oil prices rose for a second straight week on hopes that a new vaccine would end the pandemic and thereby boost demand...after rising 3.6% to $37.14 a barrel last week on falling oil inventories and hopes for a grid-locked government, the contract price of US light sweet crude for December delivery opened higher and quickly jumped 11% on Monday after Pfizer said its vaccine was more than 90% effective in preventing Covid-19, before settling $3.15 higher at $40.29 a barrel, with prices also boosted by a Saudi suggestion that oil producers could adjust their supply-cut pact to take more barrels off the market if demand slumps this winter...optimism over the vaccine carried the rally into a second day on Tuesday, as oil prices rose $1.07 to $41.36 a barrel even as the negative impact that renewed lockdowns in Europe was having on fuel demand and as rising Libyan production kept prices in check...oil prices opened 1% higher on Wednesday after the Tuesday evening API report showed U.S. crude inventories fell more than expected and hung on to close 9 cents higher at $41.45 a barrel as hopes of an effective COVID-19 vaccine continued to bolster sentiment despite European lockdowns...oil prices opend higher again on Thursday, but quickly turned south when equity markets stumbled and settled 33 cents lower at $41.12 a barrel, after the EIA reported a surprise inventory build and the Fed warned that a vaccine might not be enough to get the economy back on track....oil prices continued lower on Friday, pressured by swelling output from Libya and fears that rising coronavirus infections would slow the recovery in fuel demand, and ended down 99 cents at $40.13 a barrel, but still managed to score an 8.1% gain on the week as optimism from the news of a potential Covid-19 vaccine breakthrough had jolted markets earlier in the week...
natural gas prices also ended higher for the fifth time in 6 weeks as a winter weather outbreak in the Northern Plains gradually pushed eastward, portending greater demand for heating...after falling 14% to $2.888 per mmBTU last week as natural gas inventories fell at a record pace and traders digested the election results, the contract price of natural gas for December delivery opened lower on Monday and slid 2.9 cents or 1% as forecasts for milder weather and lower heating demand overshadowed optimism around a potential Covid-19 vaccine....but gas prices rebounded Tuesday as forecasts for colder temperatures in the Mountain West and the Northern Plains countered warmth elsewhere, and natural gas prices ended 9 cents higher at $2.949 per mmBTU, their first increase in 7 days...gas prices rallied for a second day on Wednesday and finished 8.2 cents higher at $3.031 per mmBTU as a blast of snow and cold moved into the Upper Midwest and national forecasts shifted slightly cooler, but they then fell 5.5 cents on Thursday as traders awaited the holiday delayed EIA gas storage report...December gas prices opened lower on Friday, but then jumped ten cents in morning trading before fading to finish with a gain of 1.9 cents at $2.995 per mmBTU, as weather-driven demand expectations and continued strength in exports offset a bearish storage report and left natural gas prices with a 3.7% increase on the week...
the natural gas storage report from the EIA for the week ending November 6th indicated that the quantity of natural gas held in underground storage in the US increased by 8 billion cubic feet to 3,927 billion cubic feet by the end of the week, which left our gas supplies 196 billion cubic feet, or 5.3% more than the 3,731 billion cubic feet that were in storage on November 6th of last year, and 201 billion cubic feet, or 4.7% above the five-year average of 3,751 billion cubic feet of natural gas that have been in storage as of the 6th of November in recent years....the 8 billion cubic feet that were added to US natural gas storage this week contrasted with the average forecast for a 4 billion cubic foot withdrawal from analysts polled by S&P Global Platts, while it was much less than the average of 33 billion cubic feet of natural gas that are typically added to natural gas storage during the same week over the past 5 years, and it was also less than the 12 billion cubic feet that were added to natural gas storage during the corresponding week of 2019...
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending November 6th indicated that because of an increase in our "unaccounted for crude oil", we had a surplus of oil to add to our stored commercial supplies for the 5th time in the past sixteen weeks and for the 26th time in forty-three weeks...our imports of crude oil rose by an average of 470,000 barrels per day to an average of 5,499,000 barrels per day, after falling by an average of 643,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 500,000 barrels per day to an average of 2,765,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,734,000 barrels of per day during the week ending November 6th, 30,000 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 unchanged at 10,500,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 13,234,000 barrels per day during this reporting week...
meanwhile, US oil refineries reported they were processing 13,447,000 barrels of crude per day during the week ending November 6th, 105,000 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 531,000 barrels of oil per day were being added to 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 and from oilfield production was 743,000 barrels per day less than what our oil refineries reported they used during the week plus what was added to storage....to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+743,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a fudge factor that they label in their footnotes as "unaccounted for crude oil", thus suggesting that there must have been an error or errors of that magnitude in the oil supply & demand figures we have just transcribed....moreover, since last week's fudge factor was -877,000 barrels per day, indicating a week over week difference of 1,620,000 barrels per day in the line 13 balance sheet adjustments, the difference between those errors means any week over week comparisons of oil supply and demand figures reported here are complete nonsense...however, since most everyone treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill or complete wells, we'll continue to report them as published, just as they're watched & believed to be accurate by most everyone in the industry, in what is clearly a case where a common delusion has become reality...(for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....
further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 5,327,000 barrels per day last week, which was 12.6% less than the 6,095,000 barrel per day average that we were importing over the same four-week period last year....the 531,000 barrel per day net addition to our total crude inventories included 611,000 barrels per day that were added to our commercially available stocks of crude oil, which was partly offset by the 81,000 barrels per day that was being withdrawn from the oil supplies in our Strategic Petroleum Reserve, space in which is now being leased for commercial use, and hence the recent SPR additions and withdrawals should really be included in our commercial inventories.....this week's crude oil production was reported to be unchanged at 10,500,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at 10,000,000 barrels per day, while a 51,000 barrels per day increase to 518,000 barrels per day in Alaska's oil production still added the same 500,000 more barrels per day to the rounded national total...last year's US crude oil production for the week ending November 8th was rounded to 12,800,000 barrels per day, so this reporting week's rounded oil production figure was 18.0% below that of a year ago, yet still 24.6% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016...
meanwhile, US oil refineries were operating at 74.5% of their capacity while using 13,447,000 barrels of crude per day during the week ending November 6th, down from 75.3% of capacity during the prior week, and excluding the 2005 and 2008 hurricane-related refinery interruptions, one of the lowest refinery utilization rates of the past thirty years...hence, the 13,447,000 barrels per day of oil that were refined this week were 15.5% fewer barrels than the 15,916,000 barrels of crude that were being processed daily during the week ending November 8th of last year, when US refineries were operating at 87.8% of capacity...
even with the decrease in the amount of oil being refined, gasoline output from our refineries was quite a bit higher, increasing by 247,000 barrels per day to 9,319,000 barrels per day during the week ending November 6th, after our refineries' gasoline output had decreased by 23,000 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 8.4% less than the 10,173,000 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 38,000 barrels per day to 4,237,000 barrels per day, after our distillates output had increased by 149,000 barrels per day over the prior week....since it's still near a three year low, our distillates' production was 15.9% less than the 5,039,000 barrels of distillates per day that were being produced during the week ending November 8th, 2019...
even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 14th time in 19 weeks and for the 29th time in 41 weeks, falling by 2,309,000 barrels to 225,356,000 barrels during the week ending November 6th, after our gasoline supplies had increased by 1,541,000 barrels over the prior week...our gasoline supplies decreased this week because the amount of gasoline supplied to US markets increased by 326,000 barrels per day to 8,762,000 barrels per day, and because our imports of gasoline fell by 180,000 barrels per day to 450,000 barrels per day, while our exports of gasoline fell by 6,000 barrels per day to 710,000 barrels per day....but despite the gasoline inventory drawdowns of recent weeks, our gasoline supplies were still 2.9% higher than last November 8th's gasoline inventories of 219,090,000 barrels, and about 3% above the five year average of our gasoline supplies for this time of the year...
meanwhile, with our distillates production remaining well below normal for this time of year, our supplies of distillate fuels decreased for the 8th week in a row, for the 14th time in 32 weeks and for the 31st time in 52 weeks, falling by 5,355,000 barrels to 149,289,000 barrels during the week ending November 6th, after our distillates supplies had decreased by 1,584,000 barrels during the prior week....our distillates supplies fell by more this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 292,000 barrels per day to 4,054,000 barrels per day, and because our imports of distillates fell by 201,000 barrels per day to 131,000 barrels per day, while our exports of distillates rose by 8,000 barrels per day to 1,079,000 barrels per day....but even after this week's inventory decrease, our distillate supplies at the end of the week were still 28.0% above the 116,655,000 barrels of distillates that we had in storage on November 8th, 2019, and about 15% above the five year average of distillates stocks for this time of the year...
finally, for reasons not evident in this week's reported data, our commercial supplies of crude oil in storage (not including commercial oil in the SPR) rose for the 9th time in the past twenty-two weeks and for the 33rd time in the past year, increasing by 4,277,000 barrels, from 484,429,000 barrels on October 30th to 488,706,000 barrels on November 6th...after that increase, our commercial crude oil inventories were still around 6% above the five-year average of crude oil supplies for this time of year, and 42.9% above the prior 5 year (2010 - 2014) average of our crude oil stocks for the first weekend of November, with the disparity between those comparisons arising because it wasn't until early 2015 that our oil inventories first topped 400 million barrels....since our crude oil inventories had generally been rising over the past two years, except for over the recent weeks and during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of November 6th were 8.8% above the 449,001,000 barrels of oil we had in commercial storage on November 8th of 2019, 10.6% more than the 442,057,000 barrels of oil that we had in storage on November 9th of 2018, and 6.5% above the 458,997,000 barrels of oil we had in commercial storage on November 10th of 2017...
OPEC's Monthly Oil Market Report
Wednesday of this past week saw the release of OPEC's November Oil Market Report, which covers OPEC & global oil data for October, and hence it gives us a picture of the global oil supply & demand situation over the third 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, 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 50 of this month's report (pdf page 59), and it shows oil production in thousands of barrels per day for each of the current OPEC members over the recent years, quarters and months, as the column headings indicate...for all their official production measurements, OPEC uses an average of estimates from six "secondary sources", namely the International Energy Agency (IEA), the oil-pricing agencies Platts and Argus, the U.S. Energy Information Administration (EIA), the oil consultancy Cambridge Energy Research Associates (CERA) and the industry newsletter Petroleum Intelligence Weekly, as a means of impartially adjudicating whether their output quotas and production cuts are being met, to thus avert any potential disputes that could arise if each member reported their own figures...
as we can see from the above table of their oil production data, OPEC's oil output was up by 322,000 barrels per day to 24,386,000 barrels per day during October, from their revised September production total of 24,064,000 barrels per day...however that September output figure was originally reported as 24,106,000 barrels per day, which means that OPEC's September production was revised 42,000 barrels per day lower with this report, and hence October's production was, in effect, a rounded 280,000 barrel per day increase from the previously reported OPEC production figure (for your reference, here is the table of the official September OPEC output figures as reported a month ago, before this month's revisions)...
from the above table, we can also see that the Lybian production increase of 299,000 barrels per day was the major reason for OPEC's October output increase, while the increase of 148,000 barrels per day in Iraq's output was mostly offset by decreases of 75,000 barrels per day by the Emirates and 54,000 barrels per day by Angola....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 in August and subsequent months, which is thus the agreement that covers this month's report...however, US sanctioned OPEC members Iran and Venezuela and war-torn Libya were exempt from the cuts imposed by that agreement, and with the recent suspension of Libya's civil war, their production is once again coming back online...
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 and subsequent months, 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 October:
the above table shows the oil production baseline in thousands of barrel per day from which each of the oil producers was to cut from in the first column, a figure which is based on each of the producer's October 2018 output, ie., a date before the past year's and this year's output cuts took effect, 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, September, October and subsequent months 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, allowing them to produce 864,000 barrels per day during October...offhand, by comparing this table's allocation +20% to the initial OPEC production table above, it appears that the Congo, Gabon, and Iraq have slightly exceeded their production quota for October, but none of them 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 November 2018 to October 2020, and it comes from page 51 (pdf page 60) of the October OPEC Monthly Oil Market Report....on this graph, the cerulean blue bars represent OPEC's monthly oil production in millions of barrels per day as shown on the left scale, while the purple graph represents global oil production in millions of barrels per day, with the metrics for global output shown on the right scale....
after the reported 322,000 barrel per day increase in OPEC's production from what they produced a month earlier, OPEC's preliminary estimate indicates that total global oil production increased by a rounded 0.58 million barrels per day to average 91.17 million barrels per day in October, a reported increase which apparently came after September's total global output figure was revised down by 120,000 barrels per day from the 90.71 million barrels per day of global oil output that was reported a month ago, as non-OPEC oil production rose by a rounded 250,000 barrels per day in October after that revision, with oil production increases by Canada, Norway and the UK more than offseting decreases from other non-OPEC producers in October...after that increase in October's global output, the 91.17 million barrels of oil per day that were produced globally in October were 9.25 million barrels per day, or 9.2% less than the revised 100.42 million barrels of oil per day that were being produced globally in October a year ago, the 10th month of OPECs first round of production cuts (see the November 2019 OPEC report (online pdf) for the originally reported October 2019 details)...with this month's increase in OPEC's output, their October oil production of 24,386,000 barrels per day was at 26.7% of what was produced globally during the month, up from their 26.6% share of the global total in August and September....OPEC's October 2019 production, which included 448,000 barrels per day from former OPEC member Ecuador, was reported at 29,650,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 4,816,000, or 16.5% fewer barrels per day of oil this October than what they produced a year ago, when they accounted for 29.8% of global output...
However, even after the increase in OPEC's and global oil output that we've seen in this report, there was a shortfall in the amount of oil being produced globally during the month, as this next table from the OPEC report will show us...
the above table came from page 27 of the September OPEC Monthly Oil Market Report (pdf page 36), 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 October, 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 93.67 million barrels of oil per day, which is a 1,190,000 barrels per day downward revision from the 94,86 million barrels of oil per day they were estimating for the 4th quarter a month ago (note we have encircled 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 91.17 million barrels million barrels per day during October, which would imply that there was a shortage of around 2,500,000 barrels per day in global oil production in October when compared to the demand estimated for the month...
in addition to figuring October's global oil supply shortfall that's evident in this report, the downward revision of 120,000 barrels per day to September global oil output that's implied in this report means that the 280,000 barrels per day global oil output shortage we had previously figured for September would now be revised to a shortage of 440,000 barrels per day....meanwhile, with no revisions impacting previously published July and August figures, the 2,890,000 barrels per day global oil output shortage we had previously figured for July and the 1,570,000 barrels per day global oil output shortage we had previously figured for August would remain unchanged from what we reported a month ago.
However, note that in green we've also circled an upward revision of 20,000 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 upward revision to demand, our previous estimate that there was a surplus of 4,890,000 barrels per day in June would now be revised down to a 4,870,000 barrels per day surplus, the oil surplus of 7,670,000 barrels per day that we had previously figured for May would have to be revised to a surplus of 7,650,000 barrels per day, and the 16,420,000 barrels per day that we had previously figured for April would have to be revised to a surplus of 16,400,000 barrels per day...
