 1,031 DUCs at the end of November, as 33 wells were drilled in the Eagle Ford during November, while 65 already drilled Eagle Ford wells were completed...meanwhile, the number of uncompleted wells remaining in Oklahoma's Anadarko decreased by 23, falling from 648 at the end of October to 625 DUC wells at the end of November, as just 14 wells were drilled into the Anadarko basin during October, while 37 Anadarko wells were being fracked....in addition, DUCs in the Permian basin of west Texas and New Mexico decreased by 20, from 3,536 DUC wells at the end of October to 3,516 DUCs at the end of November, as 148 new wells were drilled into the Permian, while 168 wells in the region were completed...and there was also a decrease of 12 DUC wells in the Bakken of North Dakota, where DUC wells fell from 818 at the end of October to 806 DUCs at the end of November, as 20 wells were drilled into the Bakken in October, while 32 of the drilled wells in that basin 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 11 wells, from 589 DUCs at the end of October to 578 DUCs at the end of November, as 59 wells were drilled into the Marcellus and Utica shales during the month, while 70 of the already drilled wells in the region were fracked....at the same time, the natural gas producing Haynesville shale of the northern Louisiana-Texas border region saw their uncompleted well inventory decrease by 5 to 318, as 37 wells were drilled into the Haynesville during November, while 42 of the already drilled Haynesville wells were fracked during the same period....thus, for the month of November, DUCs in the five major oil-producing basins tracked by this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a total of 128 wells to 6,434 wells, while the uncompleted well count in the natural gas basins (the Marcellus, Utica, and the Haynesville) decreased by 16 wells to 896 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas...
+++++++++++++++++++++++++++++++
"If Only I Would've Known" Oil & Gas Whistleblowers Speak Out About Exposure to Radioactivity on Fracking Jobs - Public Herald - The year is 2014, and the sleepy mining and agricultural towns of Northern Appalachia have transformed into gold-rush towns. But this is a new type of gold – Shale gas. These towns sit above an underground formation called the Marcellus Shale that could help make America the world’s greatest producer of natural gas – and in 2014 the Marcellus region is booming. The restaurants are buzzing, bars packed, hotels full for the first time since many people can remember. Each generation of this area has seen the boom and the bust of other major industries – timber, coal, steel – and shale gas is the next one. It’s marketed as energy independence, good paying blue collar jobs, the American Dream. In areas where decades of economic decline have created a culture of need, this dream is welcomed with open arms. Near Pittsburgh, Brandon is hearing about the same economic dream. He grew up in an industrial town as Pittsburgh’s steel industry died and crumbled. Running through his town was Chartiers Creek, which has long been one of the most industrially polluted streams in the region. As a kid, it was common knowledge to stay out of that water. Yet – he saw the environment start to bounce back as industry left the area and regulation increased. In 2013, he took a job with a local environmental cleanup company, Sunpro. They focused on hazardous material cleanup for oil and gas operations. The pay was good, the hours long, and they often worked for some of the big players in the Marcellus of southwestern Pennsylvania, like Range Resources. Brandon thought,“Regardless of how many regulations you can have in place, accidents happen,” and he had the skills and tools to make sure any hazardous materials were properly cleaned up. He and his colleagues took their jobs seriously and worked hard to make sure it was all done according to the books. Now the year is 2020. Brandon is standing next to Chartiers Creek, about 20 miles upstream from where he grew up. He left the industry a number of years ago and now owns his own business that provides holistic support for people dealing with serious illnesses like cancer. Nearby, foamy water spurts out into the creek from a massive concrete pipe leading to the local municipal sewage treatment plant. There’s evidence people come here to play – fishing lures, well worn paths, a lonely muddy sock. Across the stream is the local municipal landfill, Arden Landfill, where he used to drop off waste from the drilling process when he worked for Sunpro. In the past decade, this landfill has received over a million tons of solid oil and gas waste and is now one of the highest geological features in an area known for its rolling hills.
'The Fossil Fuel Industry Is Terrified': Gas Company Sues to Destroy Small Town's Rights of Nature Law – DeSmog In a clear signal of how the fossil fuel industry feels about efforts to enact Rights of Nature protections that safeguard communities and the environment from the impacts of coal, gas, and oil development, an energy company has — yet again — filed a federal lawsuit challenging a local law in Grant Township, Pennsylvania. This is the second time that Pennsylvania General Energy Company (PGE) has sued over the 2015 law, which aims to keep fracking waste injection wells out of the community of about 700 people. Though the Pennsylvania Department of Environmental Protection (DEP) also previously sued the township, earlier this year—in what Rolling Stone described as a “stunning reversal” — the department cited the law when rescinding PGE a waste injection permit. In March, the state department told the company — which is appealing the decision — that “Grant Township's Home Rule Charter bans the injection of oil and gas waste fluids… Therefore, the operation of the Yanity well as an oil and gas waste fluid injection well would violate that applicable law.” “We are over the moon that the permit was rescinded,” Grant Township Supervisor Vice-Chair Stacy Long said at the time. “However, we know the permit should never have been issued in the first place. We can't forget that DEP sued us for three years, claiming our charter was invalid. Now they cite that same charter as a valid reason to deny the industry a permit. It's hypocritical at best. Add this to the pile of reasons Grant Township did not trust the DEP to protect our environment, and why we've had to democratically work at the local level to protect our community.” Approved by over 70 percent of Grant Township's voters five years ago, the law recognizes the rights of local ecosystems. The measure was drafted with help from the Community Environmental Legal Defense Fund (CELDF), which explains that Rights of Nature “is honoring and recognizing that nature has the right to exist, flourish, and thrive.” The global movement calls for shifting away from the view of nature as property that owners and companies can legally pollute and destroy. “The fossil fuel industry is terrified the tactics taken in Grant Township are spreading,” Chad Nicholson, a CELDF organizer in Pennsylvania, said in a statement Tuesday. “This community continues to act as a lighthouse in a raging storm made up of oil and gas corporations, state permitting agencies, and enabling courts that have crashed down on them for over five years.”
Pennsylvania’s drilling impact fee sinks to record low amid pandemic losses --Pennsylvania’s drilling impact fee will hit a record low this year after the pandemic zapped energy demand. The Independent Fiscal Office said the price of natural gas on the New York Mercantile Exchange (NYMEX), upon which the impact fee is based, declined 21 percent this year, landing at $2.08. The IFO estimates that any price below $2.25 would deplete funding for the impact fee by $53 million. The impact fee, first established under Act 13 of 2012, authorizes a tax on unconventional gas wells. The Pennsylvania Public Utility Commission collects and redistributes the proceeds across the state’s 67 counties for economic development projects. In 2018, the impact fee reached $254 million after a state Supreme Court ruling narrowed the definition of a certain type of low-producing well called a “stripper well,” boosting fee collections by $30 million. But like most other industries in 2020, the pandemic hit natural gas production hard, depressing prices both in and out of state. “The COVID-related economic slowdown has softened global energy demand and the lack of pipeline take-away capacity in the region has impacted commodity prices, leading to a pullback in production activity,” said David Spigelmyer, president of the Marcellus Shale Coalition. The coalition said the fee has generated nearly $2 billion in less than a decade for local governments. Gov. Tom Wolf and Democrats have proposed an additional severance tax on natural gas producers to help fund infrastructure projects across the state, though it remains unpopular among Republicans who worry about driving companies out. Natural gas production supports about 24,000 jobs, according to state data, and is second only to Texas in terms of overall gas procured, exceeding 6.8 trillion cubic feet in 2019.
Oil spill reported at lake in Kanawha County (WSAZ) - Investigators with the WVDEP’s Environmental Enforcement and Homeland Security Emergency Response units are on scene of a reported oil spill in a creek that flows into the Chaweva Lake in Cross Lanes. The incident report says just before 2:30 Saturday afternoon, someone called reporting fish kill and an unknown petroleum-scented oil. The report says the caller said a sheen had started appearing on the lake as well, and oil was coming from the Rocky Fork Watershed. Officials say the quantity of the spill is unknown, but it is considered hazardous or toxic. The West Virginia Division of Natural Resources has also been notified. WSAZ has a crew headed to the scene.
DEP investigating petroleum spill that killed wildlife in creek feeding Lake Chaweva - The West Virginia Department of Environmental Protection is investigating an oil spill into a creek that flows into Lake Chaweva in Cross Lanes that was reported Saturday. The DEP’s Environmental Enforcement and Homeland Security Emergency Response teams are investigating the source of the spill and working with personnel from the Union Public Service District after a caller reported fish kill in a creek that feeds Lake Chaweva caused by an unknown petroleum-scented oil that was present at the site, according to a DEP report on the spill. A West Virginia Division of Natural Resources district fisheries biologist documented at least seven species of dead fish and noted dead salamanders, crayfish and worms as a result of the spill, according to Andy Malinowski, director of the state Department of Commerce’s Office of Marketing and Communications. Malinowski added that official numbers were not yet available. The caller noted a sheen had started appearing on the lake and that oil flow was coming from the path of the Rocky Fork watershed, according to the report. DEP staff placed absorbent pads and booms to clean up the material that are still in place as a precaution, said Terry Fletcher, DEP acting communications director. Fletcher declined to estimate how much product was spilled, saying an accurate estimate may not be possible given recent weather conditions and the nature of petroleum-based spills.
PA Pipeline Shift Will 'Share The Wealth' With Midwest Markets -- Energy Transfer’s (ET) recent announcement that it will convert the Mariner East 1 pipeline to help transport refined products from the Midwest to Pennsylvania and the northeast will be a boon to both northeast energy consumers and midwest producers, industry analysts say. “PA Access will utilize part of our Mariner East 1 pipeline to provide about 20,000 – 25,000 barrels per day of refined products from the Midwest supply regions through our Allegheny Access pipeline system into Pennsylvania and to markets in the Northeast,” the company said in November. The service will begin in the fourth quarter of 2020. “This is a critical development that will allow ET…to move in either direction between Chicago and New York City,” Jude Clemente, an editor for Real Clear Energy and a Principal at JTC Energy Research Associates, told InsideSources. Mark that up as a win for domestic energy security. This move will strengthen the network of transport options available. The increased access is a likely boon to Midwest refineries and suppliers, but also fills a void left by the recently closed Philadelphia Energy Solutions refinery. “The reality is that the Midwest region has been producing more gasoline, for instance, than it requires, so this move gives ET much-needed flexibility,” Clemente said. For the past few years, Mariner East 1 has transported ethane and propane from Ohio and Pennsylvania to the Marcus Hook Industrial Complex in Delaware County. The pipeline was first built in the 1930s and was converted to transporting natural gas liquids in 2015, with the other pipelines in the Mariner system nearing completion of construction and expected to be online soon. The new pipeline will share 80 percent of the same pipeline corridor as its predecessor, passing through 17 Pennsylvania counties. “The portion of the 8-inch line that we’re converting that will be moving refined products,” said Energy Transfer Chief Commercial Officer Marshall McCrea, in early November. “I suspect we could see more conversions like this move from ET and others because new greenfield builds are likely going to become more difficult to come by under a different administration and congress,” Clemente concluded.
Forest Service supports Mountain Valley Pipeline route through Jefferson National Forest - wvgazettemail.com - The Mountain Valley Pipeline inched closer Friday to the Jefferson National Forest, where plans call for it to pass through 3.5 miles of woodlands and 90 feet under the Appalachian Trail. An environmental impact statement released by the U.S. Forest Service supported running a buried, 42-inch diameter pipe through the forest to transport natural gas at high pressure.A final decision is expected early next year for a portion of the pipeline in Giles and Montgomery counties and Monroe County, West Virginia. Building the pipeline is “consistent with the Forest Service’s mission,” the 315-page document stated at one point. It later added that under numerous laws and regulations governing all national forests, “the implementation of projects related to oil and gas development and transport is permissible.” However, the magnitude of Mountain Valley’s plans for a 303-mile pipeline would not normally be allowed under a resource management plan for the Jefferson National Forest So the environmental impact statement recommends 11 amendments to the forest’s plan — changing standards for the impacts on soils, old-growth forests and scenic integrity — to make it conform to Mountain Valley’s blueprint. “As mountain defenders and trail protectors, we won’t soon forget this parting gift to the gas industry,” said Russell Chisholm, co-chair of the anti-pipeline Protect Our Water, Heritage, Rights coalition. The pipeline’s route through the forest was approved three years ago, but the decision was thrown out in 2018 by a federal appeals court. In siding with environmental groups who challenged the permit, the 4th U.S. Circuit Court of Appeals chastised the Forest Service for being too accepting of Mountain Valley’s assurances that erosion and sedimentation would not be a major problem. Muddy runoff, both in the forest and elsewhere on the pipeline’s mountainous route, has complicated construction from the start.
MVP Clears Major Permitting Hurdle as Forest Service Completes Supplemental Review The U.S. Forest Service (USFS) has finalized a supplemental environmental review of the Mountain Valley Pipeline (MVP), a key step in resolving a permitting setback that has prevented construction on a small portion of the project routed through the Jefferson National Forest. Late last week, the USFS released a final supplemental environmental impact statement for the 303-mile, 42-inch diameter natural gas conduit. The move clears the way for the Bureau of Land Management (BLM) to issue a right-of-way (ROW) for the pipeline’s proposed 3.5-mile crossing through the Jefferson National Forest near the Virginia/West Virginia border. The document was prepared in response to a 2018 ruling by the U.S. Court of Appeals for the Fourth Circuit, which vacated and remanded an earlier USFS decision permitting the project to cross protected forest lands. The latest environmental review “addresses the issues identified by the court and any relevant new information and changed circumstances,” according to USFS. The USFS review includes proposed amendments to the agency’s management plan to allow for the pipeline’s construction.“A Forest Service amendment is needed because the project would not be consistent with several Forest Plan standards,” the agency said. “Relatedly, there is a need to determine what terms and conditions should be provided to the BLM for incorporation into the ROW grant in order to protect resources and the public interest consistent” with the Mineral Leasing Act. Federal law requires a 30-day interval between finalizing the environmental impact statement and an agency record of decision, according to analysts at ClearView Energy Partners LLC. “We would therefore look for BLM to reissue these authorizations in mid-January 2021, most probably ahead of President-elect Joe Biden’s inauguration,” “We think it is possible, but not necessarily probable, that the incoming Biden Administration could act to suspend these permits if they are issued in the waning hours of the outgoing Trump Administration.” Still, while “progressive members of the Democratic Party” might pressure the new administration to suspend the permits, “we think that since the pipeline is largely complete, overt executive action may not be in the offing.” MVP continues to face legal challenges to its federal permitting, including a recent stay of updated stream-crossing permitting handed down by the Fourth Circuit. The court, however, sided with the pipeline in declining to issue a stay of the updated Endangered Species Act review for the project.
USFS Finalizes Review, Clearing Way for MVP to Cross National Forest- The U.S. Forest Service (USFS) has finalized a supplemental environmental review of the Mountain Valley Pipeline (MVP), a key step in resolving a permitting setback that has prevented construction on a small portion of the project routed through the Jefferson National Forest. Late last week, the USFS released a final supplemental environmental impact statement for the 303-mile, 42-inch diameter natural gas conduit. The move clears the way for the Bureau of Land Management (BLM) to issue a right-of-way (ROW) for the pipeline’s proposed 3.5-mile crossing through the Jefferson National Forest near the Virginia/West Virginia border.The document was prepared in response to a 2018 ruling by the U.S. Court of Appeals for the Fourth Circuit, which vacated and remanded an earlier USFS decision permitting the project to cross protected forest lands. The latest environmental review “addresses the issues identified by the court and any relevant new information and changed circumstances,” according to USFS. The USFS review includes proposed amendments to the agency’s management plan to allow for the pipeline’s construction.“A Forest Service amendment is needed because the project would not be consistent with several Forest Plan standards,” the agency said. “Relatedly, there is a need to determine what terms and conditions should be provided to the BLM for incorporation into the ROW grant in order to protect resources and the public interest consistent” with the Mineral Leasing Act. Federal law requires a 30-day interval between finalizing the environmental impact statement and an agency record of decision, according to analysts at ClearView Energy Partners LLC. “We would therefore look for BLM to reissue these authorizations in mid-January 2021, most probably ahead of President-elect Joe Biden’s inauguration,” ClearView said in a note to clients Friday. “We think it is possible, but not necessarily probable, that the incoming Biden Administration could act to suspend these permits if they are issued in the waning hours of the outgoing Trump Administration.” Still, while “progressive members of the Democratic Party” might pressure the new administration to suspend the permits, “we think that since the pipeline is largely complete, overt executive action may not be in the offing.”
Mountain Valley gets another approval for pipeline construction - Mountain Valley Pipeline gained another 17 miles Thursday in its quest to complete construction of the natural gas pipeline by the end of next year. The Federal Energy Regulatory Commission approved the company’s request to resume work on a stretch of the 303-mile pipeline that passes through Giles and Craig counties, between two sections of the Jefferson National Forest. In 2018, an appellate court threw out a U.S. Forest Service permit for the buried pipeline to cross 3.5 miles of the forest. FERC then issued a stop-work order for an approximately 25-mile segment of the pipeline, from where it enters the national forest atop Peters Mountain on the Giles County-West Virginia line, then runs through private property before re-entering a second part of the forest in Montgomery County. The buffer zone created by FERC was intended to prevent muddy runoff from construction zones on private land from being washed into adjacent federal woodlands. But in a 2-1 decision Thursday, the commission ruled that Mountain Valley had presented sufficient evidence to show that resuming work on a 17-mile segment of the pipeline on private land would not harm the forest. “That is a serious mistake,” commissioner Richard Glick wrote in a strongly worded dissent. Glick noted that Mountain Valley has yet to get renewed approval to pass through the national forest, and that other permits involving stream crossings and the protection of endangered species have been tossed out on appeal. “Given the MVP permits’ checkered litigation record, we should not authorize MVP to commence piece-meal construction, including construction affecting a national forest, before it has all the permits needed,” he wrote.