Note there was also an upward revision of 30,000 barrels per day to first quarter demand, which we have also encircled in green on the table above...that means that the record global oil surplus of 17,780,000 barrels per day we had previously figured for March would have to be revised to a still record global oil surplus of 17,750,000 barrels per day, that the 1,900,000 barrel per day global oil production surplus we had figured for February would now be a 1,870,000 barrel per day global oil output surplus, and that the 930,000 barrel per day global oil output surplus we last had for January would now be revised to a 900,000 barrel per day oil output surplus.. 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 9th week in a row during the week ending November 13th, but for just the 11th time in the past 35 weeks, and hence it is still down by 60.1% over that thirty-five week period....Baker Hughes reported that the total count of rotary rigs running in the US rose by 12 to 312 rigs this past week, which was still down by 494 rigs from the 806 rigs that were in use as of the November 15th report of 2019, and was also 92 fewer rigs than the all time low prior to this year, and 1,617 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 10 rigs to 236 oil rigs this week, after increasing by 5 oil rigs the prior week, still leaving us with 438 fewer oil rigs than were running a year ago, and less than a sixth of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014....at the same time, the number of drilling rigs targeting natural gas bearing formations increased by 2 to 73 natural gas rigs, which was still down by 56 natural gas rigs from the 129 natural gas rigs that were drilling a year ago, and was also less than a twentieth of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008...in addition to those rigs drilling for oil & gas, three rigs classified as 'miscellaneous' continued to drill this week; one on the big island of Hawaii, one in Sonoma County, California, and one in the Permian basin in Eddy County, New Mexico...a year ago, there were no such "miscellaneous" rigs deployed...
The Gulf of Mexico rig count was up by one to 13 rigs this week, with 12 of those rigs drilling for oil in Louisiana's offshore waters and one drilling for oil offshore from Texas...that was 9 fewer Gulf rigs than the 22 rigs drilling in the Gulf a year ago, when all 22 Gulf rigs were drilling offshore from Louisiana...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, there are now two rigs drilling through an inland bodies of water this week, one in St Mary's county 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 8 to 267 horizontal rigs this week, which was still 435 fewer horizontal rigs than the 702 horizontal rigs that were in use in the US on November 15th of last year, and less than a fifth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014....at the same time, the directional rig count was up by four to 23 directional rigs this week, but those were also down by 31 from the 54 directional rigs that were operating during the same week of last year....on the other hand, the vertical rig count was unchanged at 22 vertical rigs this week, and those were still down by 28 from the 50 vertical rigsthat were in use on November 15th of 2019....
The details on this week's changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes...the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of November 13th, the second column shows the change in the number of working rigs between last week's count (November 6th) and this week's (November 13th) count, the third column shows last week's November 6th 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 15th of November, 2019...
as you can see, rig increases were more widespread than in recent weeks, when activity was more subdued...checking first for the details on the Permian in Texas, we find that five rigs were added in Texas Oil District 8, which roughly corresponds to the core Permian Delaware, while a rig was pulled out of Texas Oil District 8A, which corresponds to the northern Permian Midland...that means that the Texas Permian saw a net four rig increase...since the Permian basin rig count was up by seven rigs nationally, that means that the three rigs that were added in New Mexico must have been added in the farthest west reaches of the Permian Delaware, to account for the national increase...elsewhere in Texas, we find that one rig was added in Texas Oil District 2, and another rig was added in Texas Oil District 4, while a rig was pulled out of Texas Oil District 3, which could be two rigs added in the Eagle Ford while one was pulled out, or one rig added in the Eagle Ford while rigs were added and removed from other unnamed basins..in addition, another rig was added in Texas Oil District 6, which also appears to be targetting an unnamed basin, thus bringing the Texas count up to 6...elsewhere, the rig increase in the Cana Woodford accounts for the Oklahoma addition, while the Louisiana rig increase is the rig that was added in the Gulf of Mexico...for natural gas rigs, we had the rig that was added in the Eagle Ford, and two rigs that were added in the Marcellus in Pennsylvania, while one natural gas rig was removed from Ohio's Utica shale at the same time..
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New Injection Well Planned for Coitsville Site - – A second Class II wastewater injection well is planned for a site along U.S. Route 422 in Coitsville Township, according to records from the Ohio Department of Natural Resources. Bobcat Coitsville LLC has submitted an application to ODNR to drill a new injection well at the existing Northstar Collins #6 facility at 5000 McCartney Rd., ODNR records show. According to a proposed site plan filed with the application, the new well would be drilled 216 feet from McCartney Road and about 100 feet east of where an existing disposal well is located.Class II injection wells are used to store wastewater generated from oil and gas drilling operations in the Utica and Marcellus shale formations in Ohio and Pennsylvania. Bobcat Coitsville is a subsidiary of Bobcat Energy Resources, based in Canfield. Nicholas Paparodis, Bobcat’s director of business development, said that the company is “expanding capacity at the site to meet demand.” ODNR has yet to approve a permit for the new well. Calls to ODNR were not returned. The company acquired the Collins well in Coitsville and another well in North Lima from now-defunct D&L Energy in 2013 after that company declared Chapter 11 bankruptcy. D&L’s owner, the late Ben Lupo, was convicted of violating the U.S. Clean Water Act and was sentenced to a year in prison. Injection wells in the Mahoning Valley have become a source of heated debate since a 4.0 earthquake struck the region on Dec. 31, 2011. The quake and at least seven others earlier that year were tied to an injection well in Youngstown, then operated by D&L Energy. The quakes led to a shutdown of all injection well activity in the vicinity, including the former D&L well in Coitsville and another in Girard. Those opposed to injection wells say they pose a threat to the public and the environment, since they contain toxins used in the hydraulic fracturing, or “fracking,” process.Since then, however, injection well operations have restarted across the Mahoning Valley. Earlier this year, residents of the township became concerned when contaminated wastewater was observed overflowing from two of the holding tanks at the Coitsville site. Inspectors from ODNR determined that one valve malfunctioned while another one broke.
Ohio petrochemical project hits another snag; final announcement delayed to mid-2021 -A decision about whether a Thai-based company will proceed with a massive petrochemical plant in eastern Ohio has been delayed again, raising more doubts about whether the project will proceed.PTT Global Chemical is conducting another feasibility study of the proposed plant in Belmont County, a review that will delay a final decision until at least the middle of 2021, the Bangkok Post reported. The company's decision to review the project makes sense, said Kathy Hipple, a financial analyst with the Institute for Energy Economics and Financial Analysis, a Cleveland-based research group."There's still a lot of petrochemicals on the market. And demand is uncertain, post pandemic. But the broader (issue) is that the type of plastics that they were going to make -- the price has dropped a lot, since they first conceived of this project," she said."It no longer makes economic sense to invest $10 billion in building a petrochemical complex, when the demand for this product is uncertain, the price for the product is very low."The project was announced in 2015, and the company has repeatedly missed deadlines for making a final commitment to the project. Previous delays have been blamed on the pullout of PTT's South Korean partner Daelim, the pandemic, the U.S.-China trade war and opposition from environmental groups. Now the company tells the Bangkok newspaper it must factor in the election of Democrat Joe Biden as president on its revisions.
Ohio Complaint System for Gas Industry 'Impossible' for Public to Use - A three year investigation by the advocacy group Earthworks finds that regulators in Ohio failed to act on more than a third of complaints by residents living near oil and gas development.Earthworks looked into pollution from the oil and gas industry, and how Ohio handled citizen complaints from 2018 – 2020. It concluded that Ohio’s public complaint system is “effectively impossible for the public to use.” “There are a lot of barriers that we encountered in using the complaint system,” said Leann Leiter, one of the report’s authors. “I think would be even harder for the general public to try to squeeze in around the other activities of their lives, without a specialized set of knowledge.” As part of its investigation, Earthworks employed certified thermographers to use optical gas imaging (OGI) at oil and gas wells, natural gas compressor stations, and other industry infrastructure. OGI can make visible the unseen air pollution caused by intentional safety releases, equipment failures, and operator errors in oil and gas fields. In some cases, Earthworks found leaks of methane and volatile organic compounds like benzene. Based on these findings, the group along with residents filed 31 complaints with Ohio’s Environmental Protection Agency (OEPA), Department of Natural Resources (ODNR) and Department of Health. According to the report, the agencies took action to reduce pollution in nine cases (29% of complaints). In three cases (10%), regulators contacted facility operators and conducted inspections, but did not issue any violations. Twelve cases (39%) did not lead to any action by regulators. The results of the remaining seven complaints are unclear, as the cases remain open. The report also found Ohio agencies lack consistent protocols and policies on the handling of public complaints. “Neither OEPA nor ODNR have publicly issued any requirements for inspectors and other staff to respond to complainants in particular ways or within specific timeframes,” according to the report. It sometimes took multiple filings, repeated emails and phone calls to get a response on whether and how a complaint was being addressed. There was a clear “luck of the draw” element to the complaint filing process, with variability across regulatory districts and individual inspectors, according to the report. In a 2019 investigation, The Allegheny Front found similar experiences of people who complained about the oil and gas industry to ODNR. An analysis of complaints to the agency from 2009 through 2018 showed that 2,906 complaints were specifically about the oil and gas industry. A deeper analysis of 2017 data found that of 389 complaints, three-quarters appeared to be unresolved.
Guest Commentary: Getting Real about Natural Gas and Jobs - From the governor’s office on down, we’re told that the natural gas fracking boom can lead to a manufacturing resurgence, particularly in the areas of resins and plastics. And Lord knows it’s needed, since the fracking boom itself has conspicuously failed to deliver on promises of economic recovery and job growth. Together the seven counties that produce over 90% of Ohio’s natural gas – Belmont, Carroll, Guernsey, Harrison, Jefferson, Monroe, and Noble – have seen jobs decline by 9% since the fracking boom began in 2007. Meanwhile, the rest of the state has seen an increase of 2%. So, it’s about time that the industry some called the region’s savior and an economic game-changer started delivering. But, if it does, it probably won’t be in manufacturing. Why not? First, while industry backers claim that the fracking boom has saved manufacturers billions of dollars and made Ohio more competitive, the facts say otherwise. It’s true that since 2008 natural gas prices for industrial users in Ohio have dropped by more than 40%. But, Ohio’s average price was much higher than the nation’s to begin with and it hasn’t dropped as much. As a result, at least 29 other states currently offer manufacturers a lower price for natural gas, making Ohio less, not more competitive. Second, industry economics are working against major petrochemical expansion in the region. That’s why in the more than four years since the Royal Dutch Shell ethane cracker plant in Beaver County, Pennsylvania was announced, not another major project has been greenlighted. In that time, three cracker projects have been cancelled or abandoned, the proposed Appalachian Storage Hub has failed to attract investors, and the only other major project still under consideration – a proposed cracker plant in Belmont County – has lost one principal investor and had its final investment decision postponed three times. Third, even if the Belmont County plant gets built, jobs growth will be minimal. There would be a temporary spike in construction jobs, but permanent employment would only be between 400 and 600 in a region that has lost over 7,000 jobs. And what of the expected downstream jobs in plastics manufacturing? There won’t be many. The American Chemistry Council and the US Department of Energy, both major boosters of Appalachian petrochemical expansion, acknowledge that 90% of Appalachian cracker output would be shipped out of the region for manufacturing elsewhere. And, of the 10% that stays in the region, much of it will replace feedstocks currently sourced from the Gulf Coast. To the degree that happens, local petrochemical output will merely support existing jobs, not create new ones. In short, just as job growth from the fracking boom failed to materialize, the same is likely to be true of a petrochemical buildout, if it ever happens. And we risk repeating the cycle of industry executives and politicians promoting glorious visions of jobs and prosperity in order to win taxpayer dollars and greater freedom to pollute our water and air only to be stuck again with the subsequent reality of few jobs, reduced quality of life, and increased demands on public services.
Pa. gas-producing counties surged for Trump -- Thursday, November 12, 2020 -- President Trump made substantial electoral gains in Pennsylvania counties that produce natural gas, but they were offset by his dismal showing across the Philadelphia suburbs, according to an E&E News analysis.
DEP publishes right-to-appeal notice regarding Leidy South Pipeline permits – Those opposed to the construction of a Natural Gas Pipeline slated to go through Clinton, Columbia, Lycoming, Luzerne, Schuyllkill, and Wyoming county can file an appeal with the Pennsylvania Department of Environmental Protection. On Nov. 7, the Pennsylvania Department of Environmental Protection (DEP) published a notice informing the public of the right to appeal the DEP's issuance of a Section 401 Water Quality Certification and related permits for the Leidy South Natural Gas Pipeline Project. The pipeline is intended to go through Clinton, Columbia, Lycoming, Luzerne, Schuylkill, and Wyoming Counties.The notice states:“Any person aggrieved by this action may file a petition for review pursuant to Section 19(d) of the Federal Natural Gas Act, 15 U.S.C.A. § 717r(d), with the Office of the Clerk, United States Court of Appeals for the Third Circuit, 21400 U.S. Courthouse, 601 Market Street, Philadelphia, PA 19106-1790 as provided by law. This paragraph does not, in and of itself, create a right of appeal beyond that permitted by applicable statutes and decisional law. Important legal rights are at stake, so you should show this document to a lawyer promptly.” To read more information about the permits granted for the Leidy South Pipeline project, refer topages 6,319 through 6,322 of the Pennsylvania Bulletin.
Pennsylvania Department of Environmental Protection orders ETC Northeast Pipeline to keep natural gas out of unstable sections - The Pennsylvania Department of Environmental Protection (DEP) has issued an order to prevent the ETC Northeast Pipeline from placing natural gas in what the department said are "unstable sections" of the Revolution Pipeline throughout Allegheny, Beaver, Butler and Washington counties. According to a press release from DEP, ETC notified the department that it planned to start operations at its Revolution Pipeline on Oct. 20 but ETC allegedly did not specify when natural gas would be placed into the pipeline's network. DEP said it has raised concerns with ETC about placing natural gas into possible unstable sections of the pipeline and added that doing so could impose dangers to people and the environment. DEP said its concerns come following a Sept. 18, 2018 landslide that occurred along the pipeline's path in Center Township, Beaver County. Following the landslide, DEP said a section of the pipeline separated and allowed for methane gas to escape which allegedly resulted in a fire that burned across several acres and destroyed a home and numerous vehicles. As a result, DEP executed a consent order and agreement in Jan. 2020 that assessed a $30.6 million civil penalty against ETC. DEP argues that there are currently "numerous unstable slopes along the pipeline route" and said it is concerned that should another landside occur, the resulting damage could be worse than the incident in 2018. The DEP order will remain in effect until it issues written approval of ETC's stability design of the pipeline and a written determination that "the stability analyses and permanent stabilization plans have been fully implemented."
DEP blocks restart of Revolution pipeline, saying steep slopes still a risk - Pennsylvania environmental regulators are forbidding the operator of the Revolution pipeline that exploded in 2018 from filling the line with natural gas or liquids until the company addresses unstable slopes along its route. ETC Northeast Pipeline LLC told the Pennsylvania Department of Environmental Protection on Oct. 20 and Nov. 3 that it plans to put the pipeline into service soon, but did not specify when gas would begin flowing, DEP said. In response, DEP ordered the company on Wednesday not to fill the pipeline — or to empty it if it has already been filled — until receiving DEP approval of plans to permanently stabilize 26 sites along steep or unsteady slopes, like the one that slipped in Beaver County in 2018 and caused the pipeline to rupture.The explosion destroyed a home, displaced residents, burned several acres and collapsed six high-voltage electric transmission towers, the agency said. “There are currently numerous unstable slopes along the pipeline route,” DEP said in a press release Thursday. Another landslide and rupture “could be worse than the explosion in 2018 because the pipeline’s contents would be more explosive with the addition of natural gas liquids. This would cause a significant pollution event and pose a great danger to human health, safety and the environment.” The 40-mile Revolution pipeline route crosses parts of Butler, Beaver, Allegheny and Washington counties, linking Marcellus and Utica shale wells with a gas processing plant.ETC Northeast Pipeline is a subsidiary of Texas-based Energy Transfer Corp.The company paid a record $30.6 million fine in January and agreed to shore up landslide-prone areas and ensure that the pipeline is secured in bedrock or dense soil along steep slopes.Since then, the company accrued hundreds of new violations as it struggled to keep the unsteady earth in place. In September, it began rerouting the pipeline around the site of the explosion in Center Township. DEP said the company has failed to submit required stability designs demonstrating enhanced safety factors along steep slopes and has “repeatedly stated to DEP that it has no intention of doing so.” The agency identified 26 slopes as unstable and prohibited the company from flowing gas through the line in those sites, which are distributed across nearly all the pipeline’s route.
DEP Prevents Gas Transport in Revolution Pipeline Until It Is Stabilized - The Pennsylvania Department of Environmental Protection ordered a pipeline company not to put volatile substances into unstable sections of the Revolution line, to prevent what the agency says could be a danger to the community and the environment.The DEP says ETC Northeast Pipelines, LLC, a subsidiary of pipeline company Energy Transfer, must stabilize the line before using it to transport natural gas or natural gas liquids.The pipeline company recently told DEP that it intends to put the Revolution Pipeline into service in Butler, Beaver, Allegheny and Washington counties. DEP said the company failed to submit the required stability designs for numerous unstable sectionsthat the state has identified. In 2018, a landslide occurred in Beaver County and a section of the pipeline separated, allowing methane gas to escape. It ignited, and then exploded. The resulting fire burned several acres of forestland, caused evacuation of nearby residents, and destroyed a family’s home. In January 2020, DEP issued a consent order and agreement (COA), and $30.6 million civil penalty against Energy Transfer for violations that led to the incident. DEP said Thursday that Energy Transfer is in violation of the consent agreement requirements for designs “that achieve an adequate factor of safety where [Energy Transfer] constructed the Revolution Pipeline across steep slopes and hillsides.”Now, the company intends to transmit not only natural gas, but potentially more dangerous natural gas liquids, according to DEP spokesperson Lauren Fraley.“The impact of a future landslide and pipeline separation, could be more dangerous, and cause more pollution than the explosion in 2018, because of the addition of natural gas liquids into the pipeline,” Fraley said.The order remains in effect until the agency determines the company has submitted and implemented stabilization plans.“DEP is not telling the full story regarding the stabilization work,” said Energy Transfer spokesperson Alexis Daniel in an email to The Allegheny Front. “Any areas where stabilization work has been approved have been completed or are actively in the stabilization process.” She said DEP has not approved the company’s requests to do additional stabilization work, and that independent analysis found the pipeline is built in stable soil. Daniel disputes the company is in violation of the consent agreement. She said the company looks forward to talking with DEP “instead of exchanging information in a public forum.
Generation share for gas in the US Northeast likely to fall this winter as prices rise — As more winter-like temperatures arrive across the US Northeast, rising cash prices there could begin to pressure market share for gas as power generators switch away from the fuel in favor of coal. In just the past several trading days, spot gas prices have been up sharply in both the Northeast market area and at upstream supply hubs in Appalachia. At Transco Zone 6 New York, the cash market surged more than 40 cents Nov. 11 to $1.90/MMBtu. At the nearby Texas Eastern M3 hub, prices climbed about 30 cents to $1.76/MMBtu. Just several days prior, both locations recorded record-low settlement prices at less than 30 cents/MMBtu. A similar rally in Appalachia also lifted prices from recent record lows around 30 cents/MMBtu. At Dominion South, the cash market climbed about 25 cents on Nov. 11 to $1.63/MMBtu. At Columbia Gas Appalachia the market added nearly 40 cents to trade at $2.12/MMBtu, preliminary settlement data from S&P Global Platts data showed. Over the next week, Northeast cash markets are likely to continue strengthening as colder weather finally arrives in the region. According to an updated forecast from S&P Global Platts Analytics, Northeast temperatures will average nearly 2 degrees Fahrenheit below normal over the next seven days, boosting residential-commercial gas demand by nearly 50% compared to its month-to-date average. As the extended shoulder season comes to an end, forward markets are expecting Northeast gas prices to climb further and trade well-above last winter's averages. With some market-area hubs priced at $4 to $5/MMBtu for January and February, gas could quickly fall out of favor in the PJM Interconnection – an ISO that includes key markets such as New Jersey, Pennsylvania, Maryland and Virginia. Recently, coal-fired generation in PJM has seen incremental gains at the expense of gas. According to Platts Analytics, these gains can be attributed to gas-fired generation outages and more coal-fired generation offering into the market as a price taker. Month-to-date, generation share for coal has climbed to an average 22% this month, compared with 16% and 17%, respectively, in October and September. Over the same period, gas share in the PJM generation stack has fallen to an average 31% – down nearly 9 percentage points compared to October and 10 percentage point compared to September. As gas prices continue rising – particularly at downstream hubs such as Transco Zone 6 New York and Texas Eastern M3 – market share for gas could continue falling as power generators shift increasingly to coal. In November, the $/MWh fuel cost ratio for coal vs. gas has fallen to an average 1.25 in PJM – down from an average 2.75 in September. As that ratio dips below 1, coal generation becomes cheaper than gas, likely making it the preferred fuel among power producers, S&P Global Platts data shows.
Oil spill cleanup continues along Delaware, Maryland Coast - Crews are continuing a cleanup operation from an oil spill that affected a significant stretch of coastline in Delaware and Maryland. The response crews have cleared oily debris and tar balls from the southern side of the Indian River Inlet in Delaware to the Assateague Island State Park in Maryland, the Delaware Department of Natural Resources and Environmental Control said this week. Beaches in Maryland are no longer affected by the spill. The spill was detected Oct. 19 as oil washed ashore at Broadkill Beach in Delaware and was spread by tidal action. Crews have removed an estimated 75 tons of oily sand and debris from coastal areas. We got tons of oily debris and weathered oil off our beaches, but were not done yet, DNREC Secretary Shawn Garvin said. Our experts continue to survey our coastline, assessing the cleanup operation, and as we move ahead, conducting final evaluations of our beaches to make sure the job is done. The source of the spill has not been determined. The oil was described as heavy fuel oil likely leaking from an operating vessel, not crude oil from the hold of a tanker. The U.S. Coast Guard has said oil samples are being analyzed by its Marine Safety Laboratory to try to find what is essentially a petroleum fingerprint that might help determine the source of the spill. The Coast Guard is covering the costs of the cleanup. The agency said that if the source of the spill is identified, the responsible party will be required to reimburse the agency. The beach in Lewes remains closed, officials in Delaware said. Officials are urging people visiting other affected beaches to stay out of the water and not walk along the wrack or high tide line.
Oil spill clean-up along Delaware coast nears completion - Delaware’s beaches are close to getting an “all clear” following last month’s oil spill in the Delaware Bay. The state and U.S. Coast Guard are making a final assessment after weeks of cleanup. Gordon’s Pond, North Shores Beach, Rehoboth Beach and Dewey Beach are the only sites requiring a final sign off before cleanup is considered complete. About 75 tons of oily debris have been removed from sites ranging between Dewey Beach to Assateague Island. The source of the spill is still unknown. The U.S. Coast Guard continues to analyze oil samples. The responsible party would be required to reimburse the federal government for the cleanup. The Delaware Audubon Society has offered a $2,000 reward for information about the source of the spill. The public is encouraged to report any sighting of large tar balls on the shore.
Source of oil spill still unknown as local beaches deemed cleared - With the source of the recent oil spill on the Delaware Bay still a mystery, a collaborative cleanup effort between the U.S. Coast Guard and the state Department of Natural Resources & Environmental Control is nearly complete, officials said earlier this week. The cleanup has been ongoing for about three weeks, since oily debris and tar balls began washing ashore along Delaware Bay beaches and then on Atlantic Ocean beaches in Delaware and Maryland. “Cleanup crews under the unified command have successfully cleared all Delaware Bay beaches and another stretch of Atlantic Ocean coastline of oily debris and tar balls,” DNREC officials stated on Tuesday, Nov. 10. After the latest assessment of shorelines late Tuesday, they said, only Gordon’s Pond at Cape Henlopen State Park, North Shores Beach, Rehoboth Beach and Dewey Beach required final sign-off by authorities overseeing the cleanup. The unified command will continue to survey beaches and dispatch cleanup crews as necessary, they noted. During the cleanup thus far, more than 75,000 tons of oily debris had been removed from area beaches stretching from Broadkill Beach on the Delaware Bay to Ocean City, Md. High-tech efforts used in the investigation into the source of the spill included drones and highly specific testing of the oil sludge and of oil from ships that had been in the area when the oily debris was first seen on Oct. 19. Such testing, which incident chief Lt. Cmdr. Frederick Pugh of the U.S. Coast Guard said was akin to DNA testing, has not produced any matches at this point. One ship was tracked to Corpus Christi, Texas, but oil specimens from that ship were found not to match the oil debris washing up on the Delaware beaches. As crews conduct final assessments, DNREC warned beachgoers to avoid any remaining oily debris deposited along the high tide line, also known as the “wrack line.” The public is being asked to continue reporting sizeable sightings of oiled debris, tar balls or oil-covered wildlife.
ELPC and MiCAN appeal judge decision that excluded climate change impacts in Line 5 permit — The Environmental Law & Policy Center (ELPC) and the Michigan Climate Action Network (MiCAN) today filed an appeal with the Michigan Public Service Commission to allow consideration of greenhouse gas emissions resulting from Enbridge’s Line 5 oil pipeline tunnel during the permit application review. Michigan Administrative Law Judge Dennis Mack recently denied the groups’ request. ELPC and MiCAN intervened in the Enbridge Line 5 tunnel case because the large quantity of oil transported in the pipeline after a new tunnel is constructed for a much longer time than would otherwise be the case and would be a meaningful contributor to global warming. Climate scientists have shown that lawmakers must take swift action to stop the release of carbon to the atmosphere to avoid environmental and human harm. After ELPC and MiCAN were granted intervention, Enbridge argued that the scope of the case must be limited so that the Commission cannot consider greenhouse gas emissions and climate change as among the environmental impacts of the project. ELPC and MiCAN countered that the Michigan Environmental Protection Act does not limit the types of environmental impacts considered in administrative hearings about projects like Line 5, and that it certainly makes no sense to ignore climate change, which scientists say is the single greatest threat to our environment today and will continue to be so for decades to come. As scientists have come to a better understanding of the current and potential damage of global warming, CO2 contribution from oil pipelines is being considered in a handful of permit cases around the country.
Whitmer moves to shut down Enbridge's Line 5 — Gov. Gretchen Whitmer is moving to shut down Line 5 by revoking and ending a 1953 easement that allows Enbridge Energy to run the dual pipeline through the Straits of Mackinac. The announcement was welcomed Friday by environmental groups as protecting the Great Lakes and attacked by neighboring Ohio's governor and energy groups as costing jobs and raising fuel and heating prices for consumers. The Democratic governor said Friday she has filed a lawsuit seeking validation of the action in Ingham County Circuit Court. Enbridge must shut down the pipeline by May under the notice. The pipeline presents an "unreasonable risk" to the Great Lakes in violation of the public trust doctrine, Whitmer said in a statement with the Michigan Department of Natural Resources. "Moreover, the state is terminating the easement based on Enbridge’s persistent and incurable violations of the easement’s terms and conditions," the press release said. Enbridge is reviewing the notice it received Friday afternoon and said there is no "credible basis" for revoking the easement. In reviewing the easement, the DNR operated in a "non-public manner" and rejected Enbridge's offer to discuss questions with the company's technical experts, the company said. The conduct goes against the 2018 agreement between the state and oil company, Enbridge said, citing the pact with the administration of Republican former Gov. Rick Snyder. “This notice and the report from Michigan Department of Natural Resources are a distraction from the fundamental facts,” said Vern Yu, executive vice president and president of liquid pipelines for Enbridge. “Line 5 remains safe, as envisioned by the 1953 Easement, and as recently validated by our federal safety regulator." Ohio Gov. Mike DeWine's office said the Republican governor's position on the closure of Line 5 remains unchanged from what was expressed in a July 2019 letter to Whitmer, in which he said the closure would cost more than 1,000 union jobs, create potential fuel cost spikes and lead to airline schedule disruption. Ohio's two refineries near the Michigan border supply fuel to Ohio and southeast Michigan, including the Detroit Metro Airport, DeWine said in the letter. "We ask that you please consider options to improve the safety of Line 5 that does not result in taking the pipeline offline," he wrote.
Federal court grants stay of Mountain Valley Pipeline waterbody construction - The Mountain Valley Pipeline’s legal limbo continued Monday as a panel of federal judges granted a stay of construction of the pipeline across about 1,000 waterbodies in West Virginia and Virginia. The 4th U.S. Circuit Court of Appeals granted the stay following oral arguments as it considered whether to grant a previous request by conservation groups for a longer stay barring construction of the pipeline across streams in West Virginia and Virginia. The court had granted a temporary administrative stay on Oct. 16, and its Monday stay, via a brief order without explanation, will remain in effect until it decides whether to overturn water permitting from the U.S. Army Corps of Engineers for the project. Environmental groups, including the Sierra Club, the West Virginia Rivers Coalition and the West Virginia Highlands Conservancy, challenged the corps’ September reissuance of Nationwide Permit 12 approval. The 4th Circuit had, in 2018, vacated the Nationwide Permit No. 12 issued by the Huntington District of the corps the previous year. During Monday’s oral arguments, the court questioned whether it had the authority to consider aspects of the case concerning the pipeline, which is designed to be a 303-mile natural gas pipeline system traveling from Northwestern West Virginia to Southern Virginia crossing Wetzel, Harrison, Doddridge, Lewis, Braxton, Webster, Nicholas, Greenbrier, Fayette, Summers and Monroe counties in the Mountain State. Derek Teaney of Appalachian Mountain Advocates, counsel for the environmental groups petitioning for a stay, argued that the court does have jurisdiction and that the Nationwide Permit 12 required to cross streams as reissued by the Corps of Engineers is unlawful. Under Nationwide Permit No. 12, projects do not need separate permits for individual waterbodies. “It’s right to press pause to allow the court to fully review water-crossing permits impacting over 1,000 streams and wetlands,” said Angie Rosser, executive director of the West Virginia Rivers Coalition. “Concerns raised about the legality of permits, coupled with MVP’s poor track record, warrant taking time to make sure mistakes aren’t made that will be regretted later.”