Commission OKs More MVP Work Near National Forest; Glick Dissents - In a split decision, FERC on Thursday authorized Mountain Valley Pipeline LLC (MVP) to resume pipeline construction activities within a 25-mile exclusion zone near the Jefferson National Forest. The order allows for some construction between mileposts 196.0 and 221.0 of the pipeline, where work had been on hold following a 2018 court ruling vacating federal authorization for MVP’s 3.5-mile crossing of national forest lands.Earlier this year, MVP asked the Federal Energy Regulatory Commission to reduce the size of the exclusion zone and allow for additional construction activities to resume, providing supporting information indicating that portions of the route could be reopened without impacting the national forest. Chairman James Danly and Commissioner Neil Chatterjee, who made up the majority in the 2-1 vote approving Thursday’s order, said they agreed with staff findings that “project construction activities in the area from milepost 201.6 to 218.6 would not contribute sediment to any portion of the Jefferson National Forest or contribute sediment or turbidity to any waterbody” that would then flow into the forest. Danly and Chatterjee are both Republicans. Democrat Richard Glick dissented.Thursday’s decision follows the recent conclusion of a supplemental environmental review conducted by the U.S. Forest Service (USFS) amending its management plan to allow for construction through protected lands. Project opponents have argued that MVP should not be allowed to resume construction while authorization for the forest crossing remains pending. Citing analysis on alternative routes conducted by BLM in 2018 and earlier this year, Danly and Chatterjee found that “the record gives us no reason to assume that there will be a change to the proposed route through the Jefferson National Forest, and authorizing the resumption of work outside of the Jefferson National Forest is permissible and does not improperly limit options available to BLM and Forest Service.” Glick in the dissenting opinion voiced strong disagreement with the majority, calling their position “bewildering.” He went even further, suggesting that construction should not move forward anywhere along the route until MVP once again had all requisite permits in hand.“Although unstated in today’s order, the Commission has previously taken the position that Environmental Condition 9” of MVP’s certificate of public convenience and necessity “is relevant only when a project developer first begins construction,” Glick wrote. “That interpretation is nonsensical and waters down an important environmental and landowner protection measure.” If serving the public interest meant that MVP had to have all required permits before starting construction, the same standard should apply when the developer seeks to resume construction, he said. “I see no reason why it is not equally important to require the pipeline to meet the same condition every time it recommences construction, especially after having a necessary permit invalidated by court order,” Glick wrote.
Virginia Natural Gas planning $205 million pipeline project in ‘rural crescent’ -Virginia Natural Gas is back with plans for a $205 million natural gas expansion project that would add about six miles of new natural gas pipeline and a compressor station in Prince William County’s “rural crescent,” four miles of pipeline in Fauquier County and upgrades to a metering station in Hanover County. The application for the project comes only weeks after a much larger Virginia Natural Gas expansion project, known as the "Header Improvement Project," was dismissed by the State Corporation Commission when plans for a new power plant in Charles City County, which the pipeline project would have serviced, failed to materialize.The new pipeline project, called the "Virginia Natural Gas Interconnect," is a scaled back version of the original proposal and cites increased demand from Columbia Gas of Virginia and Dominion Energy subsidiary Virginia Power Services Energy as the primary reason for the expansion.The new pipeline would start at an interconnect station along the existing Transco pipeline near the Prince William-Fauquier county line and traverse six miles through Prince William County and four miles through Fauquier County along a utility corridor before connecting with an existing pipeline in the Quantico area. The compressor station, an industrial facility that aids in the transportation of natural gas from one location to another, would be built on 36 acres of land just off Va. 28 in the Nokesville area, near Center Street and Farmview Road. The new infrastructure would add about 245,000 dekatherms per day of capacity. The Virginia Natural Gas Interconnect would add nearly 10 miles of new pipeline in Prince William and Fauquier counties as well as a natural gas compressor station off Va. 28 near Nokesville. The expansion is expected to raise rates for the nearly 300,000 customers in the Virginia Natural Gas service area, which includes the coastal plain and tidewater regions of Virginia.
LG&E Gas Pipeline's Path Would Remove Forest, Impact Endangered Species - Louisville Gas and Electric has disclosed new details about the environmental impacts of a proposed natural gas pipeline through conservation lands in Bullitt County. The nearly 12-mile-long gas pipeline would remove nearly 40 acres of forest, cross at least six major waterways and impact wetlands, sinkholes and habitat for more than a half-dozen threatened or endangered species, according to an LG&E stormwater pollution prevention plan. A consultant hired by LG&E outlined the environmental impacts in an October report sent to the Kentucky Division of Water for a water quality certification. The Division of Water has twice certified the project, but due to a recent change in federal rules LG&E has had to re-submit over technical details. LG&E expects the state will certify the plan a third time, spokeswoman Natasha Collins said. The latest application expands on minor changes and outlines the potential environmental damages and mitigation efforts for the proposed pipeline. The proposed path has sparked protest, yard signs and other advocacy campaigns, in addition to myriad legal challenges over permits, applications and condemnation. Bernheim is currently asking the public to write and email comments on the water quality certification. Bernheim Conservation Director Andrew Berry said the construction and operation of a gas pipeline on conservation lands would harm soil and water conditions and impact habitat for sensitive species. Bernheim alone would permanently lose about eight acres of forest including roosts for federally endangered Indiana and northern long-eared bats, he said.
In Weymouth, a brute lesson in power politics - The Boston Globe - A Globe investigation finds residents who fought a six-year battle with an energy giant over a controversial gas compressor never had much of a chance, with both the federal and state governments consistently ruling against them
Lawmakers Push For Gas Pipeline Safety In Climate Bill - With a compromise climate policy bill still under negotiation and time winding down in the legislative session, gas workers and nearly 50 lawmakers have been pushing to get new pipeline safety provisions enshrined into law."With limited time left in this unusual legislative session, the climate change bill in conference offers the best opportunity for us to accomplish significant improvements on a pressing public safety issue," the bipartisan group of 46 lawmakers wrote in a letter sent in October. Recent lobbying efforts have focused on the same topics.Specifically, the letter asks that the climate change conference report include a mechanism for the Department of Public Utilities to have more oversight of contractors performing work on or around gas lines, an extension of whistleblower protections for public utility workers, increased fines for violations of DPU's safety and emergency preparedness regulations, and more.The lawmakers said the provisions they hope will be included in a compromise climate bill include "elements of comprehensive gas safety legislation which were reported out of the Joint Committee on Telecommunications, Utilities and Energy with a favorable recommendation."Gas safety measures have been given a fresh look amid attempts to shore up the safety of natural gas infrastructure after the gas explosions and fires that killed one man, razed several homes and destroyed property across Lawrence, Andover and North Andover in September 2018.
Connecticut power plant proposal at odds with climate goals, critics say --Opponents of the planned Killingly Energy Center want Gov. Ned Lamont to intervene to block the 650-megawatt project. As Connecticut Gov. Ned Lamont’s climate council finalizes recommendations for how the state can meet its greenhouse gas reduction goals, state agencies are simultaneously overseeing final approvals for a new natural gas-fired power plant. Opponents of the project say the two processes are working at cross-purposes, and it’s time the Lamont administration resolved the conflict. Environmental activists joined with a few state lawmakers Tuesday to repeat their demands that the administration find a way to stop the 650-megawatt facility, called the Killingly Energy Center. “This power plant not only doesn’t meet the energy needs of Connecticut — there’s actually no evidence that this energy is necessary to meet any sort of demand through ISO New England,” the regional electricity grid, said state Sen. Mae Flexer, whose district includes the town of Killingly. “And it clearly does not fall in line with our targets in Connecticut for moving toward green energy.” The long-embattled project, being developed by Florida-based NTE Energy, was approved by the Connecticut Siting Council in June 2019, after the developer had secured a future power generation commitment from ISO New England. The siting council pointed to that seven-year capacity supply obligation as proof that the power plant is needed. But environmentalists have questioned the region’s need for another gas-burning plant, especially at a time when states are making strides on ramping up renewables and efficiency efforts. A draft subcommittee report under review by the Governor’s Council on Climate Change acknowledges as much, saying that the Killingly plant “does not align with Connecticut’s decarbonization policy objectives; and its long asset life will make it challenging to meet the state’s emissions reduction goals.” A final report from the council is due in January. ISO New England has come under criticism for not sufficiently taking into account individual states’ renewable energy goals in its grid management. In October, Lamont joined four other New England governors in calling for reform of the grid operator’s regional electricity market design, transmission planning and governance. At the time, Lamont, who has set a target of 100% clean energy by 2040, said the ISO-NE system had “actively hindered our efforts to decarbonize the grid.” All the while, the Killingly plant has continued to move through the approval process. Activists say it is incumbent upon the governor to stop it.
New Jersey LNG Export Terminal Wins Key Regulatory Approval - A small-scale liquefied natural gas (LNG) export terminal proposed for New Jersey has cleared another regulatory hurdle after the Delaware River Basin Commission (DRBC) this week voted to uphold a decision approving a key part of the project. DRBC, a quasi-regulatory agency involving four states and the U.S. government that oversees the Delaware River watershed, voted 4-0 to uphold its approval last year to build a second dock to load LNG tankers at the proposed Gibbstown Logistics Center. The facility is being developed by an affiliate of New Fortress Energy LLC. Delaware, New Jersey, Pennsylvania and the U.S. Army Corps of Engineers, which represents the federal government, voted to uphold the decision. A representative from New York abstained after the state’s effort to delay the vote failed. The DRBC said there was sufficient information to conclude that the second dock wouldn’t significantly conflict with policies to best develop and use the basin’s water resources. DRBC’s initial authorization covered only plans to export liquefied petroleum gas (LPG) from one dock. Environmental groups have opposed the project, arguing that it wasn’t made clear that the expansion approved last year would include a second dock for LNG exports.“This is the worst decision the commission has ever made,” said New Jersey Sierra Club director Jeff Tittel. “Their decision is outrageous and dangerous.” Environmental groups vowed to appeal the decision in federal court.
Seven LNG Export Licenses Extended by DOE - The U.S. Department of Energy (DOE) has extended another seven long-term liquefied natural gas (LNG) export licenses through 2050, following a policy change implemented by the Trump administration earlier this year. The authorizations extend export terms for the Golden Pass facility under construction in Sabine Pass, TX, as well as the Texas LNG project proposed for Brownsville, TX, and the proposed Magnolia and Driftwood LNG terminals in Louisiana. Export licensenses were also extended through Dec. 31, 2050 for the Delfin floating LNG project offshore Louisiana and the EnergÃa Costa Azul facility that was sanctioned for the west coast of Mexico last month. ECA has DOE authorization to import and liquefy U.S.-sourced natural gas for export from Mexico. In an effort to strengthen and promote domestic natural gas exports, the Trump administration in July extended export authorizations to non-free trade agreement (FTA) countries through 2050. The latest announcement follows 10 similar export license extensions that the DOE completed in October. The moves come as U.S. LNG exports are booming. Feed gas deliveries to terminals have hit record highs over the last week, exceeding 11 Bcf/d as the nation’s liquefaction trains run at or near peak capacity. Global natural gas prices are at some of their highest levels in the last two years as cargo loadings catch up to winter demand, supply disruptions add to seasonality and shipping constraints pressure the market.
Cameron LNG Ramping Up Operations After Brief Outage - A utility plant trip that knocked out Cameron LNG’s three liquefaction trains earlier this week has been fixed, a spokesperson said. It’s unclear what caused the incident, but Cameron said Tuesday the outage occurred overnight. “The issue is now resolved, and the operations team is in the process of restarting the trains,” said spokesperson Anya McInnis on Wednesday. Feed gas volumes to U.S. export terminals, which have been at record levels above 11 Bcf/d most of the month, dipped after the incident. Flows dropped from 11.37 Bcf on Monday to 9.53 Bcf on Tuesday, according to NGI’s U.S. LNG Export Tracker. Feed gas deliveries bounced back to 11 Bcf on Wednesday as the global gas market remains strong for exports. Cameron’s three trains can produce 12 million metric tons of LNG per year, or 1.7 Bcf/d. The facility, located in Hackberry, LA, was offline for a monthbetween August and September after Hurricane Laura made landfall. Operations again were disrupted in October when two vessels and an oil rig sank in the Calcasieu Ship Channel, which prevented LNG carriers from reaching the facility.
U.S. LNG Exports Sail to Record Levels in November, Says EIA - After sinking to their lowest levels in more than two years over the summer, U.S. liquefied natural gas exports surged to a record high in November, according to the Energy Information Administration (EIA). The agency said U.S. LNG exports reached 9.4 Bcf/d last month, surpassing the previous record set in January on strong global demand and lower supply. That represents 93% of peak LNG export capacity utilization.A cold start to the winter in Asia has combined with fewer restrictions amid Covid-19 to drive up gas demand, sending spot prices to two-year highs. Chilly conditions in Europe, meanwhile, have resulted in a quick drawdown in storage inventories and an increased appetite for the super-chilled fuel.That’s a far different scenario than the summer, when an estimated 165-200 U.S. LNG cargoes were canceled because of depressed demand from the pandemic and other factors.Global LNG supply also has fallen because of unplanned outages at LNG export facilities in Australia, Malaysia, Qatar, Norway, Nigeria, and Trinidad and Tobago, according to EIA. However, 2.7 Bcf/d of new U.S. LNG export capacity was added in 2020, the agency said, and several U.S. LNG terminals affected by hurricanes and annual maintenance have resumed LNG shipments.Cheniere Energy Inc. is in the process of commissioning the third production unit at the Corpus Christi facility, and the ramp in production also helped elevate feed gas deliveries even further. NGI data showed flows to U.S. LNG export terminals crossing the 11 Bcf/d mark earlier this month, a level that has held fairly steady since.Notably, the robust demand overseas has prompted some analysts to alter their view on U.S. exports for 2021. BofA Global Research analysts said this week they expect Asian spot prices to remain strong enough next summer to prevent significant U.S. LNG cargo cancellations. NGI data shows the projected arbitrages from the Gulf Coast to Asia or Europe are both at least $1.00/MMBtu for all of 2021, with significantly higher arbitrage opportunities in the winter and fall.
China Buying More U.S. LNG to Meet Winter Demand, but Still Far Below Phase One Targets - U.S. liquefied natural gas (LNG) exports to China have ramped up this year but remain far below the levels specified in a phase one trade deal signed in January by the two countries to try to improve trade relations. Since U.S. LNG exports to China resumed in March after a hiatus of more than one year, the East Asian country has imported, or is scheduled to import, a combined 49 U.S. cargoes with a total volume of 7.92 million cubic meters, equivalent to about 168 Bcf of natural gas, according to data intelligence firm Kpler. Additionally, 18 LNG vessels with U.S. cargoes have not declared their destinations, so some of those could go to China. That compares with two U.S. LNG deliveries to China in 2019 with a combined volume equivalent to 6.9 Bcf and 26 exports in 2018 equivalent to about 90.5 Bcf, according to the U.S. Department of Energy. U.S. exports to China have accelerated in recent months, totaling at least 24 deliveries since October, Kpler said. “When looking at Chinese LNG imports, there is a strong seasonality traditionally resulting in higher deliveries during [the] November-January period, and it is confirmed by what we are seeing this year as well,” Kpler senior market analyst Ilya Niklyaev told NGI. He mostly attributed the significant ramp-up of U.S. exports since October to China buying supplies for winter demand and “very high exports from the U.S. in general.” Since Dec. 4, combined gas flow to the six U.S. LNG plants has topped 11 Bcf/d. Kpler expects “a big increase” in U.S. LNG deliveries to China in December, Niklyaev said, noting that there are multiple vessels headed to the Far East with U.S. supplies that could ultimately end up in China. He pointed out that the U.S. still accounts for a small portion of China’s overall LNG imports, with producers in Qatar and Australia benefitting the most from Chinese winter buying. Despite the increased U.S. LNG deliveries to China, the phase one targets “are wildly out of reach for 2020 and never really had much chance of being achieved, at least on the energy side, because of the huge dollar amounts involved,” Poten & Partners’ Jason Feer, global head of business intelligence, told NGI. China in the phase one deal committed to buy $200 billion of American goods over the next two years, including $52.4 billion of energy products including LNG, crude oil, refined products and coal. Reuters recently calculated that in the first 10 months of 2020, China’s purchases of U.S. crude oil, LNG, propane, butane and other energy products totaled $6.61 billion, or about 26% of this year’s $25.3 billion target. The Covid-19 pandemic has significantly reduced energy demand throughout the world and many analysts are optimistic that vaccinations will improve demand next year.
Significant U.S. LNG Cargo Cancellations Not Likely in 2021, BofA Analysts Say - - Asian liquefied natural gas (LNG) spot prices are at two-year highs and are projected to remain strong enough next summer to prevent significant cancellations of U.S. LNG cargoes in 2021, BofA Global Research analysts said. Projected U.S. LNG export arbitrages for next summer are now positive, in the range of $0.75-$1.00/MMBtu, the analysts said in a Dec. 11 note.“Thus, we assume near max utilization rates of U.S. LNG export facilities next year and see Asian demand supporting Henry Hub prices above $3/MMBtu in the summer,” they said.Combined gas intake at the six U.S. LNG export terminals has recently averaged more than 11 Bcf/d, according to NGI data.An estimated 165-200 U.S. LNG cargoes were cancelled earlier this year as depressed demand from the Covid-19 pandemic and other factors drove Asian and European benchmarks down to parity with Henry Hub prices for much of the summer, in the range of about $1.50-2.00/MMBtu. Even though the long-term, take-or-pay liquefaction fees of $2.25-3.50/MMBtu that U.S. LNG customers pay are sunk costs, customers would still cancel U.S. cargoes if the arbitrage between the U.S. and other markets would be less than their respective spot shipping and other variable costs.According to NGI data, the projected arbitrages from the Gulf Coast to Asia or Europe are both at least $1/MMBtu for all of 2021, with significantly higher arbitrage opportunities in the winter and fall. Spot LNG prices for delivery to northeast Asia in January were $8.075/MMBtu on Dec. 11, according to NGI data. The BofA analysts said they expect the February Japan Korea Marker (JKM) contract, which is currently trading at about $9.20/MMBtu, to drop to about $7/MMBtu as more supply becomes available. Prices have increased significantly as liquefaction outages and maintenance worldwide have driven LNG supply shortages heading into the winter heating season, especially in the Pacific Basin. Gulf Coast export arbitrages to Asia have widened recently to more than $3/MMBtu on JKM strength and Henry Hub weakness, “encouraging all possible US swing volumes to set sail for the Pacific,” the BofA analysts said. The surge in Asia-bound U.S. cargoes has delayed waiting periods to cross the Panama Canal to as long as 10-15 days, from previous waits of four or five days, they said.