Fourth Circuit Stays MVP's New Stream-Crossing Permits Pending Appeal in Latest Setback The oft-delayed and increasingly costly Mountain Valley Pipeline LLC (MVP) has encountered another legal setback, as the natural gas conduit’s stream-crossing permitting has again been put on hold pending an ongoing review by the U.S. Court of Appeals for the Fourth Circuit. The Fourth Circuit issued a stay Monday after hearing oral arguments in a case filed by environmental groups challenging the Nationwide Permit 12(NWP 12) approvals issued to the embattled pipeline by the U.S. Army Corps of Engineers. The Army Corps recently renewed the project’s NWP 12 authority, which had been on hold following an unfavorable 2018 ruling from the Fourth Circuit. Environmental groups, led by the Sierra Club, wasted little time in asking the circuit court to rule against the new permits.The Fourth Circuit, which has ruled against MVP and the now-canceled Atlantic Coast Pipeline on multiple occasions in recent years, offered little in the way of explanation for its decision in Monday’s order, stating only that “an opinion as to the court’s reasoning will follow at a later date.”Breaking down the back and forth during oral arguments Monday, analysts at ClearView Energy Partners LLC observed that the judges presiding over the case “appeared to poke holes in the arguments offered by both sides.”Hearing the arguments were Chief Judge Roger L. Gregory, nominated by President Clinton, and Judges James A. Wynn Jr. and Stephanie D. Thacker, both nominees of President Obama. “The court has now converted the current administrative stay to a conventional stay pending the conclusion of their review of Sierra Club’s appeal,” the ClearView analysts said. “With the stay now extended for the duration of the appeal, the waterbody crossing work dependent on this permit may not take place until the court rules on the underlying appeal.“Therefore, in order to resume work in 2021 and meet its recently revised guidance to be in service in the second half of 2021, the Corps and MVP would need to prevail” in the case.MVP’s developers are “disappointed” with the Fourth Circuit’s latest decision, according to spokesperson Natalie Cox for project sponsor Equitrans Midstream Corp. (EQM).“We are hopeful and expect that once the case is reviewed on the merits of the arguments there will be a different conclusion,” Cox told NGI. “Although the Nationwide Permit 12 is certainly important to MVP, the crews are continuing with all other aspects of the project — including forward construction work in various upland areas along the route, as authorized and permitted.“In addition, the project team is continuing its activities to maintain and enhance erosion and sedimentation controls and complete final restoration work along portions of the right-of-way, which is the most protective measure for the environment.”Since receiving a certificate of convenience and necessity from FERC in 2017, MVP has faced numerous challenges in its efforts to construct the 300-mile, 2 million Dth/d interstate pipeline, designed to transport Marcellus and Utica shale natural gas from West Virginia to an interconnect with the Transcontinental Gas Pipe Line in southwestern Virginia.MVP only recently received authorization to resume construction after a prolonged delay amid challenges to multiple federal permits
Mountain Valley Pipeline faces another legal roadblock. What does that mean for the long-embattled project? - Yes, Mountain Valley Pipeline is still kicking. Although some activists were confident in the wake of the July cancellation of the Atlantic Coast Pipeline that Mountain Valley would soon follow suit, the project keeps plugging along even as costs rise, its timeline is extended and the courts continue to cast a skeptical eye on permits issued by federal agencies. Given the intricacies of pipeline development and the legal challenges that surround it, you could be forgiven for only having a fuzzy understanding of where the project stands. Nearly every aspect of the pipeline remains in dispute, from the public’s need for it (Mountain Valley says the Southeast faces a natural gas shortage, while opponents point toan oversupply of the resource within the region) to how much of the project is completed (Mountain Valley says 92 percent, while opponents say the estimate should be just over 50 percent and federal regulators have calculated only 84 percent has been installed). After a year’s pause in pipeline construction, though, work is cranking up again, and both sides are preparing to begin their fight anew. Here’s some key things to know about where Mountain Valley stands and where it may be headed. In October 2019, the Federal Energy Regulatory Commission ordered that all construction on Mountain Valley except restoration and stabilization activities “cease immediately” after the 4th Circuit Court of Appeals found flaws in the project’s required U.S. Fish and Wildlife Service permit.This October, in the wake of a new authorization from Fish and Wildlife, FERC on a 2-1 vote lifted the stop-work order, contending that “completion of construction and final restoration … is best for the environment and affected landowners.” Opponents have already mounted a legal challenge.Not included in the ruling? A 25-mile stretch of the pipeline route known as the “exclusion zone” that crosses through Virginia’s Jefferson National Forest. Approval to cross these lands is required from the U.S. Forest Service, but a prior authorization was struck down in 2018. A new environmental study from the Forest Service has been working through the review process and faces significant opposition.On Monday the Richmond-based 4th Circuit issued a ruling that effectively bars Mountain Valley from continuing any construction related to its crossing of hundreds of streams, rivers and wetlands in Virginia and West Virginia until a broader case about the validity of its water-crossing permit is settled. Project opponents — which include the Sierra Club, Appalachian Voices and Chesapeake Climate Action Network, among others — had argued that “irreparable harm” to the environment would result if stream-crossing work wasn’t halted before the resolution of the larger case. In August, Diana Charletta, president and chief operating officer of Mountain Valley developer Equitrans Midstream, told analysts on an earnings call that the company intended to try to cross “critical” streams “as quickly as possible before anything is challenged.” MVP attorney George Sibley told the 4th Circuit that the developer’s haste is in recognition “that our opponents are implacable.” “We have the authorizations,” he said Monday. “We are not going to wait to get sued and wait for those lawsuits to be resolved.”
Forest fracas: Activists and lawyers continue pipeline fight in western Virginia - In July, the 600-mile Atlantic Coast Pipeline was canceled, sending shock waves through the energy industry and sparking jubilant celebrations from activists who had spent years fighting the project. There’s no rest for the weary, though. Further west, a little deeper into the Appalachian hills, another fight rages on. The Mountain Valley Pipeline, if completed, would pull natural gas from the prehistoric Marcellus Shale deposits underneath West Virginia and carry the fuel 300 miles to southern Virginia. After six years of opposition from grassroots groups and professional environmental advocacy organizations, the fight over the MVP is entering a definitive stretch. On October 9, a long-standing stop-work order for the pipeline was lifted, allowing construction to resume along most of the pipeline’s length. Then, on November 9, federal judges once again halted work to allow for further examination of a key stream-crossing permit. The pipeline’s opponents say the regulatory agencies charged with making sure construction unfolds lawfully have been asleep at the wheel. They’re making their case in both the forest and the courtroom. EQT, the energy corporation spearheading the project, says the MVP is 92 percent complete. Activists who oppose the project say that’s an overstatement, and that the real figure is closer to 78 percent. Either way, “it’s over $3 billion over budget and three years behind schedule,” says Joan Walker, senior campaign representative for the Sierra Club’s Beyond Dirty Fuels Campaign. “And that’s an optimistic outlook.” “It’s been a long, long opposition,” says Kirk Bowers, co-founder of the Mountain Valley Watch, a volunteer pipeline oversight organization. The group monitors pipeline construction and submits reports of violations to the various state and federal agencies that are supposed to be overseeing the project, hoping the agencies will then slap the project with sanctions. This monitoring plays an important role in the ongoing pipeline legal debates. “Over 350 instances have been charged,” says Walker. “There have been many more water quality violations, permit violations that have been found by volunteers in the field, like Kirk Bowers and Mountain Valley Watch, that didn’t result in formal charges.” These activists, years into this conflict and staring down a huge corporation, still have energy to spare.
Judge orders tree-sitters down after more than 2 years — After spending two years, two months and seven days in the trees — where they have maintained an aerial blockade of the Mountain Valley Pipeline — protesters were told Thursday that they have four more days. A temporary injunction issued by Montgomery County Circuit Judge Robert Turk ordered the three unidentified tree-sitters and 10 of their supporters to be gone by Monday. While Mountain Valley has a legal right to a 125-foot-wide easement on which the natural gas pipeline will be built off Yellow Finch Lane, it has been unable to cut trees out of fear that it will harm the protesters in and around them. If the defendants do not leave the property that has been occupied since Sept. 5, 2018, by Monday, “the Sheriff’s Office shall thereupon take such measures as are necessary to remove them,” the order entered by Turk reads. Left unsaid in the order and during a two-hour hearing that preceded it was how the protesters might be extracted from tree stands about 50 feet off the ground on a steep, wooded slope near Elliston. In the past, more short-lived standoffs have been ended by state police, who used a hydraulic crane topped with a railed platform to reach and remove opponents chained to excavators and other high perches along the pipeline right of way. But the difficult terrain — not to mention the feisty determination of a group of mostly anonymous activists — could make the job at Yellow Finch more challenging. There was no legal battle Thursday; the defendants did not show up for their court hearing and did not have lawyers to represent them. They have not been reluctant to tangle with Mountain Valley employees, though, and signs posted at the tree-sits declare “We’re here to stay” and “Doom to the Pipeline.” Mountain Valley spokeswoman Natalie Cox said the company expects the opponents to follow Turk’s order. If not, she wrote in an email, “we will work with law enforcement to identify appropriate steps for ensuring the unlawful activity does not continue.” The 303-mile pipeline being built through West Virginia and Southwest Virginia has drawn fierce opposition from those who say it is scarring the landscape, polluting streams and contributing to climate change by advancing a fossil fuel over renewable energy. For the most part, Mountain Valley does not know the names of the protesters who take turns living on wooden platforms that went up two years ago in a white pine and a chestnut oak. A third tree-sit was erected in March.
US natural gas futures fall on lower demand - Markets - US natural gas futures slipped 1% on Monday as forecasts for milder weather and lower heating demand overshadowed optimism around a potential COVID-19 vaccine. Front-month gas futures fell 2.9 cents, or 1%, to settle at $2.859 per million British thermal units. The contract touched its lowest since Oct. 20 at $2.821 earlier in the session. "Prices are easing from early session short-covering as mid-day weather models are running and they continue to forecast a warmer than normal short-term pattern, which is not supportive given current supply and storage levels," said Robert DiDona of Energy Ventures Analysis. "For prices to recover, we need to see a colder weather pattern shift for late November," he added. Data provider Refinitiv estimated 216 heating degree days (HDDs) over the next two weeks in the lower 48 US states, well below the 30-year average of 278. Refinitiv predicted demand, including exports, would fall to an average of 91.6 billion cubic feet per day (bcfd) this week from 98.1 bcfd in the prior week. Gas production in the Lower 48 US states has averaged 88.8 billion cubic feet per day so far in November, up from a five-month low of 87.4 bcfd in October. Earlier in the day, Pfizer Inc announced its experimental vaccine was more than 90% effective in preventing COVID-19 based on initial data from a large study, boosting market sentiment among investors. Meanwhile, the amount of gas flowing to US LNG export plants hit a record 10.2 bcfd last week and was expected to remain near that level in coming weeks after a rise in global prices in recent months prompted buyers in Europe and Asia to purchase more US gas. In the spot market, mild weather this week cut next-day gas prices at the Dominion South hub in southwest Pennsylvania and Transco Z6 in New York to their lowest since October 2017 and September 2016, respectively.
Natural Gas Futures Rebound as Weather Forecasts Stabilize, Spot Prices Mount, and Pandemic’s Potential End in Sight - Regional heating demand is expected to heighten along with colder temperatures in the Mountain West and snow over the Northern Plains this week, helping to counter warmth elsewhere across the Lower 48 and fueling a long-awaited rally on Tuesday in natural gas futures. Over the prior six trading sessions, the prompt month shed nearly 50 cents.The December Nymex contract settled at $2.949/MMBtu on Tuesday, up 9.0 cents day/day. January climbed 7.4 cents to $3.073. NGI’s Spot Gas National Avg. advanced along with the blasts of cold, rising 19.5 cents to $2.450. “Weather systems with rain and snow will sweep across the West and Northern Plains with chilly highs of 20s to 50s for locally stronger demand,” NatGasWeather said. The system took hold Tuesday and was expected to linger for much of the week “for minor bumps in national demand.” Between Monday and Tuesday, weather models added a few heating degree days (HDD) because of the trending systems, the forecaster said. That noted, domestic heating demand could soon fade. The weather outlook “remains solidly bearish” in other parts of the country and overall for November. “Warmer-than-normal conditions continue across the southern and eastern” United States, “with highs of 60s to low 70s for the Great Lakes and Northeast and perfect 70s and 80s across” the South. Starting early next week and extending through Nov. 24, “warm high pressure dominates much of the U.S.,” NatGasWeather added. Lower 48 production levels that were down moderately from last week along with strong liquefied natural gas (LNG) levels, meanwhile, added to the optimism. LNG feed gas levels hovered above 10 Bcf – around record levels – as they have for several days, indicating steady export demand from key destinations in Asia and Europe. While the coronavirus looms large as a potential threat to export demands, news this week of a potential vaccine getting approved this year soothed concerns about strict and lasting lockdowns across Europe and potentially parts of Asia that could stunt economies and energy demand.
December Natural Gas Futures Rally for Second Consecutive Day as Cooler Forecasts Hold - Slightly improved weather-driven demand and rising spot prices fueled a second-straight day of gains for natural gas futures. The December Nymex contract gained 8.2 cents day/day and settled at $3.031/MMBtu on Wednesday. January advanced 7.8 cents to $3.151. NGI’s Spot Gas National Avg. climbed 13.5 cents to $2.585, a third consecutive day of gains. Wednesday’s prompt month momentum built atop an increase of 9.0 cents the previous day after a blast of snow and cold moved into the Upper Midwest, and forecasts for the next few days shifted slightly cooler. Overall, expectations increased for modest national demand improvement this week. For the second day in row, Bespoke Weather Services projected demand gains, with a few days toward the front half of the 15-day outlook moving closer to normal in terms of temperatures. This is the result of “a couple of upper level troughs swinging through the eastern third of the nation,” the forecaster said. Bespoke, however, expects continued risks for more warmth late this month and into December, increasing the odds of price declines in coming sessions. “The bearish weather remains the major obstacle for bulls, and we expect that to continue,” the forecaster said. “As it stands right now, we do not have a single day in the forecast that is colder than normal.” Unseasonably warm conditions last week sparked a six-day slump for December futures that continued through trading Monday this week. In all, the prompt month shed nearly 50 cents over that span, amplifying the importance of weather. In its latest Short-Term Energy Outlook (STEO) published Tuesday, the U.S. Energy Information Administration (EIA) estimated exports averaged 7.2 Bcf/d in October, up 2.3 Bcf/d from September volumes. That marked the largest month/month increase on record.EIA said it expects U.S. LNG exports to average 8.5 Bcf/d in November, above pre-pandemic levels, and remain robust into next year. The agency predicted export volumes would average 8.4 Bcf/d in 2021, a 31% year/year increase. LNG feed gas volumes hovered above 10 Bcf at the start of trading Wednesday.
US working natural gas volumes in underground storage increase by 8 Bcf: EIA | S&P Global Platts— While the bulk of the market expected a second, consecutive, weekly withdrawal to US working gas in storage for the first week in November, a net injection was reported instead, while one more build is likely before the seasonal switch to draws due to low heating demand. US natural gas storage inventories increased by 8 Bcf to 3.927 Tcf for the week ended Nov. 13, Energy Information Administration data showed. The report was issued one day later than usual due to the Veteran's Day holiday. The injection stood in contrast to an S&P Global Platts survey of analysts calling for a 4 Bcf withdrawal. Responses to the survey ranged for a draw of 12 Bcf to a 6 Bcf injection. The build was still less than the 12 Bcf build reported during the same week last year as well as the five-year average gain of 33 Bcf, according to EIA data. The week saw temperatures in the middling zone between heating and cooling, resulting in a 4.3 Bcf/d decline in gas-fired power generation without significant residential and commercial demand gains in return, according to S&P Global Platts Analytics. LNG feedgas deliveries continued to climb in the wake of a busy hurricane season, gaining 1 Bcf/d. Northeast production ramped up to record highs for the reference week, pushing up US supplies by 1.5 Bcf/d, and further weighing on prices at Henry Hub. Storage volumes now stand 196 Bcf, or 5.3%, more than the year-ago level of 3.731 Tcf and 176 Bcf, or 4.7%, more than the five-year average of 3.751 Tcf. The NYMEX Henry Hub December contract added 4.7 cents to $3.023/MMBtu in trading following the release of the weekly storage report at 10:30 am ET. The remaining winter strip, January through March, gained 4.6 cents to $3.086/MMBtu. However, the gains shifted to minor losses by the afternoon, with the prompt month dipping 3 cents from the day prior's settlement while the remaining winter strip shed 1 cent. S&P Global Platts Analytics' supply and demand model currently forecasts a 19 Bcf injection for the week-ending Nov. 13. A sudden shift to warmer than normal temperatures loosened US fundamentals week over week, resulting in an 8 Bcf/d decline in residential and commercial demand. Dry gas production also declined by 1.8 Bcf/d, partially offsetting the bearishness of the demand losses. The week-ending Nov. 20 looks to finally mark the switch to the winter withdrawal season, but early forecasts show below-average draws for the remainder of the month.December Natural Gas Futures Finish in Green Despite Storage Injection - Further gradual improvement in weather-driven demand expectations and continued strength in export levels offset a bearish storage report and boosted natural gas futures on Friday. The December Nymex contract gained 1.9 cents day/day and settled at $2.995/MMBtu. It had climbed as much as 10 cents higher in morning trading. January rose 2.8 cents to $3.122. NGI’s Spot Gas National Avg. dipped 6.5 cents to $2.600 after posting gains each of the four previous days. The U.S. Energy Information Administration (EIA) reported an injection of 8 Bcf into storage for the week ending Nov. 6. The result was shy of market expectations and notably bearish compared to a week earlier, when EIA reported a withdrawal of 36 Bcf that marked the first pull of the season. It also was well off the median of major polls. Reuters and Bloomberg surveys both landed at an estimate of a 3 Bcf decrease in storage. A Wall Street Journal survey found an average call for a decrease of 2 Bcf. NGI forecast a 5 Bcf increase. The increase for the latest covered week lifted inventories to 3,927 Bcf, up from 3,731 Bcf a year earlier and ahead of the five-year average of 3,751 Bcf. The plump storage levels and resumption of injections did not subdue markets, however, as the prompt month recorded its third daily gain of the week. While there were indications that colder momentum could ebb, Bespoke Weather Services said its forecast for gas-weighted degree days (GWDD) showed further gradual gains on Friday – the fourth consecutive day of increases and a vital driver of futures to culminate the week. Bespoke and other forecasters, however, said after mid-November, temperatures are likely to shift from cool to relatively warm for that time of year, with highs of 60s to 80s over much of the country outside of the far north. “We feel the colder changes the last few days, while significant, will turn out to be just a window of variability in the midst of a warm base state, and that we will move more decisively in the warmer direction at the end of the month and into early December,” Bespoke said.
Weekly Natural Gas Prices Mount Comeback on Northern Cold Blast - Natural Gas Intelligence - Weekly cash prices rebounded from the nosedive of a week earlier, lifted by a round of winter weather in the Northern Plains that gradually pushed eastward and galvanized heating demand over swaths of the Lower 48. NGI’s Weekly Spot Gas National Avg. for the Nov. 9-13 period climbed 12.5 cents to $2.510. The week before, when mild temperatures blanketed the country and sapped demand, weekly prices dropped 61.5 cents on average. For all the potential drivers of gas prices, the see-saw action so far in November amplified the outsized significance of weather as much of the country steadily moves into winter. As the trading week closed, El Paso Permian was up 43.5 cents week/week to $2.475, while Dominion North was ahead 54.5 cents to $1.165, andDefiance was up 17.0 cents to $2.485. Forecasters said volatility may continue to pervade cash markets the rest of this month, as weather outlooks hover between cold and mild over big sections of the country, and overall production, while still low compared to a year earlier, has mostly held steady this month. Bespoke Weather Services said chilly conditions are expected to hang around the Midwest and into parts of the East beyond mid-month, but the potential for comfortable temperatures – and threats to demand – look likely later in November. “We remain concerned that the warm look ultimately wins out late month into at least early December and that [recent] colder changes will just amount to some variability mixing into the warm state,” the forecaster said. “If so, price risks would be skewed to the downside.” Greater economic activity and mounting energy use could boost industrial demand and offset lighter weather-driven demand. However, despite news earlier this month of a vaccine potentially winning approval yet this year, the coronavirus pandemic in the near term is surging and threatening to stunt economic activity and, by extension, energy needs. The United States averaged more than 100,000 new cases each day during the covered week, according to Johns Hopkins University data. “We expect near-term volatility surrounding vaccine development and the Covid-19 outbreak to remain,” said Raymond James Chief Investment Officer Larry Adam. “While the vaccine development is a positive signal, it cannot remedy the current surge or the risk of the outbreak worsening as we head into the winter months.”
An oil and gas industry consultant reportedly created a fake persona of 'an imaginary, middle-aged Texas woman with a dog' to monitor environmental activists online - A consulting firm hired by the oil and gas industry created a fake persona of "an imaginary, middle-aged Texas woman with a dog" to monitor environmental activists online, according to a report from The New York Times.The global firm, FTI Consulting, was hired by oil and gas companies to help promote fossil fuels, Times climate reporter Hiroko Tabuchi said.A group within the firm was reportedly hired by Apache Energy, a company that was interested in drilling near a Texas state park. Two sources told Tabuchi that the company was worried people would show up to protest like in the case of the Dakota Access Pipeline protests in 2016, when thousands of people descended upon North Dakota to resist the pipeline.As a result, an online persona was created to keep an eye on organizers, former FTI employees told Tabuchi. That Facebook profile was "of a Texas woman named Susan McDonald who likes ice cream, the movie "Annie" and her local farmers' market," The Times reported.A spokesman from FTI, Matthew Bashalany, told The Times, "A Facebook profile was created by a former employee to monitor social media anonymously. This was wrong, and it is against our policy."The discovery of the false profile came out of a larger investigation into the firm, which Tabuchi said created multiple websites and organizations run by its own staff that appeared to be grass-roots endeavors in favor of fossil fuels. In reality, the efforts were funded by big oil and gas companies.In one instance, a pro-fracking website called "Texans for Natural Gas" encouraged people to "thank a roughneck," The Times reported. In another, the "Main Street Investors Coalition" promoted claims that climate activism doesn't help small-time investors in the stock market.Tabuchi reported that oil companies hired FTI to push back against the growing criticism surrounding fossil fuels as a result of climate change and to help shift public perception towards a positive view of oil. The price of oil dropped to historic lows in the spring after the industry was hit hard by the coronavirus pandemic. Meanwhile, President-elect Joe Biden is expected to up the country's efforts in the fight against climate change, though it's not yet clear what impact his presidency will have on the energy industry.
How One Firm Drove Influence Campaigns Nationwide for Big Oil - New York Times - FTI, a global consulting firm, helped design, staff and run organizations and websites funded by energy companies that can appear to represent grass-roots support for fossil-fuel initiatives. In early 2017, the Texans for Natural Gas website went live to urge voters to “thank a roughneck” and support fracking. Around the same time, the Arctic Energy Center ramped up its advocacy for drilling in Alaskan waters and in a vast Arctic wildlife refuge. The next year, the Main Street Investors Coalition warned that climate activism doesn’t help mom-and-pop investors in the stock market. All three appeared to be separate efforts to amplify local voices or speak up for regular people. On closer look, however, the groups had something in common: They were part of a network of corporate influence campaigns designed, staffed and at times run by FTI Consulting, which had been hired by some of the largest oil and gas companies in the world to help them promote fossil fuels. An examination of FTI’s work provides an anatomy of the oil industry’s efforts to influence public opinion in the face of increasing political pressure over climate change, an issue likely to grow in prominence, given President-elect Joseph R. Biden Jr.’s pledge to pursue bolder climate regulations. The campaigns often obscure the industry’s role, portraying pro-petroleum groups as grass-roots movements. As part of its services to the industry, FTI monitored environmental activists online, and in one instance an employee created a fake Facebook persona — an imaginary, middle-aged Texas woman with a dog — to help keep tabs on protesters. Former FTI employees say they studied other online influence campaigns and compiled strategies for affecting public discourse. They helped run a campaign that sought a securities rule change, described as protecting the interests of mom-and-pop investors, that aimed to protect oil and gas companies from shareholder pressure to address climate and other concerns. FTI employees also staffed two news and information sites, Energy In Depth and Western Wire, writing pro-industry articles on fracking, climate lawsuits and other hot-button issues. Former employees familiar with Energy In Depth said the site’s content had direction from Exxon Mobil, one of the major clients of the FTI division that worked on these oil and gas campaigns. The Energy In Depth website notes its affiliation with an energy trade group that Exxon is a member of, though not Exxon’s role in directing content that the site published. This article is based on interviews with a dozen former FTI employees, including former managing directors, a review of hundreds of internal FTI documents and an examination of the digital trail of domain-name registrations and other details left by the creation of the websites. In all, FTI has been involved in the operations of at least 15 current and past influence campaigns promoting fossil-fuel interests in addition to its direct work for oil and gas clients. Matthew Bashalany, an FTI spokesman, disputed the idea that FTI worked behind the scenes for these groups. “We hide behind no one,” he said. “We summarily reject as false, misleading and defamatory the general narrative and specific claims,” he said. “We hold ourselves to the highest professional and ethical standards of conduct; when and where shortfalls are identified in this regard, they are addressed appropriately.” An Exxon spokesman, Casey Norton, said he would not comment on the findings because he considered the reporter to be biased against the fossil fuel industry. Kathleen Sgamma, a spokeswoman for the Western Energy Alliance, which funds Western Wire, said her group had been open about its partnership with FTI and about its approach to fracking. The business of corporate consulting and public relations is vast, and countless companies routinely provide media outreach, public messaging, crisis management and other services. FTI is among them, and it has taken up an important role in helping promote the messages of the fossil fuel industry.
Krotz Springs refinery lays off workers; looks to break even after millions in maintenance work -- An oil refinery in St. Landry Parish laid off an undisclosed number of workers last week as it looks for ways to turn a profit and still plans to invest millions in maintenance work at the plant. The Krotz Springs oil refinery, owned by Tennessee-based Delek U.S. and built in 1976, had about 210 workers before the coronavirus pandemic caused lockdowns eight months ago that sapped demand for fuel for travel and work commutes. It was also not clear Monday how many workers the company still has in Louisiana. Delek officials told investors last week the company planned to lay off 8% of its workforce to save money. That would mean trimming roughly 300 workers of its 3,800 employees company-wide. About 1,300 worked in refining as of December 2019. Delek has refineries of similar size to Krotz Springs in Tyler, Texas; Big Spring, Texas; and El Dorado, Arkansas. The Krotz Springs refinery, acquired by Delek U.S. in 2017 from Alon Refining, has the capacity to process 80,000 barrels of crude oil each day. It was not clear how much production has been cut since the economic recession began. If the 8% staff reduction is evenly distributed, it would mean 16 employees lost their jobs in Krotz Springs. However, the company told investors it plans to idle unprofitable units at Krotz Springs that account for the majority of its products processed there. The profit margin for gasoline has diminished since the coronavirus pandemic and prompted other refineries across the country to idle some operations or even shutter. The Krotz Springs refinery also produces jet fuel, high-sulfur diesel, liquefied petroleum gas, isobutane, polygas, a blending fuel used in liquid fertilizers, naptha and propylene. Some of these petrochemical products are more profitable than others, but the volume is significantly lower than gasoline and jet fuel. The Krotz Springs refinery generated $70.5 million in annual sales as of December 2019, largely split between gasoline and jet fuel, with 35,000 barrels and 28,000 barrels, respectively, according to U.S. Securities and Exchange Commission records. Petrochemicals accounted for less than 5,000 barrels of daily capacity in 2019, records show. Delek U.S. told investors last week it plans to reorganize the business, but still invest $10 million in the Krotz Springs operation during fourth quarter for completion by first-quarter 2021, which is pushing the maintenance and turnaround work back by a few months.
NextDecade, Bechtel Extend Rio Grande LNG Contract to End of 2021 - Engineering firm Bechtel Corp. last month agreed to give NextDecade Corp. more time to fund its proposed Rio Grande liquefied natural gas (LNG) export project in Texas, amid a major setback that the project recently sustained. Houston-based NextDecade now has until December 21, 2021, to make positive final investment decisions (FIDs) to build up to three liquefaction trains at Rio Grande LNG for construction prices established last year to still be valid. The previous FID deadlines were July 31, 2021, according to a third quarter report NextDecade filed Wednesday with the U.S. Securities and Exchange Commission (SEC). Under one contract signed on May 24, 2019, Bechtel would build two liquefaction trains with combined capacity of 11.74 million metric tons/year (mmty), two 180,000-cubic-meter full containment LNG storage tanks, one marine loading berth and related facilities for $7.042 billion, according to a another document NextDecade filed with the SEC. Under a second contract signed the same day, Bechtel would build a third train with capacity of 5.87 mmty and related facilities for $2.323 billion. The project at full build-out would have a combined capacity of 27 mmty, equivalent to about 3.6 Bcf/d of gas, from five liquefaction trains. The contracts allow for relatively small price increases with deadline extensions and other changes, and the deadline presumably could be extended again. The French government recently delivered a blow to the project by scuttling a proposed $7-billion, 20-year deal for French energy firm Engie to buy LNG from Rio Grande because of environmental concerns over hydraulic fracturing. Rio Grande would get much of its feed gas from the Permian Basin in West Texas and Eastern New Mexico, where significant associated gas volumes are flared due to pipeline constraints. The government has a 23.63% stake in Engie. NextDecade management has said it is continuing negotiations with multiple customers to sign enough long-term deals to reach an FID in 2021 on at least two trains. Shell has signed a long-term deal to buy 2 mmty from Rio Grande but an LNG export project typically needs to sell at least 60-70% of its capacity under long-term deals to get bank financing.