Next U.S. LNG Exporter Says Project Ahead of Schedule - Construction on the next major liquefied natural gas export terminal in the U.S. is ahead of schedule and cargoes for a second project will be fully contracted by the middle of 2021, according to the developer’s top executive. Venture Global LNG Inc. plans to have six of 18 production units at the Calcasieu Pass plant in Louisiana installed by mid-February, Chief Executive Officer Mike Sabel said in an interview with Bloomberg TV. Commercial operations are expected in 2022. The first phase of Plaquemines LNG, the company’s second project in the state, will be fully contracted by the end of June, Sabel said. Venture Global’s momentum comes during what has been a difficult year for most U.S. LNG developers. The coronavirus pandemic sapped demand for the heating and power-plant fuel, hindering investment and adding to a global glut. Growing concern about climate change, meanwhile, has led to heightened scrutiny of gas projects. Tellurian Inc., which is also seeking to build a terminal in Louisiana, failed to finalize a deal with a key backer. France’s Engie SA, under pressure from an environmental group, decided against buying LNG from a Texas project planned by NextDecade Corp. Venture Global’s modular approach to construction has allowed Calcasieu Pass to proceed ahead of schedule despite the pandemic and a hyperactive hurricane season, Sabel said. The plant’s production units, called trains, are made at a Baker Hughes facility in Italy and shipped to Louisiana for installation./p>
U.S. LNG Developers Eye More FIDs in 2021 as Pandemic Recedes, Demand Rises --U.S. liquefied natural gas (LNG) developers are anticipating that 2021 will be much different than 2020. Covid-19 and uncertain long-term economics dashed the plans for a number of U.S. gas export projects to make a positive final investment decision (FID) this year. Most of those projects pushed their planned FID dates into 2021, with the expectation of coming online by the middle of the decade to meet what is expected to be global supply shortage. With vaccinations beginning, global gas demand is expected to rise, but the long-term profitability of U.S. LNG is still an open question. Arbitrage opportunities to Asia and Europe have decreased since the first wave of domestic projects was funded in the previous decade.The International Energy Agency said in October global gas demand would likely fall 3% in 2020 to 3.88 trillion cubic meters, or 375 Bcf/d. And the International Gas Union in August said LNG consumption in 2019 totaled a gas equivalent of 482 billion cubic meters, or 46.6 Bcf/d. It added that LNG use could fall about 4% this year but then rebound quickly in 2021, depending on the persistence of the pandemic.Meanwhile, Wood Mackenzie predicted in September that global LNG demand would continue to grow to 2030 by 4%/year, creating a potential supply shortfall of 100 million metric tons/year (mmty), equivalent to about 12.8 Bcf/d of gas, by the end of the decade. Qatar would likely account for a large portion of the new supply with a planned expansion at its North Field East facility, the analysts said. The United States has six export facilities in operation, with recent combined gas intake of more than 11 Bcf/d. The projects now under construction –Golden Pass in Texas, the sixth Sabine Pass train in Louisiana and Venture Global Calcasieu Pass also in Louisiana – would add roughly 4 Bcf/d of capacity in the next few years. Combined that would put total U.S output at around 15 Bcf/d. The proposed U.S. liquefaction capacity far exceeds what could be built. Seventeen projects with a combined volume of 28.9 Bcf/d have already received construction approval from FERC, a process that costs into the hundreds of millions. Four other projects with a combined output of up to 5.5 Bcf/d are in the Federal Energy Regulatory Commission’s pre-filing stage to identify major environmental issues and stakeholders. In addition, two more projects with a combined volume of 3 Bcf/d have been proposed to FERC but have not yet applied, according to the Commission. Of the 17 projects approved by FERC, only eight with a combined volume of 17.3 Bcf/d have an FID is planned next year, far more than global demand may warrant. Expansions at existing facilities are said to be more likely to get funding than greenfield projects. Three expansions proposed for the Cameron terminalin Louisiana, the Corpus Christi project in South Texas, and at the Freeport facility on the upper Texas coast, would have combined volume of about 4 Bcf/d. Those projects have not publicly provided 2021 FID dates, but if they are sanctioned, it could leave less room to FID greenfield projects next year.Two North American projects could potentially be funded this year, the 2.4 mmty EnergÃa Costa Azul (ECA) facility in northwest Mexico and the 11 mmty stage 3 expansion at Corpus Christi. San Diego-based Sempra Energy last month sanctioned ECA, making it the only export project globally to reach FID this year.
Natural Gas Production Declines from Seven Major U.S. Regions to Continue into 2021, EIA Says - The downtrend in natural gas production from seven major U.S. producing regions that has persisted for much of 2020 will extend into 2021, according to updated projections from the Energy Information Administration (EIA). Gas production from the Anadarko, Appalachian and Permian basins, as well as from the Bakken, Eagle Ford, Haynesville and Niobrara formations, is set to decline 744 MMcf/d month/month (m/m) in January, to 80.777 Bcf/d, EIA said in its latest Drilling Productivity Report (DPR), published Monday. Among the major plays tracked in the DPR, only the Haynesville is expected to grow output from December to January, with production to rise 10 MMcf/d m/m to just over 11.3 Bcf/d. Conversely, output from the Appalachian Basin is expected to fall 154 MMcf/d to around 33.5 Bcf/d in January. The Anadarko (down 155 MMcf/d), the Bakken (down 66 MMcf/d), the Eagle Ford (107 MMcf/d), the Niobrara (down 115 MMcf/d) and the Permian (down 157 MMcf/d) are also set to see output fall in January, EIA said. EIA last modeled a m/m increase in natural gas output from the seven U.S. shale regions in early 2020. Since then, the DPR data has shown a continuous decline in output, coinciding with a sharp pullback in the U.S. rig count amid the economic fallout of the Covid-19 pandemic. Meanwhile, oil production from the seven regions is set to fall 137,000 b/d m/m in January, to 7.438 million b/d, according to the latest DPR. The Permian Basin is expected to show the largest drop-off from December to January, falling 44,000 b/d to 4.196 million b/d. Declines are also expected from the Anadarko (down 20,000 b/d), Appalachia (down 1,000 b/d), the Bakken (down 23,000 b/d) and the Niobrara (down 23,000 b/d). Looking at new-well productivity per rig, EIA expects average per-rig natural gas output to slide 568 Mcf/d to 6,710 Mcf/d in January. The Eagle Ford is expected to see the largest drop-off in per-rig productivity, falling by 517 Mcf/d m/m. In the gassy Appalachia and Haynesville regions, per-rig production is set to rise m/m by 27 Mcf/d and 2 Mcf/d, respectively, the DPR data show. New-well oil productivity per rig is set to fall 11 b/d to 1,025 b/d from December to January, according to EIA. The Eagle Ford is on track to see the largest m/m decline, with per-rig output expected to fall 163 b/d m/m. EIA data show the backlog of drilled but uncompleted wells (DUC) continued to shrink across each of the seven regions from October to November. The Niobrara drew down its DUC backlog by 41 m/m, to 456 in November, with the Eagle Ford posting the next largest drawdown, down 32 to 1,031 DUCs in November.
North American Natural Gas Marketers Hold the Line in 3Q2020, NGI Survey Shows - Leading natural gas marketers posted flat sales volumes in 3Q2020, snapping a streak of five consecutive quarters of year/year declines, according toNGI’s Top North American Natural Gas Marketer rankings. The 25 gas marketers participating in the latest quarterly survey reported combined sales transactions of 117.42 Bcf/d in 3Q2020.The 24 gas marketers covered in the survey for which year-earlier data were available collectively reported 114.56 Bcf/d for the latest quarter, level with the precise total reached in 3Q2019. Several of the largest gas marketers reported modest declines for the quarter as flat consumption was more than offset by lower production amid the continued impact of the coronavirus pandemic. Energy Information Administration (EIA) data show that 3Q2020 U.S. dry gas production averaged 89.7 Bcf/d, down 4.6% from 94.0 Bcf/d a year earlier.Longstanding No.1 BP plc reported volumes of 17.53 Bcf/d in 3Q2020, a 4% decrease from 3Q2019, while No. 2 Macquarie Energy reported 10.89 Bcf/d, a 3% decline. In at No. 3 (in a tie with Shell Energy NA), Tenaska reported 10.40 Bcf/d in 3Q2019, a 6% decline. Notably, “our annual FERC Form 552 data analysis shows the combined market share of the top U.S. 20 marketers has been trending down over the last decade, and that has been providing something of a volume headwind as well,” said NGI’s Patrick Rau, director of Strategy & Research. “So you have a long-term trend being accelerated by a shorter-term production decline” among the largest players.
LNG Recap: Natural Gas Price Rally Continues Amid Tight Market - Natural Gas Intelligence - Global natural gas prices again moved higher last week as forecasts trended colder, and supply disruptions and a tight shipping market continued. Spot prices in North Asia moved above $11.00/MMBtu last week, hitting a new two-year high. One bid for a January cargo was reportedly placed for more than $12.00 as the week got underway. Meanwhile, European natural gas prices moved upward for the third week in a row and front month Henry Hubfinished higher on Friday after a volatile week as forecasts show chillier weather on the way in the United States. European and U.S. benchmarks also posted gains on Monday. Congestion in the Panama Canal, ongoing supply outages and colder weather forecast for China, Japan and South Korea are all supporting the Japan Korea Marker (JKM). The JKM prompt contract started last week at $7.600 and finished Friday at $8.075. Strength in Asia is pulling LNG from the Atlantic market into the Pacific and helping to support prices in Europe. Tudor, Pickering, Holt & Co. said European storage drew by 146 Bcf last week, well above norms of 108 Bcf for this time of year. . The price of carbon credits in Europe also hit a record 31.30 euros/ton on Friday. The European Union agreed on Friday to cut net greenhouse gas (GHG) emissions by at least 55% by 2030 from 1990 levels, replacing a previous goal to cut emissions by 40% this decade. While the European Parliament still needs to approve the new target, carbon prices were still moving upward on Monday. Oil prices also moved higher on Monday, closing at $50.29/bbl. Brent moved higher after an oil tanker exploded in a reported attack by a boat filled with explosives in the Saudi Arabian port of Jeddah.In other news last week, Gunvor, the largest independent LNG trader in the world, announced a joint venture (JV) with United States-based Energy Capital Vietnam (ECV), which is leading the development of an LNG-to-power project in southeast Vietnam. The JV will be responsible for trading and shipping on behalf of ECV. Gunvor will also supply LNG to the JV on a long-term basis. While several projects are under development in the country, Vietnam does not yet import LNG. Elsewhere, Siemens Energy has partnered with Russia’s largest independent natural gas producer, Novatek, to develop solutions to cut Novatek’s GHG emissions by using hydrogen and increasing energy efficiency in LNG production.
Gains Mount for Natural Gas Futures as Frosty Temps Creep into Forecasts; Snow Storms Lift Cash - Natural gas futures extended their gains for a fourth consecutive session as weather models continue to tease more cold for the end of the month and into January. The January Nymex contract settled Monday at $2.682, up 9.1 cents from Friday’s close. February climbed 7.5 cents to $2.678. Spot gas prices also rallied at the start of the week as back-to-back weather systems drove up demand in key regions. Driven by multi-dollar gains on the East Coast, NGI’s Spot Gas National Avg. jumped 47.0 cents to $3.035. After earlier forecasts had all but written off cold weather for December, the recent shifts in the weather data provided a boost to futures. Though models are not in full agreement in the amount of cold seen moving through the country, there at least is some variability in play. Bespoke Weather Services said the American ensemble data attempts to develop a negative Eastern Pacific Oscillation on the Pacific side, which would signify colder risks heading into the turn of the new year. The European guidance is not reflecting this pattern, but still indicates the outlook is not entirely warm. NatGasWeather said a chilly pattern held for this week but a mild break was seen over most of the United States during the Dec. 20-23 period. The GFS does show stronger cold shots into the northern and eastern states Dec. 25-26, according to the forecaster, but it has been inconsistent on exactly how that might play out and overall still isn’t exactly frigid with them.It should be noted that even if the cold blasts do show up, the timing could impact how much demand increases given the expected arrival is right at Christmas. Thanksgiving proved to be a demand crusher, with only 1 Bcf of gas withdrawn from storage during the mild holiday week.
Natural Gas Futures Stall; Northeast Cash Strong Ahead of 'Near-Blizzard' Conditions - Natural gas futures shifted into neutral Tuesday amid some inconsistencies in the weather data and a dip in liquefied natural gas (LNG) demand. After four straight sessions in the green, the January Nymex gas futures contract settled flat on the day at $2.682. February also was nearly unchanged at $2.680. Spot gas prices were mixed across most of the United States, but big gains continued on the East Coast ahead of a second winter storm set to unleash frigid air on the region. NGI’s Spot Gas National Avg. climbed 21.0 cents to $3.245.Though recent weather model runs have been far from bullish, the projected variability in the outlook for the balance of December had supported the gas market. The January Nymex contract tested $2.381 three times over the past week but hit an intraday high of $2.708 on Monday. The prompt month traded near that level again on Tuesday, but ultimately finished the day in the red as weather model data continued to flip flop.NatGasWeather said the American and European models both shed demand from the 15-day outlook, but the European data continued to run significantly colder than the American Global Forecast System. Specifically, the model continued to show a cold enough pattern this week and in the Tuesday afternoon run, gained back more than half of the demand that was lost for the Dec. 25-27 period.The European model still showed a milder break around Dec. 28-29, “but we view that as potentially a brief one as cold reloads over Canada before making a return push into the U.S. around Dec. 30-31,” NatGasWeather said, noting that more data is needed to be confident in that theory. Meanwhile, Mobius Risk Group pointed out that from Monday through Thursday, the U.S. population-weighted heating degree days (HDD) count was predicted to be three more than the 30-year normal, while the comparable period last week (Dec. 7-10) was 14 HDDs warmer than normal. “With the most bullish days of the week still to come, and an Eastern seaboard snowstorm to boot, further upside could be forthcoming.”
Natural Gas Futures Prices Still Steady Ahead of Potentially Larger-than-Normal EIA Storage Report - After an earlier dip, natural gas futures recovered to ultimately close out Wednesday’s session nearly flat as the prospects for more cold in early January appeared to dim. With a sharp increase in liquefied natural gas (LNG) demand and the potential for a much larger-than-normal storage withdrawal, the January Nymex contract settled at $2.677, down a half-cent from Tuesday’s close. February climbed one-tenth of a cent to $2.681. Spot gas prices were mixed, but the Northeast mounted more gains as snow fell on the region. NGI’s Spot Gas National Avg. climbed 14.0 cents to $3.385. The blockbuster winter storm pummeling the East Coast notwithstanding, any momentum in the futures market was sapped early Wednesday as the latest weather data decreased the risk in achieving a colder pattern into the turn of the new year. This change was most apparent in the European ensemble, according to Bespoke Weather Services. “While the late-month situation remains a lower confidence one, a failure of cold to materialize would imply that the La Niña state is able to resist any notable shift eastward in tropical forcing,” the forecaster said. This could keep the overall warm state rolling into January, absent a strong North Atlantic Oscillation block. “This is what all of the long-term climate modeling suggests will occur, and is our lean as well, as even if we are to get colder in early January, we are not convinced of its durability,” Bespoke said. The midday Global Forecast System (GFS) model gained some demand for the Dec. 24-27 period, but remained mild in the days before and after that period, according to NatGasWeather. The forecaster pointed out, though, that the GFS was colder for Dec. 25-27, which moved it closer in alignment with the European model. The European model, however, is still more than 20 heating degree days colder compared to the GFS.
US working natural gas volumes in underground storage declines 122 Bcf: EIA — US working natural gas in storage posted its first triple-digit build of the heating season last week as South Central accounted for the largest regional draw on cooler weather and record-high LNG feedgas demand. Stay up to date with the latest commodity content. Sign up for our free daily Commodities Bulletin. Sign Up Storage inventories decreased by 122 Bcf to 3.726 Tcf for the week ended Dec. 11, the US Energy Information Administration reported Dec. 17. The withdrawal was weaker than an S&P Global Platts survey of analysts calling for a 127 Bcf pull. Responses to the survey ranged from a 103 to 145 Bcf withdrawal. However, the pull was stronger than the 97 Bcf draw reported during the same week last year as well as the five-year average withdrawal of 105 Bcf, according to EIA data. The draw was also stronger than the 91 Bcf withdrawal reported the week prior. Residential and commercial demand grew by 3.5 Bcf/d week on week and power demand gained 1.6 Bcf/d, according to S&P Global Platts Analytics. Incremental power demand was also spurred by falling wind generation, which declined by nearly 15 GWs, the equivalent of 2.5 Bcf/d in gas-fired generation. Total supply was up a marginal 100 MMcf/d week on week as lower US production was offset by a 700 MMcf/d increase in net Canadian imports. Storage volumes now stand 284 Bcf, or 8.3%, more than the year-ago level of 3.442 Tcf and 243 Bcf, or 7%, more than the five-year average of 3.483 Tcf. The NYMEX Henry Hub January contract slipped 3 cents to $2.64/MMBtu in trading following the release of the weekly storage report at 10:30 am ET. The remaining winter strip, February and March, also dipped 3 cents to average $2.63/MMBtu, a decline of 5 cents from the week prior. Entering the Dec. 17 EIA report, the prompt-month January NYMEX contract has been in a well-defined range this week – oscillating between $2.60 and $2.70/MMBtu. The relatively narrow range appears to be linked to weather model uncertainty entering January with some models pointing to a colder regime, while others predict a milder background state, according to S&P Global Platts Analytics. So far this withdrawal season, inventory has declined by a net total of 229 Bcf. Over the past five years, stocks have decreased by an average of 497 Bcf by this time of the heating season. Platts Analytics supply and demand model currently forecasts a 166 Bcf withdrawal for the week ending Dec. 18, which would shrink the surplus versus the five-year average by an additional 39 Bcf as cooler temperatures spike US-level demand week over week.
Natural Gas Futures Slip After EIA Data Fails to Sway Traders; Northeast Cash Mixed as Snowstorm Exits - Natural Gas Intelligence --Even with the East Coast buried under several feet of snow, and the potential for more frigid air to arrive by Christmas, natural gas futures fell short Thursday. The January Nymex gas futures contract settled 4.1 cents lower day/day at $2.636/MMBtu after the latest government storage report came in bullish, “just not record bullish.” Spot gas prices also retreated across most of the United States, but the Northeast notched the fourth straight day of gains as the Nor’easter that slammed the region beginning midweek was set to linger through the end of the week. NGI’s Spot Gas National Avg. climbed 17.5 cents to $3.560.After two eerily quiet Nymex trading sessions, the market appeared to be on pins and needles early Thursday. Traders appeared to have lost all confidence in the weather data, given the back-and-forth swings with each model run. Instead, market players were relying on the latest storage inventory report to finally move prices decisively one way or another.The Energy Information Administration (EIA) reported a 122 Bcf withdrawal from storage inventories for the week ending Dec. 11, which was generally in line with market expectations ahead of the report. However, some estimates pegged the draw to be much larger, with major surveys producing estimates as large as a 138 Bcf draw. The EIA figure compares with the 97 Bcf decrease recorded in the year-ago period and a five-year average pull of 105 Bcf.Bespoke Weather Services, which had expected a 115 Bcf withdrawal, said since the actual figure was right in the middle of the range of expectations, it was taking a neutral stance on prices. That said, the EIA stat is “very much reflective of a tight supply/demand balance.“We expect a much larger draw next week, although thanks to having more weather demand, the balance data does not appear quite as tight for this current week,” Bespoke said.Broken down by region, the EIA said South Central inventories dropped 38 Bcf during the reference week, including a 25 Bcf pull from nonsalt facilities and a 13 Bcf pull from salts. The Midwest withdrew 36 Bcf, while the East drew 34 Bcf. Inventories in the Mountain and Pacific region each fell by less than 10 Bcf.Total working gas in storage as of Dec. 11 stood at 3,726 Bcf, 284 Bcf higher than year-ago levels and 243 Bcf above the five-year average, according to EIA. Bespoke was surprised to see the market sell off following the EIA report, although weather changes are expected to continue holding the most weight moving forward. The American and European models favor more cold air penetrating the Lower 48 around Christmas, but Bespoke said any significant drop in temperatures that may arrive is likely to be temporary.