COVID-19 oil bust turns once-pricey West Texas land into a bargain - Eric Huffman remembers a time not long ago when prospectors paid a hefty premium for land in the nation’s hottest oil fields.But since the coronavirus pandemic deflated crude demand, the value of oil land in West Texas and around the country has plummeted. Huffman, a land broker and attorney at Houston-based Lone Star Production Co., said he’s seen land prices fall below $1,000 an acre for property that was once valued at more than $10,000 an acre.“When (oil) prices are too low, no one is buying land,” Even if drillers were bullish on the quick rebound of crude demand, investors and banks have little interest in financing efforts to buy properties and drill new projects after years of disappointing returns in the energy sector. “People aren’t competing to acquire assets because there’s not the capital readily flowing into the space,” Huffman said. “The appetite is just not there.”As a result, the average price of U.S. shale acreage has fallen by more than 70 percent in two years, to $5,000 per acre in 2020 from $17,000 per acre in 2018, according to Rystad, a Norwegian energy research firm.Amid the wider decline, the value of some shale plays has held up. The Permian-Delaware basin is still valued at $30,000 per acre and the Midland basin is valued at $17,000 an acre, Rystad said. But prices for devalued oil and gas lands will be slow to recover as long as COVID-19 cases surge, and related lockdowns keep pressure on demand for petroleum.“We do not foresee demand for (oil) assets rising in the coming quarters,” Alisa Lukash, a senior analyst at Rystad, said in Thursday’s report. The real estate downturn is squeezing oil and gas companies that are relying on asset sales to balance budgets and pay debt. Houston-based Occidental Petroleum, which is trying to sell billions of dollars of assets to erase debt incurred in its $38 billion acquisition of Anadarko Petroleum in 2019, said this week that it lost $700 million on asset sales in Colombia and Wyoming because of low crude prices.Land brokers, called landmen in the oil and gas industry, also are feeling the squeeze, as work has dried up, said Huffman, a former president of the Houston Association of Professional Landmen, which has some 1,300 members. These brokers work with oil and gas producers to find and lease properties to drill. But with few companies drilling new wells, there aren’t many buyers seeking broker services.“It’s been pretty tough for landmen,” Huffman said. “What was once a land rush is now being scrutinized by very sophisticated oil and gas people that are trying to find a couple of shiny diamonds in a pile of gravel.”
Texas bill would tax wind, solar generation but not natural gas - Power bills likely would rise next year for Texas consumers who get their electricity from wind, solar, coal and nuclear generation if the Legislature approves a bill filed this week.The bill from state Rep. Ken King would add 1 cent to every kilowatt hour of energy generated. The tax likely would be passed on to consumers, adding about $12 a month to bills for households that use 1,200 kilowatt hours of renewable power sources each month. Power generated from natural gas would be exempt from the tax.Wind produced about 20 percent of electricity last year in Texas, which is the nation's leader in wind power generation, and 47 percent came from natural gas, according to the state's grid manager, the Electric Reliability Council of Texas.RELATED: Solar expected to disrupt Texas fossil-fuel apple cartLuke Metzger, executive director of the Austin-based clean energy advocacy group Environment Texas, said the bill makes no sense.“It flies against the rhetoric of Texas' market-based system of electricity, putting the thumb on the scale for natural gas and raising taxes on Texans by $2.3 billion every year,” he said in a prepared statement. “It would also discourage wind and solar power, which are reducing pollution, helping us tread more lightly on the planet, and boosting rural economies.”King, a Republican from Canadian, Texas, represents a swath of the Texas Panhandle stretching from Oklahoma to New Mexico. The region is one of the biggest generators of wind in Texas and where millions of dollars were spent to build transmission lines to transport the wind to the state’s population centers.
BP reports uptick of spills in La Plata County - BP America Production Co. has reported four spills of produced water at oil and gas facilities in La Plata County since Oct. 28, according to state records, bringing the total to nearly 20 spills for the year. The first spill in the recent string of incidents was discovered Oct. 28, north of Colorado Highway 172, about 6 miles southeast of Durango. According to an incident report, a property owner reported a pipeline leak, and upon inspection, it was determined produced water was flowing into a nearby irrigation ditch and pond, which was reportedly dry. Produced water is a term that refers to the wastewater byproduct of oil and gas production, which can contain high concentrations of hydrocarbons and carry negative environmental impacts. Livestock on the property was removed, and BP worked to contain the spill. The company reported an “unknown volume of produced water” was released in the spill, none of which could be recovered. Inspectors with the Colorado Oil and Gas Conservation Commission inspected the site. According to state records, water and soil samples were taken. The next spill was discovered Nov. 4, also off Colorado Highway 172, about 3 miles south of Ignacio. An incident report says a pipeline released produced water, which ultimately flowed into a nearby arroyo that runs into the Los Pinos River. BP says the pipeline was isolated, but doesn’t know how much produced water was spilled. Water and soil sampling will be required in that instance, too. Then, two separate spills were found Nov. 6, according to state records. One spill happened near County Road 319, about 3 miles southwest of Ignacio, where an estimated 245 barrels, or about 10,290 gallons, of produced water was released, which required BP to create a small berm to stop it. The other incident occurred near County Road 523, about 6 miles southeast of Bayfield after a pipeline was reportedly found leaking. BP said a little more than a barrel of produced water was released. BP this year sold its assets in the San Juan Basin natural gas field, which spans Southwest Colorado and northern New Mexico, to a European renewable energy company called IKAV Energy Inc. But according to COGCC records, BP is still the company filing incident reports.
Texas Clampdown on Gas Flaring Falls Short of Total Prohibition - Texas’s oil regulator took action to reduce routine natural gas flaring but its efforts fall short of more aggressive measures requested by some investors and major producers. Read more at: https://www.bloombergquint.com/markets/texas-clampdown-on-gas-flaring-falls-short-of-total-prohibition Copyright © BloombergQuint
Shell Wants Biden to Reverse Methane Emissions Rollback - Royal Dutch Shell Plc will push for the reversal of President Donald Trump’s rollback of methane emissions rules and the introduction of carbon pricing when Joe Biden moves into the White House next year. “Some of the regulatory rollbacks that we’ve seen under the current administration haven’t actually benefited our industry,” Shell U.S. President Gretchen Watkins said Tuesday on a webcast hosted by the Greater Houston Partnership. The easing of direct regulation of methane emissions put the energy industry in a “backwards-facing position,” while the absence of carbon pricing makes it harder to incentivize new technologies like carbon capture, Watkins said. “Whoever is in the White House, we will work constructively with them and are actually very much looking forward to building that relationship with the new administration that’s coming in in January,” she added. The oil and gas industry, which has long been the target of environmental groups, faces increasing pressure from shareholders managing trillions of dollars to address greenhouse-gas emissions such as methane. Shell joined BP Plc in September in calling for Texas regulators to end the routine flaring of natural gas, a by-product of the oil boom in the shale patch.
Biden's oil plan: The good, the bad and the illegal -- Thursday, November 12, 2020 -- An overhaul of the federal oil and gas program didn't make it into President-elect Joe Biden's transition priorities listed on his website Sunday after he was declared the winner of the presidential race. But observers are still expecting Biden and Vice President-elect Kamala Harris to curtail oil and gas development on federal lands and waters, an area where the president can exert significant direct control, experts say. The campaign's proposal includes a first-day promise to ban new permitting, which approves specific drilling plans, and bar new leasing, which gives prospectors a 10-year property right to develop federal minerals. The president-elect's platform has also pledged an end to hydraulic fracturing on public lands, a contentious development technique that is ubiquitous in the U.S. oil patch and has long stoked criticism from environmentalists. "A real transition to a clean energy future can and must begin with a halt to new fracking — first on federal lands, and everywhere else soon after," Food & Water Action Executive Director Wenonah Hauter said in a statement soon after the election was called for Biden. If Biden follows through on his campaign pledges, the beginning of 2021 could see a significant shift for the oil and gas industry in states like Wyoming and New Mexico — where federal oil and gas development is prominent. It also could potentially refashion oil drilling on federal land and water for many years to come. But experts say there are several big "ifs" in Biden's plan, not least of which is the potential backlash from curtailing industry. Federal oil development represents one-quarter of national production, according to the U.S. Geological Survey, and both oil and natural gas pour into both federal and state budgets. Proposed policies to choke new leasing and permitting, and even throttle fracking on federal land, are likely doable, but they'll spark political and judicial fights.
Oil and gas experts discuss how Biden administration could affect the industry — The oil and gas industry in Texas and right here in the Coastal Bend is preparing for a change in leadership, but with a new administration in the White House, some question what that will mean for local oil and gas jobs. There has been some concern ever since president elect Joe Biden mentioned that he wants to transition over time to energy sources that don't pollute as much as oil does. When you look at the state's economy, you could say Texas is oil country. According to the Texas Oil and Gas Association, in 2019 the industry supported more than 400-thousand direct jobs. Now, with a change in power on the horizon, Joe Biden's stance has certainly raised eyes and sparked some fear in an industry already hit hard by the COVID-19 pandemic. Economics professor Dr. Jim Lee at Texas A&M Corpus Christi said what the industry will likely see are more regulations and added costs of oil production. He doesn't see a major loss in jobs because of the industry's ability to adapt. "In the long run, I wouldn't say we are going to lose jobs immediately because of that, but we will feel it in our pocketbooks because in the end they are going to pass on the higher cost of extracting oil and producing oil because producing clean energy doesn't come free," said Dr. Lee. The Port of Corpus Christi also takes on a vital role in the energy sector. It has become the 3rd largest port in the U.S. based on tonnage and the second largest exporter of crude oil. Port chairman Charlie Zahn said he doesn't believe the presidential transition will have much if any affect at all. He said the country is too dependent on oil and gas. "Oil and gas are not just used for transportation purposes, they're used in a lot of products that each one of us on a day-to-day basis was still going to have a need for energy," said Zahn. "We certainly believe the Biden administration is going to have a significant focus on reducing atmospheric carbon concentrations, but when it comes to energy exports and Texas exports, we believe the Biden administration will continue with that policy," said Port of Corpus Christi CEO Sean Strawbridge.
Big Oil execs say they’re not worried about Biden’s energy plan; hope to ‘get his staff on board’— The prospect of a Joe Biden presidency and the most progressive climate strategy the U.S. has ever attempted is not something that should concern the energy industry, oil and gas executives have told CNBC. Instead, they hope President-elect Biden will engage directly with them as he rolls out his energy plan. Biden, who has won the U.S. election according to NBC projections, has previously said that one of his first acts as president would be to reverse President Donald Trump's decision to pull out of the Paris climate agreement, an international pact designed to avert the dangerous warming of the planet. Thereafter, cutting carbon emissions will likely take center stage when it comes to the former vice president's energy credibility. Democrats such as Congresswoman Alexandria Ocasio Cortez are pushing for Biden to consider backing the Green New Deal, which would eliminate carbon emissions from most sources over a decade. At present, however, Biden's energy plan is more moderate. "Talking about climate is often like talking about religion with some politicians. They don't actually understand the complexities of the energy system very much and that's never very satisfying," said Bob Dudley, former CEO of BP and chair of the Oil and Gas Climate Initiative (OGCI), an umbrella group of some of the world's leading oil and gas producers. "So, what we need are policymakers and governments around the world that actually understand the mix of technologies, how they will come along, and the cost of these technologies, rather than rushing to get elected with what sounds too good to be true." When asked specifically about whether he felt Biden understood those energy complexities, Dudley told CNBC's Steve Sedgwick: "If you look at the campaign rhetoric around it, I think you have a spectrum in his party. I think he understands it, it can't be as fast." Dudley added: "There are some who want to go much faster and as a politician, he is going to have to balance what some people describe as the 'far left' with the more centrist parts of his party. How he'll do that? I don't know."
Big Oil Has Long Way to Go on Emissions Targets: Green Insight - Just five of the 39 largest oil and gas companies have announced carbon-reduction targets that match levels needed to avoid a 2-degree Celsius temperature increase. And only 20 have taken initial steps to disclose how they plan to lower emissions produced by both their operations and electricity use, known respectively as Scope 1 and Scope 2. Put those facts together and it may seem like most of the world’s biggest polluters aren’t serious about climate change. The list of passive offenders includes four of the top-five ranked energy companies by stock market value: Chevron Corp., Exxon Mobil Corp., PetroChina Co. and Saudi Aramco. Eni SpA, Total SA, Reliance Industries Ltd., Galp Energia SGPS SA and Woodside Petroleum Ltd. are the only companies that have targets in-line with the International Energy Agency’s Sustainable Development Scenario (SDS) for 2030, said Eric Kane, senior ESG analyst at Bloomberg Intelligence, which has introduced a “carbon transition score” to evaluate, compare and rank how companies are cutting their carbon intensity. On Tuesday, Occidental Petroleum Corp. became the first major U.S. oil producer to aim for net zero emissions from everything it extracts and sells.The score allows investors to measure oil and gas companies’ progress in reducing their operational emissions intensity, Kane said. It also shows how they are positioned relative to each other and the IEA benchmark, assuming they are successful in achieving their publicly stated greenhouse gas reduction targets, he said.“Despite the risks, many companies have yet to develop reduction strategies,” Kane said.Of the 39 energy firms, just eight have established plans to lower Scope 3 emissions, which are generated when their customers burn fossil fuels, a figure that comprises about 80% of total greenhouse gases at large oil companies. That suggests most companies in the industry are likely to face significant challenges as the economy shifts away from carbon-intensive energy, Kane said.