US natgas hits 2-week high on colder late December forecasts - - US natural gas futures rose to a two-week high on Friday on forecasts for near record liquefied natural gas exports, colder weather and more heating demand in late December. That price increase comes as spot power and gas prices in the US Northeast rose to their highest in a year as a major winter storm blanketed the region in snow this week. Front-month gas futures rose 6.4 cents, or 2.4%, to settle at $2.700 per million British thermal units, their highest close since Dec. 2. That put the contract up over 4% for the week after it gained less than 1% last week. Data provider Refinitiv said output in the Lower 48 US states averaged 90.8 billion cubic feet per day (bcfd) so far in December. That compares with a seven-month high of 91.0 bcfd in November 2020 and an all-time monthly high of 95.4 bcfd in November 2019. Refinitiv projected average demand, including exports, would slip from 124.3 bcfd this week to 123.6 bcfd next week as the weather turns milder before rising to 127.8 bcfd in two weeks with the expected arrival of more cold. The amount of gas flowing to US LNG export plants, meanwhile, has averaged 10.7 bcfd so far in December, which would top November's 9.8-bcfd record. That increase comes as the third train at Cheniere Energy Inc's Corpus Christi LNG plant in Texas prepares to enter commercial service and as rising prices in Europe and Asia prompt buyers to purchase more US gas. Traders, however, noted LNG exports cannot rise much more until new units enter service in the second half of 2022 since feedgas to the LNG plants was already over their 10.5-bcfd export capacity. LNG plants can pull in a little more gas than they can export since they use some of the fuel to run the facility.
What made Columbia, Lexington homes rattle Friday night? It was 2 different events.— Depending on where you live in the Columbia and Lexington areas, a boom heard and felt Friday night could have had separate sources in what officials say is a near-simultaneous coincidence. Two potentially jarring events happened within about an hour of each other: an earthquake in Columbia and a natural gas line release near Saluda Dam near Irmo. The U.S. Geological Survey confirmed a 2.4 magnitude earthquake in Columbia at 8:37 p.m. The quake was centered just north of Benedict College in the old Allen-Benedict Court public housing community. A safety valve released at a natural gas regulatory station near Saluda Dam close to the same time. The mechanism is triggered when pressure builds in a gas line due to trash or similar blockage and the sound of the valve venting can be a boom or a champagne cork popping, said Tom Allen, safety director for the S.C. Office of Regulatory Staff, which oversees utilities in the state. Depending on the size of the gas line and amount of pressure, the sound can seem as loud as a jet engine. Allen said the first calls he received related to the gas valve were about an hour after the earthquake. “It served its purpose; that escape valve vented the natural gas as it was designed to do,” Allen said. “I would say it was probably more of a mundane issue than it was the earthquake.” The valve is designed to open based on pressure and shouldn’t be affected by physical jostling as from earthquake tremors — cars have crashed into the regulatory stations without triggering the valve, Allen said. Lexington, Irmo and St. Andrews residents might have heard the gas incident and other areas of Columbia were probably experiencing the earthquake, Allen said.
These Ladies Love Natural Gas! Too Bad They Aren’t Real. – The website Women for Natural Gas is a pink-tinged, fancy-cursive-drenched love letter to the oil and gas industry. A prominently featured promo video shows women in hard hats and on rig sites. “Who’s powering the world? We are!” enthuses the narrator. Viewers can click through to a “Herstory” timeline of women working in the oil sector. Another page, about the group’s grassroots network of supporters, announces, “We are women for natural gas,” and shows three professionally dressed ladies alongside their testimonials. There’s a Carey White gushing, “The abundance of oil and gas in Texas helps keep prices at the pump lower.” One Rebecca Washington raves, “Natural gas is a safe, reliable source of energy that provides countless numbers of jobs.” But there’s a catch: The women don’t exist. A few months ago, I received a tip to look into the website’s testimonials—my tipster suggested that the group was using stock photos to represent the women who had supposedly contributed testimonials about natural gas. A reverse image search revealed that two of the images were indeed stock photos. The third, supposedly of a woman named Carey White, was the professional headshot of Jessi Hempel, a senior editor at-large at LinkedIn. The photo had been published in a brochure when she appeared at a 2020 Tupelo, Mississippi conference for landscape architects. When I contacted Hempel, she said she had never contributed any photo or testimonial to Women for Natural Gas. She said she found it “incredibly disturbing” that the group was using her image without her permission. “Thank you so much for discovering my image on a website I guarantee you I never would have clicked on,” she told me. Texans for Natural Gas, an oil and gas industry group that created Women for Natural Gas, never responded to Hempel’s or Mother Jones’inquiries about the photo. The group did eventually swap out Hempel’s image, but only after being contacted twice by a lawyer for Hempel’s employer, LinkedIn. A closer examination of Women for Natural Gas revealed that for the last year, the group has cycled through different headshots of women and quotes. My reporting suggests that it’s unlikely that the testimonials are genuine. Back in May, the site showed testimonials from Natalie White, Carey White and Natalie Smith, with identical quotes for the two Natalies (notwithstanding the overlapping names). By August, the names had diversified, a little, to Rebecca Washington, Natalie Smith, and Carey White, and the identical quotes had also changed again.
Dickinson supports Enbridge tunnel pipeline — Dickinson County adopted a resolution Monday in support of Enbridge’s Line 5 pipeline, urging completion of a tunnel replacement project with no disruption of service.The resolution comes in response to Gov. Gretchen Whitmer’s recent demand the company shut down its oil pipeline that crosses the bottom of the waterway connecting Lake Huron and Lake Michigan.“We can’t give up this fight,” said Commissioner Joe Stevens, saying a shutdown would severely restrict propane supplies in the Upper Peninsula, leading to price hikes.“I think we’ve been very proactive on this — our county,” Stevens said, predicting negative consequences statewide if the pipeline closes.The board adopted the measure unanimously, although Commissioner Kevin Pirlot said he’d like assurances a new tunnel can be completed in several years. “I support the concept of the tunnel, but it can’t take forever,” he said.Extensive inspections and safety tests have confirmed the integrity of Line 5, the county’s resolution states. It also notes Enbridge’s proposed $500 million investment in the replacement project and the crucial need to continue fuel shipments in the meantime.The 67-year-old pipeline has been targeted for shutdown by environmentalists who fear the implications of a spill in the Straits of Mackinac. A month ago, Whitmer accused Enbridge of failing to safeguard Great Lakes waters. A Michigan Department of Natural Resources report said Enbridge has failed to meet numerous safety standards.Enbridge, in turn, has filed a legal challenge to the Nov. 13 shutdown order, set to take effect in 180 days.Line 5 moves about 23 million gallons of oil and natural gas liquids daily between Superior, Wisconsin, and Sarnia, Ontario, traversing parts of northern Michigan and Wisconsin.The underwater section beneath the straits is divided into two pipes. Enbridge says they are in sound condition and have never leaked, while Whitmer contends they’re vulnerable to a catastrophic spill.
With Buttigieg as Transportation secretary, Michigan enviros envision a ‘federal ally’ in Line 5 fight ⋆ On Wednesday, President-elect Joe Biden made history in announcing former South Bend, Ind., Mayor and Democratic presidential candidate Pete Buttigieg as his choice to head up the U.S. Department of Transportation (DOT). If confirmed, not only would Buttigieg be the youngest secretary of the department and the first openly LGBTQ cabinet secretary — he would also likely be the department’s first leader to publicly oppose Michigan’s controversial and Enbridge-owned Line 5 pipeline. The DOT head matters for pipeline policy because the Pipeline and Hazardous Materials Safety Administration (PHMSA), which oversees the nation’s pipeline infrastructure, is housed within the department. PHMSA’s office is currently headed up by the controversial President Donald Trump-appointed Howard R. Elliott, whose replacement has not been announced. At the very top, Buttigieg would be replacing Elaine Chao, current U.S. Secretary of Transportation and spouse of Republican U.S. Senate Majority Leader Mitch McConnell (R-Ky.). Chao previously was secretary of labor under President George W. Bush. Trump nominated her for DOT at the beginning of his term. In February, before Michigan’s presidential primary, Buttigieg signaled his opposition to the pipeline with a tweet: “With such a high risk of an oil spill under the Great Lakes, Michigan can’t afford to keep the Line 5 pipeline in operation,” he wrote. “In every community, we need new clean energy solutions to meet our climate crisis.” That won praise from Attorney General Dana Nessel, a big Line 5 opponent, at the time. She declined to endorse anyone in the primary, which Biden won. Former Democratic presidential contenders Washington Gov. Jay Inslee and U.S. Sens. Bernie Sanders (I-Vt.) and Elizabeth Warren (D-Mass.) also spoke out against Line 5 during their campaigns.
With Line 5 closure, a ‘game of chicken’ over how to heat Upper Peninsula - If the Enbridge Line 5 pipeline shuts down next spring, Michigan has a matter of months to find a new way to deliver propane to Upper Peninsula residents who collectively use tens of millions of gallons from the pipeline annually to heat their homes. But one month after Gov. Gretchen Whitmer announced that she’s giving the Canadian oil giant until May to shutter the 67-year-old pipeline that runs beneath the Straits of Mackinac, her administration still won’t say exactly how Michigan will make up the difference. Spokespeople for Whitmer did not respond to numerous calls, texts and emails asking about potential contingency plans. Spokespeople for key state agencies told Bridge Michigan they’re studying alternative ways to meet U.P. propane needs, but none identified specific solutions that would be in place by next heating season. And while state officials and industry experts have said they expect the free market to adjust on its own, industry representatives said so far, they’ve made only tentative progress on the infrastructure investments necessary to wean the U.P. off Line 5. Experts who spoke to Bridge for this article said it’s possible to transition the Upper Peninsula to other propane sources using delivery methods such as truck or rail, but it will take money, time, and a clear strategy — with no guarantee it’s possible to achieve in a matter of months. “A lot of things have to go right,” said Eric Pardini, a director with Lansing-based Public Sector Consultants, who led a state-commissioned study outlining pathways to transitioning the Upper Peninsula’s propane sector. “The number of potential solutions gives me optimism, but it doesn’t give me peace.” In the absence of a detailed plan from the state, Upper Peninsula propane providers complain that they’re left to decide for themselves how they’ll serve their customers next year. Some are pursuing other sources of supply. Others are stalling as Enbridge and state attorneys wage a court battle that could determine whether the shutdown order sticks. That, Pardini said, sets up a “game of chicken” between the industry and the Whitmer administration over changes that must happen to ensure a Line 5 shutdown doesn’t strand tens of thousands of U.P. residents without a reliable propane supply come next heating season.
Activists build political power, vow to keep fighting Boxtown pipeline at Saturday rally - MLK50: Justice Through Journalism – A capacity crowd of about 60 attended a rally against a proposed oil pipeline through Boxtown in Southwest Memphis on Saturday, where a series of speakers vowed to fight the development.“For too many years Boxtown has been the dumping place for the rest of Memphis,” said Batsell Booker, president of the Boxtown Neighborhood Association, at the event held in the gazebo at T.O. Fuller State Park. Booker and several other speakers condemned the pipeline and its planned route through the mostly Black community that already is surrounded by industry.The event, which was live-streamed on Facebook, was held by Memphis Community Against the Pipeline. The group was recently organized by young activists, including Kathy Robinson and Justin J. Pearson, who both grew upin Southwest Memphis. Some people were turned away from entering the area by park rangers when capacity was reached. There were social distancing rules in place, with seating numbered, and volunteers did temperature checks and took down identification information from attendees. at the rally. The group live-streamed the event for those not able to attend due to COVID-19 social distancing recommendations. Photo by Andrea Morales for MLK50 The goal of the rally was to take the lead away from developers, who made presentations at previous community meetings; to label the Byhalia Connection Pipeline plan asenvironmental racism, and gather support from more residents and local officials to stop the project, Pearson and Robinson said. Black people are 75% more likely to live near a polluting facility, according to a 2017 report by the NAACP and the Clean Air Task Force.
Rep. Garret Graves has dim view of oil and gas industry under Biden administration - In a meeting Monday with local business people, U.S. Rep. Garret Graves addressed the future of oil and gas, the likelihood of a new federal stimulus package and acceptance of Joe Biden’s win in the presidential race. Graves spoke during an online meeting of the Bayou Industrial Group, which includes about 15 businesses in Terrebonne, Lafourche and surrounding areas. Graves, R-Baton Rouge, said Biden’s win disappoints him, adding that Donald Trump was doing a good job. But until evidence arises to show otherwise, “Biden is the president-elect at this point and we’re going to have to move forward under those conditions.” "At this point, the Trump campaign, investigators, FBI, no one has been able to produce evidence showing that the election outcome was different than projected,” said Graves, whose district includes northern Terrebonne and Lafourche. As for Biden’s emphasis on renewable energy, Graves said the oil and gas industry still supplies most of the national and world's energy needs and will do so for many years to come. “We can sit here and have these dreams about unicorns powering our fires and other things but, the fact, the science, is very different,” he said. “The technology is not there right now, and the reality is that the biggest secret to reducing emissions over the last 15 years … is natural gas.” Paul Danos, owner of the Danos oilfeld services company, based in Gray, spoke before Graves delivered his speech. He said 2020 has been tough on the company but it was able to start two new businesses. “Obviously the oil and gas industry is the main driver for our region, and as we go into a new administration, our industry is not necessarily the darling of the administration,” Danos said. “So we have a couple of options: We can stick our head in the sand and hope that it all passes or we can wake up and ... do something about it.” Don’t panic, Danos said, because the world needs oil and gas, will will make up a significant portion of the globe’s energy production for the foreseeable future. This should be a source of confidence, he explained. “But then again, we also need to embrace the fact that the world is transitioning to renewable forms of energy,” he said. The people of Louisiana are well poised to take part in this transition, through innovation and experience, ultimately becoming leaders in the transition, Danos added.
Texas LNG Bunkering Project Starts Waterway Assessment Process with Coast Guard - A plan to build the first liquefied natural gas (LNG) bunkering terminal along the U.S. Gulf Coast is progressing through the permitting process by initiating a water suitability assessment with the U.S. Coast Guard (USCG). Pilot LNG LLC’s proposed Galveston LNG Bunker Port (GLBP) project would comprise an LNG production vessel that would be permanently moored off Pelican Island, TX. The island is in Galveston Bay, one of the busiest marine corridors in the United States, providing access to the ports in Houston, Galveston and Texas City.The project, which would have production capacity of 500,000 tons per year, equivalent to about 64 MMcf/d of gas, plans to make a positive final investment decision in late 2021 or early 2022 after getting regulatory approvals. Operations are slated to begin in 2024.Pilot LNG earlier this month submitted a letter of intent and a preliminary water suitability report to the USCG to initiate the evaluation, management said. The review would assess the potential safety, security, marine and economic impacts of expected marine traffic from the project. Bunker barges would load at the terminal and distribute LNG fuel to ships, but the project has not yet determined if it would operate its own fleet.The bunker port project in October reached a preliminary long-term supply deal with GAC Bunker Fuels, an affiliate of the GAC Group that procures fuel for customers in the shipping industry. The heads of agreement outlined the terms for Pilot to provide LNG bunker fuel to GAC customers on a delivered ex-ship basis.The project in July applied for key permits from the U.S. Army Corps of Engineers. The U.S. LNG bunkering market is most advanced along Florida’s Atlantic Coast, primarily to serve ships transporting U.S. goods to Puerto Rico. Demand for LNG bunker fuel is poised to grow. International regulators have tightened emissions standards, and the maritime industry has increasingly turned to LNG as a fuel source because of its lower emissions profile and cost competitiveness. The International Maritime Organization has established the goal of reducing greenhouse gas emissions from shipping by at least 50% by 2050 compared to 2008, and many LNG-fueled ships are expected to be produced going forward.
Natural gas leak repaired on rig near Bob Hall Pier — Magellan E&P Holdings, Inc., the operator of a platform located in the Mustang Island offshore planning area has repaired a natural gas leak. City officials say the leak occurred early in September. The leak happened because off a failed valve. Officials say no further leaks or emissions are expected. However, there are still repairs to be made and vessels involved in the repair process will remain visible from shore. City officials said the company continues to fully cooperate with all appropriate state and federal regulatory entities.
Oil and gas job losses in Texas were even worse than reported - The oil and gas industry in Texas lost more jobs than reported after the federal government revised its employment estimates. Nearly 60,000 oil drilling, production and services workers have lost their jobs between February and August, 20 percent higher than the 50,000 layoffs previously reported, according to a new report from the Texas Alliance of Energy Producers. The new job analysis from the statewide trade group comes after the Federal Reserve Bank of Dallas revised its employment data, which showed that more jobs were cut in the oil-field services sector than previously thought.
US oil, gas rig count rises by 10 to 414 as producers try to hold output: Enverus — US oil and gas rigs rose by 10 to 414 in the week ending Dec. 16, rig data provider Enverus said, as operators continue to replace production setbacks earlier in the year from coronavirus-related curtailments. Stay up to date with the latest commodity content. Sign up for our free daily Commodities Bulletin. Sign Up The week's gains were split 50-50, five apiece between oil plays, where the number of rigs rose to 300, and gas fields, where the number increased to 114. Among individual basins this week, changes were a hodgepodge, with most basins adding or shedding a rig apiece. The Eagle Ford Shale of South Texas added two rigs for a total 32. Adding one rig each were the Permian Basin (181 rigs) of West Texas/New Mexico, the Haynesville Shale (46) in East Texas/Northwest Louisiana and the Marcellus Shale (30), mostly in Pennsylvania. Reducing fleets by a rig apiece on the week were the Bakken Shale (13) of mostly North Dakota, the SCOOP-STACK (13) of Oklahoma, and the Utica Shale (six), mostly in Ohio. The DJ Basin of Colorado was unchanged on week at nine rigs. "Overall, North American drilling and completions activity is tracking higher than expected," Wells Fargo analyst Christopher Voie said in a Dec. 17 investor note. "The Lower 48 rig count is above expectations, and based on discussions with [four large US drillers], the horizontal rig count is tracking above our models and should plateau through year-end." For the week ended Dec. 16, the horizontal rig count was 329, down two, according to Enverus data. While first-half 2021 visibility is limited, "we model 350-360 horizontal rigs by mid-2021, assuming private E&Ps' activity mirrors publics' budget discipline" which is conservative, Voie said. S&P Global Platts Analytics expects rigs to continue to recover through early 2023. More good news on a coronavirus vaccine could cause a further uptick from what Evercore analyst James West called "jaw-dropping" declines in North American rig counts this year. The current total rig count is now just shy of half its early March figure of 838, Enverus data shows, and the North American rig count is poised for to rise, albeit off a low base, West said.
U.S. Crude Oil Inventory Declines; Weekly Demand Increases But Remains Modest, EIA Says - After jumping a week earlier, domestic oil inventories dropped during the week ended Dec. 11, the U.S. Energy Information Administration (EIA) said Wednesday. EIA said in its Weekly Petroleum Status Report that U.S. commercial crude oil inventories — excluding those in the Strategic Petroleum Reserve — decreased by 3.1 million bbl from the prior week. A week earlier, stockpiles increased by nearly 15.2 million bbl amid robust imports and after light post-Thanksgiving holiday demand, lifting crude storage to its highest level since August.The latest result “was a nice walk down from last week’s supersized” build, said Robert Yawger, director of energy futures at Mizuho Securities USA LLC. The prior week increase “threatened to overwhelm storage in a relatively short time span. This week’s report has reduced those concerns.”Despite a draw in the latest covered week, U.S. inventory of 500.1 million bbl is still about 10% above the five-year average for this time of year, EIA said.Demand, meanwhile, increased 4% week/week for the latest covered period, EIA said, but it remained weak relative to pre-pandemic levels in 2019. Demand has been choppy on a week-to-week basis but, aside from an occasional exception, it has been consistently below year-earlier levels in recent months.Demand for the Dec. 11 week was 11% below the comparable week of 2019, with jet fuel consumption down 44% year/year and gasoline off 15%.
Ban on federal drilling leases would cost eight U.S. states billions, study finds (Reuters) - A ban on new oil and gas drilling leases on federal lands would cost eight Western states $8.1 billion in tax revenue and $34.1 billion in investment in the next five years, according to a study released on Tuesday by the state of Wyoming. The report, commissioned by one of the nation’s top oil and gas-producing states, aims to push back against President-elect Joe Biden’s campaign promise to halt leasing on public lands as part of a sweeping plan to tackle climate change. “The economic predictions are devastating, to be blunt, to Wyoming,” Governor Mark Gordon said during a virtual press conference to unveil the study, which was conducted by University of Wyoming Professor Tim Considine. The policy would be most detrimental to Wyoming and New Mexico, the report said, where most drilling activity occurs on federal lands. Without new leasing, states would lose the opportunity to generate revenues from new wells on those lands. As a result, those states are projected to lose $304 million and $946 million a year in tax revenue, respectively, through 2025. Annual losses in revenue and investment are projected to increase through 2040 as the oil and gas industry becomes more productive and prices increase, the report said. Between 2036 and 2040, the investment losses are expected to reach $164.5 billion. Biden will assume office on Jan. 20 and has promised aggressive policies to reduce climate-warming greenhouse gas emissions. His administration will mark an abrupt shift from that of President Donald Trump, which has sought to boost domestic oil and gas production over the last four years. During the press conference, Wyoming officials said it was likely that a leasing moratorium would simply shift production and related emissions to other regions, such as Mexico or Canada, rather than having the desired effect of helping to curb global emissions from drilling activity.
Oil's collapse could spark growth in Colorado natural gas - For the first time in years, market conditions for natural gas may be poised to spark growth in Colorado’s oil and gas industry. The price for natural gas reflected in contracts for winter deliveries rose steadily in recent weeks. An upswing is normal as cold weather sets in, but contract prices are up 20% from the same point in 2019, and forecasts increasingly predict natural gas' price rise to hold beyond winter. Domestic oil and natural gas production has been dropping due to the collapse in the price of crude oil, and reduced supply is bolstering the price of natural gas. Prices are settling into a $2.50 to $3 per million British thermal unit range at the regional pipeline hub in Western Colorado — high enough for Colorado’s natural gas producers to consider expansion. “That puts a dry gas producer in the money,” said John Harpole, founder and president of Littleton-based Mercator Energy, a natural gas services and brokerage company. “The dry gas producers finally have a price.” Sustained conditions for even modest expansion would be a welcome change for a part of the state’s oil and gas industry that’s been quiet. Western Colorado is home to the Piceance Basin, the second-largest reserve of natural gas in North America. There’s also abundant natural gas in the San Juan Basin in southwestern Colorado. Denver also is home to the headquarters of Antero Resources (NYSE: AR), the third-largest U.S. natural gas producer, which operates in the Utica and Marcellus shale formations in eastern Ohio, western Pennsylvania and northern West Virginia. It primarily supplies the Northeast with natural gas, and exports liquified natural gas east to Europe. Crude oil’s collapse this spring has set the table for natural gas’ renaissance. Shale oil wells also produce natural gas, though the gas is treated by most companies as a byproduct of the more lucrative oil. The crash in crude prices this spring led to a 73% decline in the number of rigs drilling wells in U.S. oil and gas fields, a drop of 461 rigs since early March. The decline in drilling for oil is has cut associated natural gas production from domestic shale basins by 9% since March 6, Antero Resources' analysis shows. The output will remain down through 2021, the company predicts, while U.S. demand for natural gas is unchanged, and exports to Mexico and Europe are expected to rise.
Colorado's Boulder County Revamping Oil, Gas Rules, but Energy Industry Questioning Authority - Colorado’s energy industry has come out swinging against Boulder County’s attempt to impose more stringent oversight of oil and gas well operations. Operators working in unincorporated areas of Boulder County would be required to ensure well pad setbacks are at least 2,000 feet and generally 2,500 feet near homes, schools and licensed child care centers. The setbacks also would be required in light industrial, commercial, business and transitional zones. The three-member Board of County Commissioners unanimously approved the fourth draft last week to revise Article 12 of the Land Use Code. The revisions are “are the strongest rules in the state and will be a model for others,” said Commissioner Matt Jones. Listen to the most-recent episode of our podcast NGI’s Hub and Flow via: A review of the three-year-old land use regulations had begun in March, but Covid-19 stalled hearings. Also, the revisions are tied to state oversight, and the county commissioners wanted to wait for the Colorado Oil and Gas Conservation Commission (COGCC) to complete extensive rulemakings required by Senate Bill 19-181. Among other things, the COGCC last month granted additional authority to local governments to regulate the impacts of oil and gas development. The updated regulations would “provide for close scrutiny of all proposed oil and gas development and multiple opportunities for public input prior to any decision being made,” the county commission noted. “For any new oil and gas development applications, these regulations will allow staff, the Parks & Open Space Advisory Committee, the Planning Commission, and the Board of County Commissioners to consider site-specific circumstances and possible measures to avoid, minimize and mitigate adverse impacts in determining whether to approve or deny a proposal.” The proposed rules also “will help to ensure careful monitoring and enforcement over oil and gas operations,” including existing facilities. While the regulations are under review, the county is continuing a moratorium on new oil and gas development and seismic testing to the end of the year “so that any new applications to drill can be reviewed under the most protective, updated regulations that are ultimately adopted.” Colorado energy industry groups blasted the county revisions as unnecessary. Colorado Oil & Gas Association CEO Dan Haley told NGI’s Shale Daily that the state’s “communities can’t ban oil and natural gas development — either through outright bans or through regulations that make it impossible to access a mineral owner’s private property and investment. “
Line 3 construction barrels ahead, despite efforts to block it | MPR News - In northern Minnesota’s Aitkin County, just north of the tiny town of Palisade, construction workers are clear-cutting a wide path through the forest near the Mississippi River, heavy equipment rumbling, to make way for the new Line 3 oil pipeline replacement project. And Tania Aubid, a member of the Mille Lacs Band of Ojibwe, is there to try to stop them."They want to ship the tar sands, toxic oil. … And when that pipeline breaches, it's going to go into the waterways here," she said.Aubid has come to this place every day for more than a week, part of a group of people who call themselves water protectors — there to speak out against the pipeline and, in some cases, put their bodies in the way of construction.Tania Aubid of the Mille Lacs Band of Ojibwe is among the “water protectors” who have demonstrated at a construction site in Aitkin County where the Line 3 oil pipeline is slated to cross the Mississippi River.Also out there every day: Law enforcement, including Aitkin County Sheriff Dan Guida."You're angry at me because you're mad at them,” Guida told Aubid last week, as he gestured toward the pipeline workers.“These guys are raping, murdering and killing Mother Earth,” Aubid shouted. “You're standing here and not doing anything about it!”Guida told Aubid he understood she’s fighting the pipeline for her grandkids. “We talked about that,” he said. “You're trying to keep their land safe. You're trying to keep their water clean. I understand that. But there is a law that has to be followed.”Construction has ramped up quickly on Line 3 since Enbridge Energy received its final state and federal permits late last month — and so have the protests of activists determined to stop work on the contentious project, at least until challenges can be heard in court. Guida says he respects the "energy" that both sides bring to this divisive project. Demonstrators have set up a gathering space alongside the Great River Road, just a few feet from the pipeline corridor."We want the people here to be safe. We want the people to be heard, we want to support their First Amendment [rights], we want to support their freedom of speech, we want to support all that,” he emphasized.Two people even camped high up in trees along the pipeline corridor for more than a week to try to block work on the project.The scene remained fairly low-key until early Monday afternoon, when several people were arrested, including Liam Delmain, the last person remaining in the trees, who was removed with the aid of a bucket truck. Dawn Goodwin, a member of the White Earth Nation and a leader in the fight against Line 3, witnessed the arrests, but said they left her undeterred. "It just gives me more energy and drive to continue on and do all that I can do to stop this horrible idea," she said.
Indigenous Groups Push Insurers to Abandon Fossil Fuel Projects --AS OIL AND gas projects expand across the United States and Canada, often imperiling Indigenous land without ever obtaining consent, land defenders are increasingly pressuring the financiers of fossil fuel infrastructure — banks, insurance companies, and asset managers — to respect their sovereign land right. Amplifying the calls of this grassroots movement, the largest organization representing American Indians and Alaskan Natives passed a historic resolution last month calling on “private insurance companies to end their underwriting of the expansion of tar sands oil, Arctic oil and gas, and LNG export terminals.”The resolution, put forward by the National Congress of American Indians, or NCAI, also asks insurance companies to adopt policies on “free, prior, and informed consent.” This principle, enshrined in the United Nations Declaration on the Rights of Indigenous Peoples, is “really just a fancy way of saying that any corporation, any bank, any agency that wants to engage in a project that impacts Indigenous lands and treaty lands must get consent from that particular tribal nation or Indigenous community,” said Matt Remle, who is Lakota and the primary author of the resolution. “And if the community says no, that project doesn’t happen.”Remle is also the co-founder of Mazaska Talks, an Indigenous-led organization focused on campaigns to divest from projects that violate human rights and treaty rights abuses, which came out of an effort that began about five years ago to defund the Dakota Access pipeline. This movement pushed the city of Seattle to divest $3 billion from Wells Fargo in 2017, one of the main backers of the pipeline, and sparked similar campaigns throughout the country. More recently, every major bank has agreed to not fund drilling in the Arctic after facing pressure from Stop the Money Pipeline, a coalition of over 130 organizations which includes Mazaska Talks. Most Wall Street banks at least publicly acknowledge free, prior, and informed consent while still financing projects, like the tar sands pipelines, that face Indigenous-led opposition. Yet no major U.S. insurance companies, the biggest insurers of oil and gas projects across the globe, have released publicly facing statements about Indigenous rights, let alone the principle of free, prior, and informed consent, according to Elana Sulakshana, energy finance campaigner at Rainforest Action Network. This is, in part, why there has recently been more intense scrutiny of insurance companies’ enablement of fossil fuel projects on Indigenous land.
Bakken Oil Output Flat in October, but Natural Gas Up 2% from September - Oil production in the Bakken Shale during October remained flat month/month at 1.22 million b/d while natural gas output increased by 2% to 89 Bcf, the North Dakota Department of Mineral Resources (DMR) reported Monday. Oil production levels are not likely to grow until 2022, DMR director Lynn Helms said during a monthly webinar. “The resurgence we saw in July through September is pretty much done, and essentially all of the shut-in production has been put back online,” he said. Oil output was slightly above the state’s revised projection level of 1.2 million b/d. “Gas grew at the same time, which is sort of the history of the Bakken/Three Forks reservoirs, and we’re starting the phase where we see enough reservoir depletion and new wells are coming on with higher gas-oil ratios.” Total October oil production was 37.9 million bbl (1.22 million b/d), compared to 36.6 million bbl (1.22 million b/d) in September. Gas output reached 89 Bcf (2.87 Bcf/d) from 84.4 Bcf (2.81 Bcf/d). Gas capture was 93% in September and October, with the remaining 7% of output flared. “Industry now has the infrastructure in place, so capture stayed the same with a slight decrease in volumes/day” at 13 MMcf/d,” Helms said, “so we didn’t lose any ground on gas capture.” Well permitting, however, is “up and down and all over the place,” depending on the price of oil, which he said needs to be at least $55/bbl for significant increases in rigs and well counts.
Bakken Natural Gas Capture in North Dakota Said Improved from 2019, Stable Until 2025 - North Dakota is this year better equipped to capture vented and flared natural gas from the Bakken Shale than in 2019, and processing capacity is said to now be adequate for the next five years. north dakpta gas North Dakota Pipeline Authority director Justin Kringstad discussed the outlook during an interview with NGI’s Shale Daily. “The gas capture landscape has improved dramatically from 2019,” he said. “North Dakota’s gas production exceeded gas processing capacity for much of 2019, but during the second half of that year, the gas processing industry added 700 MMcf/d of new processing capacity to the region.” Overall processing capacity in the Bakken should remain stable through 2025, Kringstad said. “When factoring in additional planned processing capacity expected to come online in 2021-2022, I forecast plant capacity to be adequate until the 2024-2025 timeframe.” The U.S. Energy Information Administration recently reported that North Dakota and Texas led the nation last year in gas venting and flaring. Bakken gas production last year rose to 290 MMcf/d from 200 MMcf/d in 2010, according to federal statistics. “We have prior history to tell us that gas plant capacity needs in North Dakota cannot be viewed in a 1:1 ratio between field production and plant capacity,” Kringstad said. “Today’s current gas processing capacity in North Dakota is expected to be adequate for one to three years before additional capacity would be required.” Long-term projections of takeaway capacity are also enough to keep up with Bakken oil production, which is forecast to reach 1.7-1.8 million b/d by the late 2020s.
North Dakota Examining Potential for Bakken Natural Gas, Liquids Storage - North Dakota’s Industrial Commission (IC) has asked the state legislature to authorize pursuing options to add oil and natural gas storage for the Bakken Shale. The governor-led commission “pre-filed a bill for next year’s legislature to take on permitting of oil, gas and natural gas liquids storage,” said Department of Mineral Resources director Lynn Helms. “Those are critical infrastructure pieces.”To convert part of an oilfield for storage would require approval by the same percentage of surface landowners (55%) as required in field unitization, Helms said. All of the landowners would have to be “equitably compensated” by the storage operators. When at least 55% of the landowners approve pore leasing space for gas storage or a salt cavern for natural gas liquids (NGL), the IC could create a unit to pull all of the space together. There is a legislative vehicle “to move forward and a report is due from the Energy and Environmental Research Center at the University of North Dakota when lawmakers convene next year,” Helms said. A second report on salt cavern storage is to be released to the legislature about the same time.Early last year, the EERC concluded that if certain issues were resolved, injecting the gas produced with the Bakken oil into underground formations and later withdrawing it could allow for more oil production and help meetstate-mandated gas capture goals.Helms said the best potential locations for salt cavern storage locations are between Williston, in the far northwest corner of the state, and Minot in the north-central area. It would need to be along railroad, highway and pipeline routes within proximity of a large workforce.“All of that exists north of Lake Sakakawea and between the two cities,” he said. Caverns are typically used for storing NGLs for petrochemicals before they are processed and shipped to market. “Salt caverns worldwide are the way to store ethane; it looks like from some very preliminary work that it is feasible and we have the geology to support it.”Currently, North Dakota has no underground storage for oil, NGLs or produced associated gas. However, in the Montana portion of the Williston Basin is the largest underground gas storage facility in North America at 164 Bcf capacity, the Baker Storage Field.“At his time, there are no plans for residue gas storage in North Dakota,” said North Dakota’s Justin Kringstad, director of the Pipeline Authority. “The Baker storage is used by both Canadian and Williston Basin shippers.” Kringstad said he was not aware of any plans to expand Baker, which has ample capacity.
Oil companies turn to rapid virus testing to keep crews in field - Oil companies are increasingly relying on rapid tests to determine if any of their workers in the Bakken have contracted the coronavirus. “All 14 of our drilling rigs are using rapid testing for everybody who visits the rig site as well as for the crews coming on and off,” State Mineral Resources Director Lynn Helms said Monday at his monthly briefing on oil production. “The industry’s been buying rapid tests like crazy.” Oil companies have been purchasing the tests, but the industry is hopeful it can use some of the state government’s stash, said Ron Ness, president of the North Dakota Petroleum Council. State officials began a more concentrated effort last month to use up 150,000 tests North Dakota received from the federal government. Some of the tests were slated to go to first responders, health care workers, long-term care facilities, schools and Native American tribes. The Abbott BinaxNOW tests do not require lab processing and return results within 15 minutes. The North Dakota Department of Emergency Services and the Greater North Dakota Chamber are surveying large employers to see if they would be good fits for the state's tests, Ness said. He added that he’s hopeful smaller companies in the Bakken can make use of those tests too. The seven crews completing hydraulic fracturing work in the Bakken are using rapid tests, as well as workers at a gas plant construction site in Williams County, Helms said.
North Dakota oil production not likely to improve for months - North Dakota's oil production was essentially flat in October, and it's not likely to appreciably improve until well into next year or even 2022, the state's mineral resources director said. North Dakota, the nation's second-largest oil-producing state after Texas, pumped 1.22 million barrels of crude per day in October, down 236 barrels from the previous month, the state said Monday. Natural gas production, however, rose 2% from September to October. After the coronavirus pandemic decimated global oil demand, North Dakota's crude production fell to a seven-year low in May of only of 858,400 barrels per day. Output then rallied over the summer as oil prices recovered a bit and shut-in wells were reopened. However, "that surge in July, August and September is over," Lynn Helms, head of the North Dakota Mineral Resources Department, told reporters. The benchmark U.S. crude oil price — West Texas Intermediate (WTI) — has climbed over the past month from $41 to $47 per barrel, about where it was in early March. But Helms said WTI needs to get to at least $55 a barrel before oil operators in North Dakota start looking to drill new wells. Such new business is needed to boost total state oil output as production from existing wells naturally declines. "As we go into next year, I don't think it looks promising in terms of growth," he said. The pandemic's effects on demand and depression of crude prices might not correct itself until late 2021 or 2022. Helms also noted that the oil industry is increasingly challenged by "ESG" — environmental, social, and corporate governance — investors. ESG investors' influence is growing, Helms said. And they aren't partial to the carbon-intensive oil industry. As for 2020, "all and all, it was a terrible year for the industry," Helms said. Still, during his 40 years in the state's oil patch, he said two other oil busts — one in 1985 and 1986, the other in 1999 and 2000 — were worse.