Oil, Gas Permits for Lower 48 Federal Land Climb Ahead of Biden's Election - U.S. explorers during October increased their oil and gas permit requests for the third month in a row, with an uptick in developing leaseholds on federal lands, according to Evercore ISI. The analyst firm each month provides data using state and federal sources regarding permits for oil and gas wells, plugging and abandoned (P&A) wells approved and detailed variances of onshore and offshore permitting. The gains in federal land requests preceded the election of Democrat Joseph R. Biden Jr., who has said he would seek to ban drilling on federal lands. U.S. applications by exploration and production (E&P) companies accelerated 25% month/month (m/m) in October, “which is the largest monthly increase so far in 2020,” Evercore analysts said.The increase mainly was driven by the Permian Basin, with permits up 76 over September. Requests to drill on federal lands in the Permian jumped by 19% m/m, according to Evercore. Marcellus Shale permit requests rose by 83 from September, with Bakken Shale requests increasing by 20, the data indicated. Operators filed 1,301 permits in oil formations, up by 199 from September, with 46% approved for the Permian and the Eagle Ford Shale. Leading up to the U.S. election, Evercore noted that Devon Energy Corp. boosted its permit activity in the Permian by 15 m/m in October, “as it pressed ahead with plans to receive regulatory approval of 650 federal permits by year-end.” Concho Resources Inc. and Occidental Petroleum Corp. (Oxy) “ramped their permits to a new 2020 peak in October,” analysts said. Oxy “scaled up applications to 63 (plus 40 m/m) with the bulk of permits focused mainly in New Mexico.” The Bakken permit count rose to 73 during October, up by 20 from September, “which is only 3% lower from January,” said analysts. “Incremental activity was primarily driven by ConocoPhillips,” up by 28 m/m, and the October count “reached the highest level so far this year.” Overall, permitted wells in oil formations had declined through October by 67% year/year (y/y) to 14,656, primarily from a “collapse in the Powder River Basin,” which had plunged by 67%, Evercore noted. Permian activity through October stood at 5,353, off by 37% y/y. The pullback was driven by “sharp reductions” at ExxonMobil, off by 52%, Marathon Oil Co., down 75%, and ConocoPhillips, whose permitting activity was 61% lower. Meanwhile, public E&Ps working in Appalachia’s Marcellus Shale increased their permitting activity by 1,038% from September, according to the data. Natural gas prices are forecast to strengthen, along with activity in the gassy formations of the Marcellus and Utica shales, and the Haynesville Shale.Overall, state regulators during October granted 220 permits in Lower 48 gas formations, up by 98% from September, with “a strong recovery in the Marcellus and the Utica, where applications are returning to 1Q2020 levels,” said Evercore analysts. “Wells permitted in the Marcellus ramped to 91 (up 83 m/m),” driven Antero Resources Corp., up 28, Southwestern Energy Corp., up 15, and Chesapeake Energy Corp., up by 11. Public operators submitted 75% of the October permits in the Appalachian plays, Evercore noted. Meanwhile, Utica permit activity was higher at 27, an increase of 13 over September, “trending upward for the second consecutive month.”
US Rig Count Rises Double Digits as Recovery Gains Steam - Already on the ascent, the U.S. rig count’s trajectory bent further upward for the week ended Friday (Nov. 13), as strength in oil-directed drilling lifted the overall domestic tally 12 units to 312, according to the latest data from Baker Hughes Co. (BKR). Gains for the week included 10 oil rigs and two natural gas-directed units. The U.S. count ended the week nearly 500 units shy of its year-ago total of 806. The domestic count has risen steadily over the past two months, clawing its way back from a recent low of 254 rigs for the week ending Sept. 11, according to the BKR numbers, which are based on data provided in part by Enverus Drillinginfo. Land drilling rose by 11 units during the period, while one rig was added in the Gulf of Mexico. Eight horizontal units and four directional units returned to action, while the total number of vertical units remained unchanged at 22. The Canadian rig count increased three units to 89, including two oil rigs and one natural gas rig. The Canadian count finished 45 units below the 134 rigs running there at this time last year. The combined North American rig count finished at 401, down from 940 a year ago. Among major plays, the Permian Basin added seven rigs to grow its tally to 154, versus 408 in the year-ago period. The Marcellus Shale added two rigs, while the Cana Woodford and Eagle Ford Shale each added one rig. The Utica Shale saw a net decrease of one rig during the period. Broken down by state, BKR tallied a six-rig increase in Texas, with three rigs returning to action in New Mexico. Pennsylvania added two rigs week/week, while Louisiana and Oklahoma each added one. Ohio dropped one rig from its total. U.S. explorers during October increased their oil and gas permit requests for the third month in a row, with an uptick in developing leaseholds on federal lands, according to a recent analysis conducted by Evercore ISI. U.S. applications by exploration and production companies accelerated 25% month/month in October, “which is the largest monthly increase so far in 2020,” Evercore analysts said. The increase mainly was driven by the Permian, with permits up 76 over September. Requests to drill on federal lands in the Permian jumped by 19% month/month, according to Evercore.
Oil operators get DUCs in a row, adding fracking crews to boost output - US frackers are bringing back equipment even as oil prices languish around $40 a barrel in a bid to boost production and tap into a backlog of drilled wells left uncompleted (DUCs) when oil prices crashed earlier this year.The number of active hydraulic fracturing fleets has climbed by nearly 50% since mid-September to 127, according to data from consultancy Primary Vision, outpacing a roughly 17% jump in the number of active drilling rigs over that same period of time. That count stands at 296.US oil prices were trading around $38.53 a barrel on Thursday, below profitable levels in some US producing basins. Still, hydraulic fracturing equipment is headed back to the field, as oil companies are trying to deal with the swift rate at which shale well production falls. US shale production is expected to fall to 7.7 million barrels per day in November, down from 9.2 million bpd in February, before prices crashed, according to the USEnergy Information Administration.Fracking was the first thing to get shut down when oil prices collapsed because it's the most expensive part of drilling and completing a well, said Andy Hendricks, chief executive officer of driller Patterson-UTI Energy. When prices rose, operators brought back frack crews to complete wells that were drilled but not yet completed, accounting for a big bump in frack activity.The companies that specialize in well completions, like ProPetro Holding Corp and Liberty Oilfield Services , have said they are adding back workers."Oil focused operators and basins are trying to manage decline curves," said Matt Johnson, chief executive of Primary Vision.The US added as many as 1,200 DUCs in May, according to analysis from consultancy Enverus, but began completing wells at a faster rate than rigs could drill them starting around July. In October, operators were burning through DUCs at a rate of roughly 200 a month, Enverus said. That pace could slow, Hendricks warned. "I don't expect big increases in frack activity from where we are. We just don't have the inventory," he said referencing drilled-but-uncompleted wells.
State regulators approve Line 3 permits; move pipeline closer to construction - State environmental regulators issued several key permits Thursday that move Enbridge Energy closer to building its controversial Line 3 oil pipeline replacement project. The Minnesota Department of Natural Resources and Minnesota Pollution Control Agency both approved permits for the Line 3 project. Now, Enbridge just needs a permit from the U.S. Army Corps of Engineers and an additional permit that's expected from the MPCA in the next month. The MPCA’s decision this week will trigger a decision from the U.S. Army Corps of Engineers on its permit. At that point, Enbridge could begin work on the project — which would replace an existing, aging pipeline that at nearly 60 years in operation, is deteriorating and can only transport about half the oil it was designed for, with a new, larger line along a different route across northern Minnesota. An Enbridge spokesperson said only that the company would begin construction once it has all approvals in hand. Kevin Pranis, a spokesperson for the LIUNA union, whose members plan to work on the project, said they expect construction to begin in the next month. Once it does, Enbridge says construction will take six to nine months. The Minnesota Public Utilities Commission, which regulates state utilities and pipelines, gave the Line 3 project its stamp of approval for the second time earlier this year. The PUC originally granted a required certificate of need and route permit for the project in 2018, but had to vote again on the proposal after a court ordered that the project’s environmental review needed to be revised. In the meantime, the project has been held up by legal challenges, including one that the state Commerce Department renewed in August. An array of environmental and tribal groups oppose the project, arguing that it will contribute to climate change and risk oil spills in northern Minnesota waterways. Supporters argue that the new pipeline will be safer than the current line, and that it will create thousands of construction jobs.
Indigenous and Climate Leaders Outraged Over Minnesota Permits for Line 3 Pipeline - Environmental and Indigenous leaders on Thursday responded with alarm after Minnesota regulators approved key permits for Enbridge Energy's planned Line 3 Pipeline replacement, and called on Democratic Gov. Tim Walz to block any construction for the Canadian company's long-delayed multibillion-dollar project."Gov. Walz has apparently decided that if Washington won't lead on climate, Minnesota won't either," said Andy Pearson, MN350's Midwest tar sands coordinator, in a statement about the permits. "Make no mistake. "This decision is a sharp escalation against water protectors and climate science."The Associated Press reported that "the approvals from the Minnesota Pollution Control Agency and Department of Natural Resources clear the way for the U.S. Army Corps of Engineers to issue the remaining federal permits, which is expected to happen fairly quickly. The MPCA could then approve a final construction storm water permit that's meant to protect surface waters from pollutant runoff."As Leo Golden, vice president of Line 3 execution, called it "a big day for Line 3 in Minnesota" and said that "these authorizations and approvals are an important step towards construction," Pearson and other critics of the crude oil project reiterated their opposition, citing both treaty rights and climate science."Line 3 is facing multiple court challenges by Native nations, grassroots groups, and the Minnesota Department of Commerce," Pearson noted. "This decision means that Enbridge may launch construction while the overall need and legality of the pipeline are being fought in court, including by a state agency." "There is a good chance that courts will find the pipeline was approved illegally," he said. "It's just common sense, then, to demand that the state immediately halt Enbridge's progress toward construction while those important legal challenges play out."
State launches economic stimulus program to bring oil and gas workforce back - Gov. Mark Gordon launched an economic stimulus program on Wednesday to help the state’s ailing oil and gas industry recover from the economic collapse of energy markets fueled by the COVID-19 pandemic.The $15 million available to operators will come from federal CARES Act dollars. The program aims to pump resources into well cleanup and finishing uncompleted oil and gas wells.Uncompleted wells have a well bore drilled, but oil and gas have yet to be extracted. To complete the well, operators engage in hydraulic fracturing, or fracking.Wyoming operators will be eligible for up to $500,000 in aid.“These funds will have a direct impact on Wyoming’s employment rate and put people back to work in our oil and gas sector which was impacted by COVID-19,” Gordon said. “It will provide opportunities for employees who lost jobs when drilling ceased. The oil and gas industry is a huge contributor to Wyoming revenues, employment, and its overall economy. These dollars will assist in our state’s economic rebound.”In March, a global oil price war broke out between Russia and Saudi Arabia, sending prices tumbling. Simultaneously, the COVID-19 pandemic brought the economy to a near standstill, chilling demand for fuel. By April, the glut in supply and drought in demand caused oil prices to go negative. West Texas Intermediate contracts for May sold at negative $40 per barrel, plummeting roughly 300% a day before the deadline to purchase them. In June, Wyoming’s oil and gas rig count sank to zero for the first time in over 136 years. The series of events this year have devastated the U.S. oil and gas business.Measures taken to stem the tide of COVID-19 infections slashed petroleum consumption to the lowest levels the U.S. Energy Information Administration has recorded since it began collecting this data in the early 1990s.“The Energy Rebound Program is an excellent use of the CARES Act funding,” Rep. Steve Harshman, R-Casper, said in a statement. “CARES funding was designed to address many of the disastrous economic effects stemming from the COVID and the collapse of much of Wyoming’s economy. The program will provide immediate jobs and long-term revenue for Wyoming.” The Petroleum Association of Wyoming also praised the economic stimulus program.
Oil field operations likely triggered earthquakes in California a few miles from the San Andreas Fault - The way companies drill for oil and gas and dispose of wastewater can trigger earthquakes, at times in unexpected places.In West Texas, earthquake rates are now 30 times higher than they were in 2013. Studies have also linked earthquakes to oil field operations in Oklahoma, Kansas, Colorado and Ohio.California was thought to be an exception, a place where oil field operations and tectonic faults apparently coexisted without much problem. Now, new research shows that the state’s natural earthquake activity may be hiding industry-induced quakes.As a seismologist, I have been investigating induced earthquakes in the U.S., Europe and Australia. Our latest study, released on Nov. 11, shows how California oil field operations are putting stress on tectonic faults in an area just a few miles from the San Andreas Fault.Industry-induced earthquakes have been an increasing concern in the central and eastern United States for more than a decade.Most of these earthquakes are too small to be felt, but not all of them. In 2016, a magnitude 5.8 earthquake damaged buildings in Pawnee, Oklahoma, and led state and federal regulators to shut down 32 wastewater disposal wells near a newly discovered fault. Large earthquakes are rare far from tectonic plate boundaries, and Oklahoma experiencing three magnitude 5 or greater earthquakes in one year, as happened in 2016, was unheard of.Oklahoma’s earthquake frequency fell with lower oil prices and regulators’ decision to require companies to decrease their well injection volume, but there are still more earthquakes there today than in 2010.A familiar pattern has been emerging in West Texas in the past few years: drastically increasing earthquake rates well beyond the natural rate. A magnitude 5 earthquake shook West Texas in March. At the root of the induced earthquake problem are two different types of fluid injection operations: hydraulic fracturing and wastewater disposal. Hydraulic fracturing involves injecting water, sand and chemicals at very high pressures to create flow pathways for hydrocarbons trapped in tight rock formations. Wastewater disposal involves injecting fluids into deep geological formations. Although wastewater is pumped at low pressures, this type of operation can disturb natural pressures and stresses over large areas, several miles from injection wells.Tectonic faults underneath geothermal and oil reservoirs are often precariously balanced. Even a small perturbation to the natural tectonic system – due to deep fluid injection, for example – can cause faults to slip and trigger earthquakes.
Trump to Rush Drilling Leases in Arctic Before Biden Takes Over The Trump administration is advancing plans to auction drilling rights in the U.S. Arctic National Wildlife Refuge before the inauguration of President-elect Joe Biden, who has vowed to block oil exploration in the rugged Alaska wilderness. The Interior Department is set to issue a formal “call for nominations” as soon as Monday, kick-starting a final effort to get input on what tracts to auction inside the refuge’s 1.56-million-acre coastal plain. The plans were described by two people familiar with the matter who asked not to be named detailing administration strategy. Biden has pledged to permanently protect the refuge, saying drilling there would be a “big disaster.” But those efforts could be complicated if the Trump administration sells drilling rights first. Formally issued oil and gas leases on federal land are government contracts that can’t be easily yanked. The U.S. Geological Survey has estimated the refuge’s coastal plain might hold between 4.3 billion and 11.8 billion barrels of technically recoverable crude. Yet it’s unclear how many oil companies would have the appetite to mount costly operations in the remote Arctic wilderness amid low crude prices, steep public opposition, and regulatory uncertainty. Major U.S. banks have sworn off financing Arctic drilling projects, and conservationists are also pressuring oil executives to rule out work in the region. Environmentalists argue Arctic oil development imperils one of the country’s last truly wild places -- a swath of northeast Alaska populated by polar bears, caribou, and more than 200 species of birds. The Trump administration is also fast-tracking a proposal to conduct 3-D seismic surveys inside the refuge before Jan. 20. The surveys can help pinpoint possible underground oil reserves, but environmentalists warn they are large industrial operations that threaten polar bears hidden in snow-covered dens. Oil companies that buy leases in the refuge might never get the opportunity to use them while Biden is in the White House. Even if leases are sold and issued before Jan. 20, companies will need permits governing air pollution, animal harm, water usage and rights of way that the new administration could stall or deny. Congress mandated the Interior Department hold two auctions of coastal plain oil leases before Dec. 22, 2024. But environmentalists, states and indigenous groups have already mounted legal challenges against the leasing plan. Any victory by the conservationists or settlement with the Biden administration requiring more environmental review could jeopardize leases.