U.S. shale should be worried about 'very aggressive' policies from Washington: Energy secretary - American shale producers are likely being kept up at night over what could be in store for their industry over the next four years, if pledges made by some lawmakers in Congress and President-elect Joe Biden are anything to go by. U.S. Energy Secretary Dan Brouillette seems to think so. Asked by CNBC's Hadley Gamble whether shale producers, whose drilling boom catapulted America to the position of the world's largest oil producer in 2018, should be worried about the incoming administration, Brouillette replied, "Of course." "I think they should be, frankly, because there are some in Congress who are going to drive a climate policy that's going to be very aggressive. So there may be some concern on the part of those folks, I know the ESG (Environmental, Social, and Corporate Governance) movement is very strong." "The investment money may become a bit more difficult to get," he added. "Those are all policies where we'll have to wait and see what happens with this new Congress." A derrick man secures a length of drill pipe during drilling on a natural gas drill rig near Montrose, Pennsylvania, U.S., on Monday, April 5, 2010. Daniel Acker | Bloomberg | Getty Images The ESG movement has picked up pace in recent years, with some major investors — notably BlackRock, the largest asset manager in the world — "making sustainability integral to portfolio construction," according to its CEO Larry Fink. Fink wrote this year that "climate risk is investment risk," and that it's brought the world to "the edge of a fundamental reshaping of finance." But climate action on a federal government level may be what scares shale producers the most. Biden has pledged to pursue "aggressive emissions reductions," focusing on a greener agenda that aims to reduce fossil fuel dependence in the fight against climate change, which climate scientists almost universally agree is a grave threat to the planet. A 2018 report by scientists in President Donald Trump's own administration warned that climate change will cost the U.S. hundreds of billions of dollars yearly and harm human health. Trump, who has consistently supported the fossil fuel industry in favor of American energy independence, replied by saying, "I don't believe it." The Democratic former vice president doesn't plan to outright ban fracking, the fossil fuel extraction process by which shale gas is produced, or oil and natural gas production generally, which employed nearly 1 million American workers in 2019, according to official U.S. figures. But he aims to significantly stifle it with regulation, many analysts say. Biden has pledged to protect national parklands and wildlife refuges, where Trump allowed or tried to allow drilling to take place, and says he will be "banning new oil and gas leasing on public lands and waters," according to his campaign website. He also promised to enact punishments for major corporate polluters, proposing fines and even jail time, and warned that he'd force "polluters to bear the full cost of the carbon pollution they are emitting." And when asked about his approach to the industry in a pre-election presidential debate with Trump, Biden said, "I would transition away from the oil industry, yes. The oil industry pollutes significantly. It has to be replaced by renewable energy over time." He later backtracked somewhat, telling reporters, "We're not getting rid of fossil fuels. We're getting rid of the subsidies for fossil fuels, but we're not getting rid of fossil fuels for a long time." .
SEC approves anti-corruption disclosure after lengthy campaign by oil firms - — The Securities and Exchange Commission voted Wednesday to implement a new regulation requiring American oil and mining companies to report on payments to foreign governments, after a decade-long lobbying campaign by oil companies to weaken transparency efforts.Under the new regulation, U.S.-based companies would be required to report overall payments to governments but not force them to do so on a project-by-project basis, as required in the European Union and Canada. That has drawn protest from anti-corruption groups, who say the rule will offer a general sense of the money flowing into government coffers, but not the details of whether revenues are being skimmed by corrupt officials or the country is getting its fair share for extracted oil and gas.The rule stems from the bipartisan Cardin-Lugar Anti-Corruption Provision passed in 2010 as part of Dodd-Frank, Congress’s effort to regulate Wall Street and limit the amount of risk banks could assume after the 2008 financial crisis.But in the years after Republican opposition grew amid persistent lobbying and a lawsuit by the oil and gas industry, claiming it would be put at a disadvantage in bidding for overseas projects where transparency might be considered a detriment.In 2017 Republicans and President Donald Trump passed new legislation ordering the SEC not to require as much detail in creating anti-corruption rule-making.Last year under SEC Chairman Jay Clayton, the SEC released a revised rule that drew protest from Democrats and cheers from the oil sector. "We appreciate the Commission’s work on this rule and the effort to balance transparency with the its overall mission to protect investors, competition and the efficiency of capital markets,” Stephen Comstock, a vice president at the American Petroleum Institute, said in a statement Wednesday. "It will set the world back years in the effort to fight corruption in the oil and mining industries," said Kathleen Brophy, U.S. director of the nonprofit Publish What You Pay. "It's part of a slew of other midnight rules the Trump administration is trying to push through."
John Day Dam oil leak spills into Columbia River - Maintenance technicians at John Day Dam estimated 63 gallons of oil spilled into the Columbia River from a pinhole leak in a turbine guide bearing chiller discovered on Monday, Dec. 7. The U.S. Army Corps of Engineers, Portland District (Corps) discovered the leak near the downstream side of the dam. Corps staff isolated the system, began identifying the exact number of gallons lost and started fixing the issue. The Corps is dedicated to rapid spill responses. “Daily, weekly and monthly inspections are a critical way for us to swiftly identify and respond to oil spills,” said Dwane Watsek, Operations Division chief. “The team’s attention to detail during one of these inspections led to the discovery of the pinhole leak. The unit will remain out of service and isolated from the river until technicians assess and repair it.” Corps officials notified partner agencies, including National Response Center, Oregon and Washington emergency management offices and the Columbia River Intertribal Fish Commission. This is the second spill at Corps dams on the Columbia River this month. The Dalles Dam spilled 45 gallons of oil into the river, Dec. 3. Corps technicians originally estimated the impacted turbine could have lost up to 200 gallons; however, they confirmed the lesser amount Dec. 11.
Oil continues to spill from sunken freighter off Vancouver Island; wildlife affected -- Federal officials say emergency response crews will work through the holidays to try to contain an oil spill from a historic shipwreck off the west coast of Vancouver Island. The coast guard says it is still working to confirm just how much fuel oil was on board the Holland America freighter when it ran aground in Nootka Sound and sank in January 1968. The 150-metre MV Schiedyk was carrying thousands of tonnes of wood pulp and barley bound for Portland, Ore. when it went down near Bligh Island. All 34 sailors aboard the ship survived the wreck. Related Stories •'A very serious situation': Coast guard scrambles to clean spill from sunken freighter Mariners and aviators in the remote area say small slicks of bubbling oil have long been apparent on the water’s surface, but last month those trickles turned into a plume of oil stretching upwards of two kilometres. The coast guard says it first received reports of an oil sheen near the island in September but investigators couldn’t locate its source until early this month. On Tuesday, officials said there are approximately 30 to 50 litres of oil on the water’s surface at any given time. Six pollution response vessels and 40 personnel are currently on scene, with two more expected to arrive over the coming weeks. Crews have deployed two oil skimmers and nearly 5,000 metres of containment booms around the site to contain what DFO officials say is a “continuous but slow discharge of oil pollution.” More than 40 additional pollution response workers from federal, provincial and local governments are managing the spill response on shore. Federal officials said Tuesday they don’t know how much oil has been collected to date. Samples of the oil have been sent to a lab for identification and officials say both bunker fuel and diesel were on board when the vessel sank. “Photo and video documentation from the ROV (remotely operated underwater vehicle) shows that the ship sustained significant damage when it sank in 1968,” said wreck co-ordination spokesperson Kiri Westnedge. “The upwell of oil is coming from several locations in the vessel.” Westnedge says a dead sea otter was found near the spill site and a necropsy will determine whether it died due to exposure to the oil. Another sea otter was found alive but covered in oil. Crews were attempting to capture the otter Tuesday to transport it to the Vancouver Aquarium’s Marine Mammal Rescue Centre. A blue heron was also found coated in oil.
Snare Falls Hydro unit removed from service after potential oil spill spotted - The Snare Falls Hydro Unit was removed from service on Dec. 10, according to a news release issued by the Northwest Territories Power Corporation (NTPC) Friday. The release states that a “potential spill” was spotted in the water near Snare Falls as staff spotted an oil sheen during testing of the unit. A report was called into the NWT Oil Spill Line on the same day. “A diesel unit at the Jackfish Generating Plant will provide backup power while Snare Falls is offline, if required,” states the release. Noel Voykin, president and CEO at NTPC, provided a statement saying that the corporation is prioritizing environmental safety and contending with maturing equipment as it attempts to bring the unit back online. “NTPC took a proactive approach to protecting the environment when it began work at Snare Falls,” Voykin stated. “We expect to face ongoing challenges with maintenance of aging hydro infrastructure until our hydro fleet can be refurbished. Friday’s release states that NTPC became aware that the Snare Falls unit was consuming a higher volume of oil than normal last week. At the time, there was no evidence that the oil was being released to the environment. As a precautionary measure, booms were put in place several weeks ago when maintenance work began to ensure that any leaks are contained. The cause of the spill is still under investigation.Last May, the Snare Falls unit was shut down for about three weeks in May 2020 as the result of a similar situation. “The timetable for completion of the investigation and maintenance work at Snare Falls are unknown,” states the release. The costs are also unknown.
Alaska environmental regulator reports 190-barrel oil spill at Hilcorp site on Cook Inlet - An oil spill at a Hilcorp Alaska facility on the west side of Cook Inlet was discovered Tuesday afternoon, a state environmental regulator said Wednesday. The state reported that 190 barrels leaked from containment layers. As of Wednesday afternoon, the spill was contained to the facility and had not reached Cook Inlet, according to an Alaska Department of Environmental Conservation report. The spill was discovered by an operator at 12:30 p.m. Tuesday at the Trading Bay Production Facility, about 20 miles northwest of Kenai, and was reported two hours later, according to DEC. “It’s a large quantity of oil, however, the weather is working for us right now,” said Jade Gamble, a unit manager for DEC’s Prevention, Preparedness and Response Program. “The ground is frozen so it’s not able to seep through the ground as easily as it would in the summertime.” The spill is a mixture of 80% crude oil and 20% water, called “slop oil,” which can’t be sold, according to the report. On Tuesday, 15 barrels of oil were recovered from the spill. The spill happened during a transfer of oil from one tank to another, the state report said. An operator noticed that one tank wasn’t filling proportionately to how much oil was leaving the original tank. “After visual inspection, the operator observed oil under and around the edges of the secondary containment liner,” the state said. Gamble said the oil is on the ground and not being held by any other containment barrier, but is in the facility and is at this point staying put. She said the groundwater is more than 100 feet underground and currently believed to be safe from the spill. Hilcorp in a statement confirmed details of the state’s account of the spill. Spokesman Luke Miller in an email said the spill was “immediately isolated” and cleanup is underway. Gamble said the priority now is making sure the spill doesn’t reach Cook Inlet. She said the cause is still under investigation. In a report published online, the state cited “a leak in an underground line in the slop oil processing system.” The facility is near Trading Bay State Game Refuge and Redoubt Bay Critical Habitat Area, which contain important bird habitat, particularly in the summer, according to the state report. During winter, many species have migrated from the area, but it is home to rock sandpiper, which are known to overwinter there and might be in the area, the report states. Other potential overwintering wildlife include some species of waterfowl, seabirds, shorebirds, raptors and moose.
Groups to court: Stop 'headlong rush' to drill in ANWR -- Wednesday, December 16, 2020 -- A coalition of environmental and Indigenous groups last night asked a federal court to put an immediate halt to the Trump administration's plans to open the coastal plain of the Arctic National Wildlife Refuge to oil and gas development.
ECA LNG Export License Extended As Panama Canal Bottleneck Tightens - The U.S. Department of Energy (DOE) has extended through 2050 the long-term liquefied natural gas (LNG) export license of the EnergÃa Costa Azul (ECA) facility that was sanctioned for the west coast of Mexico last month. ECA was one of seven LNG export projects for which DOE granted an extension following a policy change implemented by the Trump administration earlier this year. In addition to ECA, DOE extended export terms for the Golden Pass facility under construction in Sabine Pass, TX, as well as the Texas LNG project proposed for Brownsville, TX, the proposed Magnolia and Driftwood LNG terminals in Louisiana, and the Delfin floating LNG project offshore Louisiana. ECA has DOE authorization to import and liquefy U.S.-sourced natural gas for export from Mexico. Equity stakes of 41.7% each are held in the project by Sempra LNG and Infraestructura Energética Nova (IEnova), while offtaker Total SE recently acquired the remaining 16.6%.The ECA project, one of multiple liquefaction terminals envisaged for Mexico’s west coast, would allow U.S. gas exports to bypass the Panama Canal and reach Pacific demand markets faster and more cheaply. The project’s geographic advantages explain why it was sanctioned this year in spite of the havoc wreaked by Covid-19 on the global LNG market, RBN Energy LLC analyst Jason Ferguson said in a blog post last week. He noted, however, that getting gas into the area “can sometimes be tricky,” citing that gas prices in the U.S. Desert Southwest and SoCalGas border regions have traded at premiums of about $0.20/MMBtu to the Louisiana and Texas Gulf Coast markets this year. Mexico Pacific Limited LLC’s (MPL) CEO Doug Shanda told NGI recently that commercial momentum for MPL’s LNG export project in Mexico’s Sonora state is building, citing that, “Asian countries don’t have indigenous resources and they’re really concerned about energy security.” LNG vessels have been waiting longer to pass through the Panama Canal in recent weeks, tightening an already stretched shipping market and creating logistical issues for U.S. LNG exports at a time when global gas prices are moving higher.
New Five-Year Plan for Mexico E&P Potential Sign of Future Bid Round Reactivation - The release of a new five-year plan by Mexican Energy Ministry Sener could be a sign that future exploration and production (E&P) bid rounds for private sector operators are in the offing. That’s according to analysis done by Mexican consultancy Talanza. E&P bid rounds have been frozen since President Andrés Manuel López Obrador came to power in late 2018, and this would be a sharp departure from current government policy. On October 28, Sener published the second five-year plan for E&P bidding processes as required by the Hydrocarbons Law. The first was published in 2015 with four subsequent annual updates from 2016 to 2019, but this is the first new plan published during the administration of López Obrador. “At the beginning of his administration, president López Obrador announced the suspension of future bidding rounds and the publication of this document raises suspicions about a possible policy change,” analysts Marco Cota and Ricardo Alcudia said. “However,” he warned, “this publication could be the outcome of a legal requirement.” The main differences between the new plan and the previous edition are the absence of unconventional areas and the increase in block size in the offshore. Learn More - LNG Insight “This five-year plan brings new hopes about reactivating bidding rounds in the future, based on the fact that Sener actually worked on a new proposal increasing block size and resources per block for offshore areas,” the analysts said. The previous plan included 187 blocks for unconventional areas covering 53,969 square km (20,838 square miles). López Obrador and Energy Minister RocÃo Nahle have been adamant that hydraulic fracturing (fracking) would not be permitted during this 2018-2024 presidential term, even as regulation for the technique remains in place. The new five-year plan formally recognizes that all rounds are suspended, and “relaunching them is conditioned to private operators’ cooperation for achieving national energy objectives,” the Talanza analysts said. In other words, private sector operators need to show results from the contracts awarded during the previous administration. Mexico’s private sector organization Asociación Mexicana de Empresas de Hidrocarburos (Amexhi) is upbeat about the upstream performance of bid round winners. They said recently that E&P contracts awarded through Mexico’s 2013-2014 energy reform remain on track to reach targets. The group is aiming for natural gas production of 355 MMcf/d and oil output of 280,000 b/d by 2024 from the contracts, which were awarded through bid rounds, farmout tenders and the migration of oilfield service service contracts to E&P contracts between 2015 and 2018. “Practically all the oil companies in the world are cutting their investments,” the group said in an update published November 30. “Nonetheless, the commitment to Mexico is maintained.” The group said it expects private oil production to close 2020 at 57,000 b/d, up 20% from full-year output in 2020.
Venezuela's PDVSA starts oil transfer from offshore facility to barge, sources say - (Reuters) - Venezuelan state oil company Petroleos de Venezuela PDVSA.UL has begun transferring crude off of an offshore oil facility where governments in two neighboring countries have voiced concerns about a potential spill, two people familiar with the matter said on Tuesday. The company this week began the first of several transfers from the Nabarima floating storage and offloading facility (FSO), anchored in the Corocoro oilfield off Venezuela's eastern coast, onto the Inmaculada barge, said the people, who spoke on the condition of anonymity because they were not authorized to speak publicly. The Inmaculada will ferry the crude onto PDVSA's Icaro tanker, a process expected to take weeks, the people said. Refinitiv Eikon tracking data show the Icaro navigated toward the Nabarima on Tuesday morning and anchored nearby in the Gulf of Paria. PDVSA did not immediately respond to a request for comment. The company has previously dismissed concerns by environmental groups and the governments of neighboring Trinidad and Tobago and Brazil that the facility could be prone to a spill. The Nabarima is holding some 1.3 million barrels of crude, and images of the facility listing in September and October raised alarms about a potential spill. PDVSA corrected its tilt and said the vessel, part of the Petrosucre joint venture with Italy's ENI SpA ENI.MI was in satisfactory condition. PDVSA has suffered for years through cash flow shortages during an economic crisis that has led OPEC-member Venezuela to neglect maintenance of infrastructure. More recently, U.S. sanctions on the company aimed to oust Venezuelan President Nicolas Maduro have hindered operations.
Oil refinery fined over spill, penguins get off scot-free - An oil refinery business has been fined for leaking thousands of litres of transformer oil into Wellington’s Seaview Marina. No penguins were harmed by the toxic oil, but only by the sheer chance that their breeding season was over. eNZoil (NZ) Ltd was convicted and fined $90,000 for discharging between 5000 and 6000 litres of refined transformer oil from their operation into the stormwater network and then Seaview Marina, on March 17 - 18 last year. Greater Wellington Regional Council laid charges against the company, which takes waste transformer oil and refines it into a usable product. In passing sentence, Judge Dwyer said the discharge was a result of gross negligence and significant failures. The spill was the result of a series of failures, including not closing a valve on a bund which should have contained any spill. The oil, despite being refined, is still toxic to sea life..”Given the proximity to the marina and the direct connection to the stormwater system, they should have been aware of the risks; processes should have be undertaken with the highest degree of care.” However, he acknowledged that eNZOil was an environmental and sustainability focused organisation, taking a waste product and making it reusable. eNZoil assisted with clean-up, which involved regional council harbours and environmental protection staff, Hutt City council officers, and marina staff. A spokesperson said the company immediately accepted responsibility. “We were implementing equipment and process changes which we believe would have prevented the event, but regrettably these were not in place at the time.” Ongoing improvements to their system would ensure no more spills. “eNZoil is a small business committed to removing a pollutant from the environment not adding one to it.”
Reliance, BP Ramp Up First of Three Massive Natural Gas Fields Offshore India - BP plc and Reliance Industries Ltd. have ramped up production from the first of a trio of ultra-deepwater natural gas fields offshore India that could meet the country’s rapidly expanding energy needs and reduce the need for imports. The R Cluster project in Block KG D6 is about 60 kilometers (37 miles) off the east coast of India. Satellites Cluster is set to come onstream in 2021, followed by the MJ project in 2022. Peak gas production from the three fields is forecast to be around 1 Bcf/d, or 30 million standard cubic meters/d (MMcm/d) by 2023. The three fields together could meet 15% of India’s gas demand by 2023 and account for 25% of total domestic production, sharply reducing the need for liquefied natural gas (LNG) imports. “This start-up is another example of the possibility of our partnership with Reliance, bringing the best of both companies to help meet India’s rapidly expanding energy needs,” BP Group CEO Bernard Looney said. “Growing India’s own production of cleaner-burning gas to meet a significant portion of its energy demand, these three new KG D6 projects will support the country’s drive to shape and improve its future energy mix.” The field is expected to reach plateau gas production of nearly 13 MMcm/d) in the coming year. It would produce from a subsea production system tied back to the existing KG D6 Control & Riser Platform (CRP) via a subsea pipeline. Reliance operates the field with a 66% stake; BP holds the minority interest. The partnership with BP “combines our expertise in commissioning gas projects expeditiously, under some of the most challenging geographical and weather conditions,” India’s growing energy needs “require rapid scaling across a wide spectrum of energy sources and technological solutions,” BP noted. India is the world’s third largest primary energy consumer today, according to BP’s Energy Outlook. The country’s primary consumption is set to more than double by 2050. “However, primary energy consumption per capita is significantly lower than most countries, indicating significant inequities in energy consumption,” BP noted. “Gas consumption is 60 billion cubic meters/d (165 MMcm/d), and more than 50% is imported.”
Japan considers ¥30 billion loan to Mauritius after oil spill - Japan is considering offering ¥30 billion ($289 million) in loans to Mauritius following a major oil spill in July off its coast caused by a Japanese freighter, Foreign Minister Toshimitsu Motegi said Sunday during a visit to the Indian Ocean country. Speaking after talks with Mauritius Prime Minister Pravind Jugnauth and Foreign Minister Nandcoomar Bodha, Motegi said Japan will also start delivering technical support to restore the Mauritian environment and local fisheries industry from next month. Motegi said Japan will "positively consider" meeting Mauritius' request for yen loans to help it recover from the spill and develop its economy, which has also been hit by the novel coronavirus pandemic. "Japan hopes to implement concrete cooperative measures thoroughly at an unprecedented speed and size," Motegi told reporters online from Mauritius, after he inspected a coastal area damaged by the oil spill. Tokyo is working to compile an aid package for Port Louis after Motegi promised Jugnauth over the phone in September to provide long-term assistance, including support for the local fisheries industry and for restoring damaged mangroves. Japan has since sent a team of experts to Mauritius to work out the package.
Japan operator says human error caused Mauritius oil spill - The Japanese operator of a bulk carrier that struck a coral reef and caused an extensive oil spill off the coast of Mauritius said Friday that the accident occurred after the ship shifted its course two miles (3.2 kilometres) closer to shore than planned so its crewmembers could get cellphone signals. Mitsui O.S.K. Lines said its investigation showed the accident was caused by human error, including inadequate nautical charts, navigation systems and risk awareness, and a lack of supervision and safety monitoring. The company said the tanker's nautical chart provided little information about depth and other necessary information. Crewmembers on duty also failed to conduct safety checks visually or by radar, it said. The captain and crewmembers were also using their cellphones while on duty, the company said. It said it will invest about 500 million yen ($4.8 million) to provide electronic nautical charts, training to strengthen safety culture and other systems to enhance safety. The environmental disaster began July 25 when the ship MV Wakashio strayed off course and struck a coral reef a mile (1.6 kilometres) offshore. After being pounded by heavy surf for nearly two weeks, the ship's hull cracked and on Aug. 6 began leaking fuel into a lagoon, polluting a protected wetlands area and a bird and wildlife sanctuary. The company apologized for the damage and in September offered 1 billion yen ($9 million) to fund environmental projects and support the local fishing community in Mauritius. More than 1,000 tons of oil spilled into the coastal waters. About 3,000 tons that remained on the ship was pumped into barges before the Wakashio broke in two several days later. Thousands of civilian volunteers worked for days to try to minimize damage from the oil spill, while environmental workers ferried baby tortoises and rare plants to shore and plucked trapped seabirds out of the goo.
Report indicts Shell employees for causing oil spills in Niger Delta -Employees of Shell Petroleum Development Company (SPDC) in Nigeria cause oil spills to enable them to make money from cleanups, a new report by Milieudefensie and Friends of the Earth Nigeria, verified by an independent journalist, has said. A statement issued by Head of Yenagoa Office of the Environmental Rights Action/Friends of the Earth Nigeria (ERA/FoEN) in Bayelsa State, Alagoa Morris, revealed that Shell organises the oil spill cleanups in such a way that they generate income for the local population and that the oil giant was aware of the development, but was doing nothing about it. Milieudefensie said: “Shell employees are involved in the oil spills in Nigeria. This directly contradicts the picture that Shell paints, in which it places the responsibility for the spills on rebels and saboteurs. “Residents of Ikarama in the Niger Delta not only confirm that Shell employees hire residents to perpetrate spills, but also claim that they have approached everyone in the community. Most people are sensitive to the issue because their fields and fishponds are often too polluted by oil to earn a living.” A representative of the Ikarama community pointed out that “someone who is hungry is someone who easily consents.” “Shell employees, residents, and cleanup companies are working together. The employee points out where and when a spill occurs. Young people usually perpetrate spills. Then a Shell employee hires a cleanup company from among the perpetrator’s acquaintances and afterward, they divide the profit among themselves. At least 30 oil spills have been recorded in the Ikarama area in the past 10 years,” the statement added. The report described several key moments that prove that Shell was aware of the practices and, should, therefore, be Shell’s responsibility to protect the pipelines from the spills and also arrange for their cleanup.
IEA, OPEC Each Lower Estimates for Global Oil Demand, Citing Weak Transportation Fuel Consumption - Demand for transportation fuel remains weak amid a still-raging global pandemic, forcing downward revisions to oil consumption for 2020 and next year. The International Energy Agency (IEA) said Tuesday in its Oil Markets Report for December that it lowered its demand estimate for this year by 50,000 b/d and its projection for next year by 170,000 b/d. Citing pandemic-induced travel restrictions that continue to curb demand for jet fuel and gasoline in Europe and the United States, the Paris-based watchdog said 2020 oil demand would fall 8.8 million b/d when compared to 2019, to 91.2 million b/d, while 2021 consumption would increase by an estimated 5.7 million b/d. IEA researchers said coronavirus vaccines that hit the market this month – and more are expected early next year – provide upside to both economic growth and fuel demand in 2021, though the recovery is expected to prove gradual over the first half of the year. A full rebound is dependent on widespread inoculation bringing an end to the pandemic. It “will be several months before we reach a critical mass of vaccinated, economically active people and thus see an impact on oil demand,” IEA researchers said. “In the meantime, the end-of-year holiday season will soon be upon us with the risk of another surge in Covid-19 cases and the possibility of yet more confinement measures.” The Organization of the Petroleum Exporting Countries this week also lowered its 2021 global oil demand forecast. In its Monthly Oil Market Reportreleased Monday, the cartel said it now expects consumption will rise by 5.9 million b/d to 95.89 million b/d in 2021. In November, it predicted demand would grow by 6.25 million b/d. Last month’s outlook reflected a 300,000 b/d drop from a previous forecast. OPEC expects oil demand to decline by 9.77 million b/d to 89.99 million b/d this year. It cited the festering impacts of the coronavirus pandemic on transportation fuel demand for the lowered 2021 outlook and the 2020 decline. The pandemic “and accompanying lockdown measures have had an unprecedented impact on world oil demand,” OPEC researchers said, “with the latest data pointing to a historic contraction” in 2020.“Uncertainties remain high,” they added, noting the likelihood of more virus outbreaks this winter and the unknown pace of vaccine rollouts, as well as the potential for long-term changes to consumer behaviors, “predominantly in the transportation sector.”
Oil prices steady after six weeks of gains, pressured by glut (Reuters) - Oil prices were little changed in choppy trade on Monday as persistent oversupply in the market largely offset hopes that a rollout of coronavirus vaccines will lift global fuel demand. Brent crude futures for February ended the session 32 cents, or 0.6%, higher at $50.29 a barrel, while U.S. West Texas Intermediate crude futures for January settled up 42 cents, or 0.9%, at $46.99 a barrel. Prices slid more than 1% earlier in the session after OPEC said global oil demand would rebound more slowly in 2021 than previously thought because of the lingering impact of the coronavirus pandemic, hampering efforts by the group and its allies to support the market. Brent and WTI have rallied for six consecutive weeks, their longest stretch of weekly gains since June. “Price momentum has slowed appreciably during the past couple of weeks and while some fresh or unexpected bullish headlines may be required to advance the complex into new high territory, we will also note a market that appears to have developed immunity to bearish headlines that would normally be slapping the complex down,” Jim Ritterbusch, president of Ritterbusch and Associates, said. Signs of rising supply have weighed on the market. Libyan oil production stood at 1.28 million barrels per day on Monday, a National Oil Corporation (NOC) source said, up from 1.25 million bpd in late November. In the United States, energy firms last week added the most oil and natural gas rigs in a week since January as producers continued to return to the well pad. Global onshore crude inventories in December are still well above 2019 and 2018 levels, market intelligence firm Kpler said, with the biggest onshore builds this year seen in China .
Oil prices rise to 9-month high on vaccine rollout, stimulus hopes - Oil prices gained on Monday amid hopes that a rollout of coronavirus vaccines will lift global fuel demand. Brent crude futures for February rose 32 cents, or 0.6%, to $50.29 a barrel, while U.S. West Texas Intermediate crude futures for January were up 42 cents, or 0.9%, at $46.99 a barrel, its highest level in nine months. Brent and WTI have rallied for six consecutive weeks, their longest stretch of weekly gains since June. "Price momentum has slowed appreciably during the past couple of weeks and while some fresh or unexpected bullish headlines may be required to advance the complex into new high territory, we will also note a market that appears to have developed immunity to bearish headlines that would normally be slapping the complex down," Signs of rising supply have weighed on the market. Libyan oil production stood at 1.28 million barrels per day on Monday, a National Oil Corporation (NOC) source said, up from 1.25 million bpd in late November. In the United States, energy firms last week added the most oil and natural gas rigs in a week since January as producers continued to return to the wellpad. Global onshore crude inventories in December are still well above 2019 and 2018 levels, market intelligence firm Kpler said, with the biggest onshore builds this year seen in China . "Whilst the sharp jump of global stocks from the beginning of the Covid pandemic in spring to summer mirrored anemic fuels demand early this year, a still historic high volume of crude oil stocks indicates worldwide demand hasn't yet bounced back to pre-Covid levels," Major European countries continued in lockdown mode to curb the spread of COVID-19 which has reduced fuel demand. For example, Germany, the fourth largest economy in the world, plans to impose a stricter lockdown from Wednesday to battle the virus. In early trading, prices rose after a shipping firm said an oil tanker was hit in the Saudi port of Jeddah, which the energy ministry called a terrorist act. "Traders have for years now been used to tensions flaring in the region and when that happens, oil markets tick up," "(The blast) has caused concerns for stability in the major oil hub of Jeddah and for overall traffic security in the region."
Oil rises more than 1% to 9-month high as vaccine optimism offsets new lockdowns - Oil rose on Tuesday as optimism from the roll-out of coronavirus vaccines balanced out tighter lockdowns in Europe and forecasts of a slower demand recovery. The United States began vaccinating people on Monday as the country's COVID-19 death toll crossed the 300,000 mark. Britain and Canada have also begun to administer shots. U.S. West Texas Intermediate (WTI) crude settled up 63 cents, or 1.34%, at $47.62. Brent crude was up 41 cents, or 0.8% at $50.70 a barrel. Oil prices have recovered in the past few weeks, with Brent reaching $51.06 on Dec. 10, its highest since March, supported by hopes of a recovery in demand. Prices had dropped to historic lows in March as the pandemic took hold. "Brent is continuing to defy all the negative news," said Carsten Fritsch, an analyst at Commerzbank. "More and more countries in Europe and states in the U.S. are tightening the corona restrictions over Christmas and the new year, which is likely to weigh on demand." London stepped up pandemic restrictions requiring bars and restaurants to close, Italy is considering more stringent steps over Christmas and Germany is likely to be under lockdown until early 2021. Forecasters are also trimming demand numbers. The International Energy Agency on Tuesday said that any impact of the vaccines on demand is several months away. OPEC on Monday had said oil demand will rise more slowly than expected. "There is a growing agreement between forecasting agencies that the improvement in global oil demand might not start at the beginning of next year but in the second half," said Tamas Varga of oil broker PVM. The latest snapshots of U.S. oil supplies are expected to show a mixed picture, with gasoline and distillate stocks rising and crude inventories falling.
Oil prices slip on surprise gain in U.S. inventory, demand worries (Reuters) - Oil prices dropped on Wednesday on a surprise gain in crude oil inventories in the United States and as investors continued to worry about demand for fuel being squeezed amid tighter lockdowns in Europe to counter the coronavirus pandemic. Brent crude futures fell 8 cents, or 0.2%, to $50.68 a barrel at 0126 GMT, while U.S. West Texas Intermediate (WTI) crude futures fell 6 cents, or 0.1%, to $47.56 a barrel. “Crude prices are slightly softer after the API (American Petroleum Institute) inventory report posted a second consecutive build,” said Edward Moya, senior market analyst at OANDA. Crude inventories swelled by 2 million barrels in the week to Dec. 11 to about 495 million barrels, according to industry group API. Analysts had expected a draw of 1.9 million barrels, according to a Reuters poll. Official government data was scheduled for Wednesday. The rollout of vaccines this month to combat the coronavirus pandemic will not quickly reverse the destruction wrought on global oil demand, International Energy Agency (IEA) warned on Tuesday. The IEA revised down its estimates for oil demand this year by 50,000 barrels per day (bpd) and for next year by 170,000 bpd, citing scarce jet fuel use as fewer people travel by air. “On the demand side, the biggest near-term downside risk to oil demand expectations is the United States, predominately due to persistent weaknesses in U.S. gasoline demand, given the current trajectory of COVID-19 in the country,” analysts at FGE wrote in a note. Still, progress on vaccine rollouts continued on Tuesday after Moderna Inc’s COVID-19 vaccine appeared set for U.S. regulatory authorisation this week. The U.S. also expanded on Tuesday its rollout of the newly approved COVID-19 vaccine developed by Pfizer Inc and German partner BioNTech SE to hundreds of additional distribution centres on Tuesday, inoculating thousands more healthcare workers in a mass immunisation expected to reach the general public in the coming months.
Oil advances after larger-than-expected U.S. crude stockpile draw - Oil prices edged higher on Wednesday, buoyed by U.S. government data that showed crude stockpiles fell last week and by optimism about a coronavirus relief package in the United States. Brent crude futures rose 28 cents to $51.04 a barrel. West Texas Intermediate (WTI) crude futures settled 20 cents, or 0.4%, higher at $47.82 per barrel. U.S. crude inventories fell by 3.1 million barrels in the week to Dec. 11, the Energy Information Administration said. Analysts had expected a 1.9-million-barrel drop, after stockpiles surged in last week's data. "We couldn't afford to have a build after last week," said Bob Yawger, director of energy futures at Mizuho. "A U.S. stimulus package seems on the way, which will also be supportive." U.S. congressional leaders said substantial progress has been made in the months-long standoff on coronavirus relief and a funding bill to avert a government shutdown. U.S. oil demand is down roughly 13% year-to-date due to the coronavirus pandemic, and Wednesday's figures on retail sales showed a second consecutive month of declining spending due to a resurgence in COVID-19 cases. Worldwide demand has been poor, with the most notable rebound coming in China. The International Energy Agency (IEA) warned on Tuesday that it will take some time to reverse the collapse in global oil demand during the pandemic. The IEA revised down its estimates for oil demand this year by 50,000 barrels per day (bpd) and for next year by 170,000 bpd, citing reduced jet fuel use as fewer people travel by air. In Europe, Germany entered a strict lockdown on Wednesday as the number of registered deaths from COVID-19 jumped by the highest daily increase yet.
Oil Prices Advance As US Inventories Decline -- Oil closed higher on a surprise decline in U.S. crude inventories, but gains were limited with increased gasoline and diesel supplies underscoring weaker fuel demand. Futures in New York rose for a third straight day on Wednesday after flipping between gains and losses during the session. A U.S. government report showed domestic crude supplies fell more than 3 million barrels last week. But the data showed fuel supplies rose and gasoline inventories are at the highest since August, highlighting the mixed picture within the petroleum complex. “The bounce-back in exports and significant decline in imports is driving the draw,” said Rob Thummel, a portfolio manager at Tortoise, a firm that manages roughly $8 billion in energy-related assets. Still, “lack of mobility will impact gasoline demand.” Despite the day-to-day fluctuations in headline crude futures, the rally in physical oil prices signals the fundamental strength underlying the market as Asia leads the recovery from the pandemic-induced demand slump. A slew of purchases from Indian and Chinese refiners have lifted crude values from Russia, the Middle East, Latin America and the U.S. At the same time, other areas of the petroleum markets are signaling strength. Higher diesel prices have lifted the profitability of processing a barrel of light crude into fuels, as diesel consumption has returned to pre-virus levels due to an e-commerce-driven boost in trucking. “Prices since the beginning November have trended higher, and have made up a lot of ground,” said Rob Haworth, senior investment strategist at U.S. Bank Wealth Management. “The faster we get the vaccinations globally, the more that helps the oil narrative.” West Texas Intermediate for January delivery gained 20 cents to settle at $47.82 a barrel, its highest since late February. Brent for February settlement gained 32 cents to end the session at $51.08 a barrel. The contract is at the highest since March. The rise in gasoline inventories comes as indicators of demand for the fuel trend lower. The four-week rolling average for gasoline consumption was down for a fifth straight week and it may weaken further amid expectations for fewer road trips in the U.S. during the Christmas holiday period. Meanwhile, the mixed outlook for oil has weakened the front end of Brent’s forward curve, which is now on the verge of a bearish contango structure in which nearer-dated contracts trade at a discount to later-dated ones. For comparison, Brent’s nearest contract last week traded at a premium of as high as 18 cents to the following month. Crude’s rally over the past month and a half also raises concerns over how well the Organization of Petroleum Exporting Countries can keep output in check, while the producer group and its allies move to taper some of their output cuts come January.
Oil prices rise, hit 9-month high on U.S. stimulus progress (Reuters) -Oil climbed on Thursday and touched a nine-month high, with traders optimistic about progress toward a U.S. fiscal stimulus deal and record-breaking refining demand in China and India. U.S. lawmakers edged closer to agreement on a $900 billion virus-relief spending package on Wednesday. The U.S. dollar set a 2-1/2 year low against major rivals on Thursday. Since crude is priced in greenbacks, this made oil cheaper for buyers holding other currencies. Brent crude futures settled up 42 cents at $51.50 a barrel, and touched a session high of $51.90. U.S. West Texas Intermediate (WTI) crude futures rose by 54 cents to $48.36 a barrel, with a session high of $48.59. Both benchmarks hit their highest since early March. “Asia was ahead of the curve in recovery mode from the Coronavirus,” said Phil Flynn, senior analyst at Price Futures in Chicago. “Looking at what we’re seeing in Asia is raising expectations that in the New Year we will see a rapid increase in crude oil demand, as the vaccine rolls out in the U.S.,” he said. The United States on Thursday expanded its campaign to deliver COVID-19 vaccine shots. U.S. crude inventories fell by 3.1 million barrels in the week to Dec. 11, the Energy Information Administration said, far more than analysts’ expectations of a 1.9-million-barrel drop.
Oil up a 4th straight session to settle at highest price in over 9 months - Oil futures on Thursday stretched their gains to a fourth straight session, as signs of progress toward another round of economic relief by U.S. lawmakers helped to keep prices at their highest levels in more than nine months. "Crude prices have been unstoppable the last several weeks as vaccine rollouts begin, oil inventories are starting to come down, Asian demand remains robust, and the dollar slide propels commodities higher across the board," Edward Moya, senior market analyst at Oanda, said in a market update. "If Congress can get a virus relief bill done this week, that might be the last catalyst needed to help WTI crude make a run towards the $50 level," he said. West Texas Intermediate crude for January delivery rose 54 cents, or 1.1%, to settle at $48.36 a barrel on the New York Mercantile Exchange, for the highest front-month contract settlement since Feb. 26, according to Dow Jones Market Data. February Brent crude , the global benchmark, added 42 cents, or 0.8%, to $51.50 a barrel on ICE Futures Europe to log the highest finish since March 3. "Sentiment has shrugged off slightly bearish monthly updates from OPEC, the EIA, and the IEA this week," Crude was lifted Wednesday after the Energy Information Administration reported that U.S. crude inventories (link) fell by a larger-than-expected 3.1 million barrels in the week ended Dec. 11. Meanwhile,Washington lawmakers were seen making progress toward a $900 billion package (link) of economic relief. The U.S. reported a record 247,000 new COVID-19 cases on Wednesday, The Wall Street Journal reported (link), citing data compiled by Johns Hopkins University. There were 113,090 COVID-19 patients in U.S. hospitals on Wednesday, according to the COVID Tracking Project (link), up from 112,816 on Tuesday, as hospitalizations reached a record for an 11th-straight day. An advisory panel was widely expected on Thursday to recommend the Food and Drug Administration authorize a COVID-19 vaccine developed by Moderna Inc. If the FDA does so, it would be the second vaccine authorized by the FDA, joining the drug developed by Pfizer Inc. (PFE) and BioNTech SE (BNTX), which saw rollout begin this week. "The only thing that could get in the way of oil's rally is if any problems emerge with the coronavirus vaccine rollouts," Moya said. "Transportation issues and some slowness in getting people vaccinated may start to raise doubts that a return to pre-pandemic life will happen by mid-fall." Back on Nymex, natural-gas futures finished lower after the Energy Information Administration reported on Thursday that domestic supplies of natural gas declined (link) by 122 billion cubic feet for the week ended Dec. 11. On average, the data were expected to show a drop of 127 billion cubic feet for the week, according to analysts polled by S&P Global Platts.
Oil settles up, marking seventh straight weekly gain (Reuters) -Oil settled up at a nine-month high on Friday, rounding out seven straight weeks of gains as investors focused on the rollout of COVID-19 vaccines and a decline this week in the U.S. dollar. Pfizer has applied for approval in Japan for its vaccine, which is being used in the United Kingdom and the United States. U.S. Vice President Mike Pence said U.S. approval for Moderna’s shot could come later on Friday. Brent crude settled up 76 cents, or 1.5%, to $52.26 a barrel after touching $52.48, its highest since March. U.S. West Texas Intermediate (WTI) crude settled up 74 cents, or 1.5%, to $49.10 after reaching $49.28, its highest since February. The U.S. dollar rebounded slightly on Friday but stayed near 2-1/2-year lows reached a day earlier. A weak dollar makes oil and other commodities cheaper for buyers using other currencies. U.S. lawmakers worked late to meet a deadline to agree on $900 billion in fresh relief for the pandemic-hit economy, but may instead may pass a third stopgap spending bill to keep the government from shutting down at midnight. The dollar’s weekly decline “is a significant move down and is pushing the oil complex higher,” said John Kilduff, partner at Again Capital LLC in New York. Oil gained support this week from weekly U.S. supply data showing crude inventories fell more than expected. [EIA/S] The oil and gas rig count, an early indicator of future output, rose by eight to 346 in the week to Dec. 18, the highest since May, energy services firm Baker Hughes Co said in its closely followed report on Friday. The Organization of the Petroleum Exporting Countries and allies, known as OPEC+, are supporting the market by slowing the pace of a planned increase in supplies next year. OPEC+ plans to add 500,000 barrels per day of supply in January and will meet in early January to decide on next steps.
Oil Prices Post Another Weekly Gain -- Oil rose for a seventh straight week as efforts to pass another U.S. virus relief package added to optimism that the vaccine’s rollout will provide a long-awaited boost to demand. Futures rose 1.5% in New York on Friday, extending this week’s rally to over 5%. Talks on a relief package have made some headway, with Senate Majority Leader Mitch McConnell saying he’s “even more optimistic now” that an agreement is near. Recent progress in rolling out a Covid-19 vaccine has also buoyed the outlook for consumption. “It’s all about the return to pre-pandemic life, and we’re getting there,” said Edward Moya, senior market analyst at Oanda Corp. “You have major breakthroughs on the vaccine front, which has been very positive for the demand recovery outlook. People are also playing close attention to the overall trajectory of the U.S. dollar.” The Bloomberg Dollar Spot Index is set for a weekly decline and has been trading near its lowest since 2018. A weaker dollar raises the appeal for commodities priced in the currency. Underlying the climb in headline crude prices, premiums on nearer-dated contracts relative to later ones are indicating improving demand. The bullish pattern known as backwardation has strengthened at the back end of oil’s forward curve. West Texas Intermediate’s nearest December contract trades more than a $1 a barrel higher than that for December 2022, compared to trading at a discount less than a month before. Yet, there are signs the market’s rally is due for a pause. Brent’s nearest timespread ended the week at parity, compared with a premium of as much as 18 cents the week prior. At the same time, premiums for real-world barrels are easing. “There’s great news about the arrival of vaccines, the promise they hold, and that global demand is likely to return in a big way as a result,” said Matt Marshall, director of market analytics at AEGIS. “But in the near term, that has zero effect on petroleum demand.” West Texas Intermediate for January delivery rose 74 cents to settle at $49.10 a barrel. Brent for February settlement gained 76 cents to $52.26 a barrel. Both benchmarks closed at their highest since late February. The spreading virus and lockdowns are weighing on demand, but the hit is much smaller than earlier in the year and is likely only a speed bump to rebalancing the market, according to a Goldman Sachs note. This will leave the oil market range-bound and choppy in coming weeks as vaccine enthusiasm is followed by headlines on tighten pandemic restrictions, the bank said. Meanwhile, as oil prices move higher, there are concerns this might lure producers to tap capacity that’s been sidelined during the pandemic. While the U.S. shale industry requires heavy reinvestment to boost output, the large amount of spare capacity could present a risk to further price gains.
Scientists warn of ‘imminent and devastating’ Red Sea oil spill from Houthi-held tanker - A decaying tanker moored off Yemen’s Houthi-controlled coast is on the verge of creating one of the world’s biggest oil spills, scientists have warned. The Safer tanker holds one million barrels of oil — four times the amount that leaked from the Exxon Valdez in the catastrophic 1989 spill in Alaska. The Houthi militia has repeatedly blocked experts from accessing the ship, which was abandoned in 2015. A paper published on Tuesday by a group of international experts warned that unless action was taken immediately, there would be a “regional environmental and humanitarian disaster.” The scientists developed a computer model of how the oil would disperse if a major leak unfolds during winter. Currents at this time of year would spread the oil much further along the Red Sea coast than in summer. The tanker, which was used as a storage and offloading vessel, is moored off the coast of Hodeidah, a key battleground in Yemen’s conflict between the Iran-backed Houthis and the internationally recognized government. “The time is now to prevent a potential devastation to the region’s waters and the livelihoods and health of millions of people living in half a dozen countries along the Red Sea’s coast,” said Karine Kleinhaus, an associate professor of the School of Marine and Atmospheric Sciences at Stony Brook University, who led the team of scientists. “If a spill from the Safer is allowed to occur, the oil would spread via ocean currents to devastate a global ocean resource, as the coral reefs of the northern Red Sea and Gulf of Aqaba are projected to be among the last reef ecosystems in the world to survive the coming decades.” She said that the region’s reefs can survive in much warmer waters compared to other coral around the world, which is being wiped out by rising temperatures due to climate change.
Researchers Warn of Looming Oil Spill Four Times Larger Than Exxon Valdez if Urgent Action Not Taken -- A team of scientists issued a stark warning Tuesday that the possibility of averting an oil spill bigger than the 1989 Exxon Valdez catastrophe and "disastrous environmental and humanitarian consequences" posed by an abandoned oil tanker in the Red Sea are "quickly disappearing." At issue is the corroding Safer, moored off the coast of Yemen and under control of Houthi rebels since 2015. After blocking such efforts for years, Houthi authorities last month approved a United Nations plan to visit the tanker early in 2021. U.N. Environment Program executive director Inger Andersen warned in July that the vessel's deteriorating condition and the over 1 million barrels of oil it holds threaten long-term damage to local ecosystems. In a policy brief published in Frontiers in Marine Science, researchers said the need to pump off the oil is urgent. "A massive leak of over 1 million barrels of oil (4 times the Exxon Valdez tanker spill) is anticipated shortly off the coast of Yemen, in the Red Sea, where the Safer floating storage and offloading unit (FSO) is in the final stages of decay." That quantity, they continued, "guarantees a regional environmental and humanitarian disaster," with impacts certain to affect dozens of coastal countries and the sea's rich biodiversity, including its coral reefs. Given the stakes, the paper called for the U.N. International Maritime Organization and U.N Secretary-General António Guterres to "take coordinated action and achieve access to the Safer by all means necessary in order to pump off the oil." That action must happen before winter, they added, pointing to models showing that "winter oil dispersion will extend further north and into the center of the Red Sea as compared to a spill dispersing during summer." "The time is now to prevent a potential devastation to the region's waters and the livelihoods and health of millions of people living in half a dozen countries along the Red Sea's coast,"
Saudi Arabia Reins In Spending to Contain Deficit – WSJ -Saudi Arabia plans to spend less next year to rein in a pandemic-induced budget deficit, pursuing austerity even as a rally in oil prices signals a higher demand for crude and a global economic recovery. The Saudi government expects to trim its budget deficit from 12% of economic output this year to 4.9% in 2021, as it lowers spending by about 7% to 990 billion Saudi riyals, equivalent to $264 billion, the country’s Finance Ministry said Tuesday. State revenues are forecast to grow nearly 10% to 849 billion riyals on higher taxes and oil revenues. Saudi Arabia’s budget announcement is a closely watched measure of spending in the wider Gulf region and an indicator of Riyadh’s expectations on the direction of oil prices. Crown Prince Mohammed bin Salman is expected to face a tricky economic balancing act next year as the kingdom’s de facto ruler will have to cut spending on some projects related to his plan to diversify the economy yet still try to create jobs for his young population. The crown prince also faces a new administration in Washington that has indicated it would reassess the U.S. relationship with Riyadh, which could hamper already weak investment into the kingdom. Saudi Arabia’s oil infrastructure also has come under increasing attack, threatening its ability to earn revenues. This week, a boat loaded with explosives targeted an oil tanker at the Saudi port city of Jeddah, in the latest strike on the country’s hydrocarbon assets. While crude prices have rallied 30% since the start of last month, the International Monetary Fund predicts Saudi Arabia’s economy will shrink by 5.4% this year, compared with a global contraction of 4.4%. The Saudi government forecasts a return to growth of 3.2% next year. Unemployment among Saudis stands at roughly 15%, according to the latest government statistics.
U.S. energy secretary sees Middle East oil and gas security in pipelines, not tankers— Outgoing U.S. Energy Secretary Dan Brouillette is looking for alternative methods to transport Middle East oil and gas to ensure regional energy security. "Part of the conversation we're having with the Abraham Accords is to look for alternatives to shipping, so that's why these pipelines are so important," Brouillette told CNBC's Hadley Gamble on Wednesday. The energy secretary visited Abu Dhabi this week to meet with ministers from the United Arab Emirates, Bahrain and Israel. Their discussions follow September's signing of the Abraham Accords, which normalized diplomatic relations between Israel and several Arab states. With just over four weeks remaining in the role, Brouillette is making a final lap through the region as the Trump era of strong-arm oil diplomacy comes to an end in the U.S. Brouillette will be replaced by Jennifer Granholm, the former governor of Michigan who, unlike her predecessor, is widely seen as a climate hawk. As Brouillette leaves his post, Gulf leaders are questioning how Joe Biden will engage with the region on issues like Iran. Middle East allies still don't know how the United States, a primary external foreign policy actor in the region, will guarantee security and stability of supply to key markets in Asia and beyond. The Middle East holds over half the world's proven oil reserves, but exporting it through the narrow Strait of Hormuz can often prove difficult. The UAE and Saudi Arabia have long sought to find alternative routes to bypass the Strait, including through pipelines. The Abu Dhabi Crude Oil Pipeline has a capacity of 1.5 million barrels per day and carries the bulk of its production to the UAE port of Fujairah on the Indian Ocean. Saudi Arabia already exports some of its oil using a 745 mile-long pipeline that runs from its key production facilities in the east to the Red Sea port city of Yanbu in the west. A major expansion of its capacity is already underway. Robin Mills, CEO of Qamar Energy told CNBC there is "no perfect solution" for exports. "Tankers can be vulnerable at certain times, so can pipelines. The point is about having options and having a diversity of routes, about having backup. And that's really what Saudi Arabia and the UAE and tried to do with those pipelines," he said. "Pipelines can be vulnerable, but you can also protect them," Brouillette told CNBC on Wednesday. "If we can move natural gas more easily throughout the region, shipping becomes less of a concern. If we can move crude more easily, shipping becomes less of a concern."
Iran fights fire in southwest after oil pipeline spill -Firefighters were working to put out a blaze after a pipeline carrying crude oil to Iran's second-largest refinery ruptured and burst into flames on Sunday, Iranian news agencies reported. "The fire has not been contained but is under control. Its smoke is irritating, but it is not enough to injure anyone, and flames have not reached people's homes," Khosro Kiani, an emergency owicial in southwestern Iran, where the blaze occurred,told the semiowicial news agency Tasnim. 12/14/2020 Iran fights fire in southwest after oil pipeline spill | Deccan Herald https://www.deccanherald.com/international/world-news-politics/iran-fights-fire-in-southwest-after-oil-pipeline-spill-927039.html 4/32 The oil ministry's news agency SHANA said repair teams had shut ow the Maroun pipeline, which feeds the Isfahan refinery, Iran's second-largest with a capacity of about 375,000 barrels per day. Iran's ageing oil infrastructure has been long in need of rehabilitation, as refurbishment plans have been delayed by Western sanctions and local bureaucracy, analysts say. There have been several earlier instances of spillage from the pipeline that have adversely awected the region's agriculture and fishing,the state news agency IRNA reported.
“Zombie Angelina Jolie” Sentenced To 10 Years In Prison For “Promoting Public Corruption” - A young woman from Iran was sentenced to 10 years in prison for posting photos on social media where she looked like a “Zombie Angelina Jolie.” The 19-year-old Instagram star calls herself Sahar Tabar, but her real name is Fatemeh Khishvand. While her pictures online make her appear very strange and unhealthy, her online persona is merely an illusion. She uses a combination of make-up and photoshop techniques to make herself appear the way that she does in her photos. Still, under Iran’s strict social laws, her activities are considered “promoting public corruption.” She says that her page was intended to be a social commentary, but the government thought that she was a danger to society. Last year, she was arrested along with three other female Instagram influencers accused of similar offenses. In court this week, Tabar was sentenced to ten years in prison, which is much longer than the terms that were initially expected.
Investigative Reporting Details Massacres, Reign of Terror by US-Backed Death Squads in Afghanistan - An extraordinary investigation by Australian journalist Andrew Quilty published Friday by The Intercept reveals U.S.-backed Afghan government paramilitary death squads have been waging a campaign of terror targeting civilians—including children—in Wardak province as part of the American military occupation of the nation that began nearly two decades ago.In one December 2018 attack in Omar Khail, Wardak province, men in camouflage—some of them speaking English—took part in a nighttime madrassa raid. Afghan soldiers roused the sleeping boys, ages 9 to 18, before choosing the oldest-looking ones and taking them away. Twelve-year-old student "Bilal"—The Intercept changed his name for his protection—heard gunshots, explosions, and screams. The following morning, when he looked in the school's other rooms and in the basement, he found the bullet-ridden bodies of 12 of his classmates. The perpetrators of the killings are believed to belong to an elite, CIA-trained paramilitary force known as Unit 01 which—in concert with U.S. Special Forces and U.S.-led airstrikes—"unleashed a campaign of terror against civilians," according to Quilty. Unit 01 is nominally under the control of Afghanistan's intelligence service, the National Directorate of Security (NDS). The Omar Khail massacre was but one of at least 10 previously undocumented night raids in Wardak province that, starting December 2018 and continuing for at least a year, killed at least 51 civilians, mostly men and boys—some as young as eight years old. According to The Intercept, few of the victims were members of, or connected to, the Taliban.Residents of four Wardak districts—Nerkh, Chak, Sayedabad, and Daymirdad—described similar massacres, as well as summary executions, mutilations, kidnappings and forced disappearances, attacks on religious and medical facilities, and airstrikes on civilians. Children were often the unfortunate—but sometimes deliberate—victims of these attacks. "The prevalence of boys among those killed in Wardak indicates that Unit 01 was trying to eliminate not only existing enemies, but potential future foes as well," writes Quilty.Such barbarism has incensed local leaders. The Americans, said Wardak provincial council head Akhtar Mohammad Tahiri, "step on all the rules of war, human rights, all the things they said they'd bring to Afghanistan" and are "conducting themselves as terrorists.""They show terror and violence and think they'll bring control this way," he added. Quilty reports that not only do CIA advisers train Afhgan death squad members, they also choose their targets, which they refer to as "jackpots." American aircraft transport the Afghans to and from attacks, and U.S. warplanes are on standby to launch airstrikes, sometimes targeting homes, health clinics, and religious buildings.
No comments:
Post a Comment