Oil spill at Churchill Falls in October released roughly 45,000 litres of oil: Nalcor - An oil spill at the Nalcor Energy Churchill Falls switchyard in late October released roughly 45,000 litres of oil, the company said in a media release on Thursday, as it continues to work on clean up. The spill was caused by a transformer failure and fire, the company maintains, but while Nalcor at the time said the transformers hold 53,000 litres of oil, they actually hold 111,400 litres, according to Thursday's release. Nalcor said 65,000 litres of oil were recovered in tankers in the switchyard, and an unknown amount of the oil spilled was consumed by the fire. "Priority continues to be employee safety and the safe containment, control, and recovery of oil. Absorbent materials, booms, and vacuum trucks are being utilized for containment and collection," reads the company's statement. "We continue to see no visible evidence of oil in the Churchill River." In October, Nalcor said the oil used in the failed transformer was voltesso — an oil that is inherently biodegradable as opposed to readily biodegradable, meaning it will break down over time but the timeline is indefinite. However, Nalcor says now the oil spilled was actually luminol, which is readily biodegradable. "Luminol is more environmentally friendly and has a higher rate of biodegradability than voltesso," says Nalcor's statement. "Significant efforts continue to be made by the Churchill Falls team who has been safely working together in these recovery and collection efforts with dedication and commitment since the onset."
The multi-billion-dollar merger of Canadian giants Cenovus and Husky - On October 25, a major consolidation of two Canadian oil and gas companies was announced with the planned merger of Cenovus Energy and Husky Energy. The prospective consolidation will offer the opportunity for corporate-level synergies and, over the longer term, for the physical integration of some of the companies’ operations, especially in Alberta’s oil sands. In today’s blog, we discuss some of the more nuanced elements of the consolidation, including potential improvement in crude oil market access and the larger presence of the combined company in PADD 2 refining, a sector that has taken a major hit during the pandemic. This blog also introduces a new weekly report from RBN and Baker & O’Brien: U.S. Refinery Billboard. Cenovus Energy is an integrated oil and natural gas company headquartered in Calgary, AB. It was formed when Encana Corp. (now known as Ovintiv) spun-off its oil-based assets into a separate corporation in 2009, allowing Encana to — at the time — focus on its natural gas assets. Cenovus produces oil in Canada and has refining interests in the U.S. The production assets include oil sands facilities at Christina Lake and Foster Creek (blue dots in Figure 1) and conventional operations at Marten Hills and Deep Basin (blue triangles). Notably, Cenovus announced this week that they have entered into an agreement to sell their Marten Hills oil assets to Headwater Exploration. In the U.S., Cenovus has a 50-50 partnership with Phillips 66 in WRB Refining, which has refineries in Borger, TX, and Wood River, IL (blue refinery icons). Husky Energy is also an integrated oil and natural gas company based in Calgary. The company was founded in 1938 in Cody, WY, but relocated to Canada in 1946. Since then, the company has grown organically and through acquisitions of companies such as Mohawk Oil, Renaissance Energy, and the Canadian unit of Marathon Oil, as well as the purchases of Valero Energy’s Lima, OH, refinery and Calumet’s refinery in Superior, WI. Today, the company is majority-owned by Hong Kong billionaire Li Ka-Shing, the 30th-richest person in the world. Husky’s oil production assets include oil sands operations at Sunrise, Tucker, and Lloyd Thermal (green dots in Figure 1); conventional assets at Rainbow and Deep Basin (green triangles); and offshore production in the South China Sea (the Liwan project) and the Madura Strait in Indonesia (the Madura project; green offshore platform icons in inset map), and off the coast of Newfoundland & Labrador in eastern Canada (the White Rose project; green offshore platform icon on main map). Husky’s refining assets include the Lloydminster Upgrader in Saskatchewan and asphalt refinery in Alberta; the Superior, WI, refinery (which is currently shut down and under repair after a major explosion/fire in 2018), and two refineries in Ohio (Lima and the BP-Husky JV refinery in Toledo; green refinery icons).
BP refinery closure threatens hundreds of jobs in Western Australia - In late October, British oil and gas company BP announced that over the next six months it will progressively close its refinery in the city of Kwinana near Perth, Western Australia (WA). The shutdown will cost at least 590 jobs. The refinery, the largest in Australia and the only one in WA, has been in operation for over 65 years. It currently employs 400 permanent staff and 250 contractors. It is to be converted into an import terminal that will employ only 60 people when it is completed in the middle of next year. Even before the pandemic had fully taken effect, official unemployment in Kwinana had hit 11.8 percent in the March quarter this year. This is far higher than the general rate for WA, which has just fallen to 7 percent, down from 8.7 percent in June as COVID-19 restrictions are eased. BP Australia head Frédéric Baudry told the media that the company’s decision “was not in any way a result of local policy settings,” but was in “response to the long-term structural changes to the regional fuels market.” The closure is part of a vicious global restructuring of the sector by the major oil companies, to cut costs and offset the impact of a slump in oil prices. Production is being slashed, jobs destroyed and older plants closed to facilitate the relocation of operations to newer large-scale export refineries in Asia and the Middle East. A September article by Reuters stated that global oil refiners, “reeling from months of lackluster demand and an abundance of inventories,” are cutting fuel production “because the recovery in demand from the impact of coronavirus has stalled.” Reuters reported that the Paris-based International Energy Agency (IEA) had reduced its forecast for global oil demand for 2020 for the second time in two months “due to the faltering recovery.” The IEA also forecast that “global consumption of petroleum and liquid fuels will average just 91.7 million barrels per day (bpd) for all of 2020, a reduction in its previous forecast of 200,000 bpd and down 8.4 million bpd from 2019’s 100.1 million bpd level.” According to natural resources research and consulting firm Wood Mackenzie, nearly 10 percent of high-cost refineries in Europe, or 1.4 million bpd of capacity, are in serious threat of closure over the next three years. Research and marketing agency Argus reported in August that US and Canadian refiners had already slashed 800,000 bpd of crude capacity this year and “at least 575,000 bpd of that will stay closed.” In Australia, other closures are likely to follow Kwinana with owners of the country’s three other remaining refineries already placing their operations under critical review. Ampol is considering shutting its Lytton refinery in Queensland, threatening 500 jobs, Viva Energy will possibly close its refinery in Geelong, Victoria, a facility that employs 700 people, while ExxonMobil has put a question mark over its Altona refinery in the same state, which is manned by 350 workers.
Oil spill- AIbom group demands N16.4bn compensation from NNPC --THE Akwa Ibom Oil Producing Community Development Network has asked the Nigerian National Petroleum Corporation to pay the sum of N16.4bn being compensation for oil spills in some communities in the state The demand was contained in a letter addressed to NNPC Managing Director and signed by the organisation’s lawyer, Mr N. A. Williams. The letter was copied Managing Director, Nigerian Petroleum Development Company Limited; the Managing Director, Sterling Oil Exploration & Energy Production Company Ltd; the Executive Secretary, National Human Rights Commission; the Manager, Cooperate Lands Management, and the Village Head, Ikot Ada Udo Community, Ikot Abasi. According to the letter, the organisation for many years has been demanding compensation from Shell Petroleum Development Company and other oil companies due to the negative effects of hydrocarbon pollution (oil spills, gas flaring and toxic waste dumping by Exxon Mobil and gas leakages/emissions from corked and uncorked wells, especially those belonging to SPDC Ibibio I oil spill at Ikot Ada Udo and elsewhere in the state. The letter recalled that “in the case of Ikot Ada Udo, SPDC Ibibio 1 oil spill incident first occurred in the year 1997. It re-occurred in 1999, 2004 and lasted till 2007 due to Ibibio 1 oil well head facility failure. “The spills resulted in the discharge of remarkable quantity of crude oil into the majorly rural farmlands and water bodies in Ikot Ada Udo and adjoining villages in Ikpa Nung Asang Clan in Ikot Abasi L.G.A, Ibiaku/Ukpum Minya Clans in Mkpat Enin L.G.A and Abak Midim in Oruk Anam L.G.A. “The spills drastically affected the ecosystem, wellbeing of the inhabitants and the environment. “Sequel to this unfavorable development, the community Attorney consulted an Accredited Estate Surveyors and Valuers who carried out valuation of the damages caused by the said spill/gas emissions which is in the sum of N4,136,484,000.00 only for Ikot Ada Udo. “The valuation for villages in Ikpa Nung Asang in Ikot Abasi L.G.A, Ukpum Minya/Ibiaku Clan in Mkpat Enin L.G.A and other SPDC’s host communities in Akwa Ibom State is N12,266,950,000.00 (Twelve Billion, Two Hundred and Sixty-Six Million, Nine Hundred and Fifty Thousand Naira) only, totaling N16,403,434,000.00.”
OPEC cuts 2020 oil demand forecast again on rising Covid cases — sees slower recovery next year— OPEC on Wednesday trimmed its global oil demand forecasts for the remainder of this year and 2021, citing a weaker-than-expected economic outlook and a surge in coronavirus cases. In a closely watched report, the group of oil-producing nations said it now expects world oil demand to contract by around 9.8 million barrels per day year over year in 2020. That reflects a downward revision of 0.3 million barrels from last month's assessment. For next year, OPEC said oil demand growth will rise by 6.2 million on an annual basis, representing a downward revision of another 0.3 million barrels from its October report. The group has steadily lowered its oil demand outlook for 2021 from an initial expectation of 7 million in July. "These downward revisions mainly take into account downward adjustments to the economic outlook in OECD economies due to COVID-19 containment measures, with the accompanying adverse impacts on transportation and industrial fuel demand through mid-2021," OPEC said in the report. The report comes ahead of the group's Nov. 30 and Dec. 1 meeting with non-OPEC allies to discuss the next phase of oil production policy. The energy alliance, a grouping known collectively as OPEC+, had agreed to a record supply cut of 9.7 million bpd starting on May 1. The cut was subsequently scaled back to 7.7 million in August and OPEC+ has said it plans further tapering next year. A coronavirus-led demand shock has seen oil prices collapse in 2020, with strict public health measures coinciding with curtailed travel and economic activity. An easing of lockdown measures in the third quarter helped global oil demand to improve, but OPEC now fears a surge in the number of reported Covid-19 cases could derail an expected recovery. "As new COVID-19 infection cases continued to rise during October in the US and Europe, forcing governments to re-introduce a number of restrictive measures, various fuels including transportation fuel are thought to bear the brunt going forward," OPEC said.
Successful vaccine would boost oil consumption, but not for 6-12 months: Kemp (Reuters) - Coronavirus vaccines are expected to boost international passenger transportation and oil consumption, but the first significant impact will not be felt until well into the second half of 2021, based on futures price movements on Monday. Brent calendar spreads surged that day as traders priced in an announcement from Pfizer about successful immunisation trials, fuelling optimism an effective vaccine will become available within the next few months. Before Pfizer’s announcement, flat prices and spreads had been under pressure since mid-October, prompting a statement from Saudi Arabia that OPEC and its partners are prepared to “tweak” their production agreement. The combined effect of Pfizer’s announcement (potentially boosting oil consumption) and Saudi Arabia’s talk about tweaking (potentially reducing production relative to the planned baseline) sent oil futures soaring. Front-month Brent futures prices closed more than 7% higher, an increase of more than three standard deviations, and the largest one-day percentage gain since the start of June. In the last two weeks, hedge funds and other money managers had sold the equivalent of almost 120 million barrels of Brent and WTI, including the creation of 62 million barrels of fresh short positions. The existence of so many shorts accelerated the price rise, as fund managers raced to buy back some contracts they had earlier sold, a classic high-volatility short-covering rally. Pfizer’s successful trial is reason for optimism that vaccines could be effective in controlling the coronavirus, as an alternative to lockdowns and travel restrictions. But any vaccination programme will not have a major effect until the second half of 2021, and in the meantime oil consumption is set to remain depressed, leaving OPEC and its partners with more to do to rebalance the market. Despite Pfizer’s optimism, any vaccine will take time to be approved by regulators, manufactured in large volumes, deployed through the logistics system, and administered to hundreds of millions of individuals. Likely delays at each stage of the timeline will ensure most restrictions on travel, especially those on international aviation, remain in place for at least six months, and possibly much longer. In the interim, news of successful trials may make governments more determined to maintain social-distancing and travel controls to suppress the virus as much as possible until the vaccine can be widely administered. Once vaccination is underway, however, many governments will come under pressure to permit some resumption of travel for passengers who can prove they pose a low transmission risk. And businesses will be allowed to re-open and domestic travel restrictions will be lifted as part of a plan to restart economic activity. But any relaxation of coronavirus controls, including limits on aviation and congregating in crowded spaces, is likely to be carefully phased and gradual. Only in the longer run, with widespread vaccination possibly tending towards herd immunity, coupled with a cyclical upswing in the global economy, will passenger flying recover to pre-pandemic levels.
Oil jumps on vaccine hopes, OPEC+ signal to tweak deal - Oil jumped on Monday by almost 10%, the highest daily rise in almost 6 month, after Pfizer said its COVID-19 vaccine was very effective, and Saudi Arabia said an OPEC+ deal on output cuts could be adjusted to offset rising supply and weak demand. Brent crude rose $3.33 cents, or 8.4%, to $42.78 a barrel, and U.S. West Texas Intermediate crude was at $40.53, up $3.39 cents, or 9.1%. Pfizer said the experimental vaccine was more than 90% effective in preventing COVID-19, based on initial data from a large study. Saudi Arabia's Energy Minister Prince Abdulaziz bin Salman said the OPEC+ deal on oil output cuts could be adjusted as it has been in the past if there is consensus among members of the group. The Saudi minister was commenting after being asked whether OPEC+ - which groups OPEC states, Russia and other producers - would stick to existing cuts of 7.7 million barrels per day (bpd), rather than easing them from January to 5.7 million bpd. Key members of the Organization of the Petroleum Exporting Countries are wary of Biden relaxing measures on Iran and Venezuela, which could mean an increase in oil production that would make it harder to balance supply with demand. "While a Biden presidency increases the likelihood of Iranian oil supply returning to the market, this is not something that will happen overnight, and we still believe it's more likely an end of 2021/2022 event," ING said in a note. The oil prices also found some support from a weaker U.S. dollar driven by Joe Biden becoming president-elect, said Giovanni Staunovo, oil analyst for UBS. The dollar weakened on Monday, hitting a 10-week low and boosting commodities priced in the greenback as they became more affordable for investors holding other currencies. China, the world's top crude importer, reported a 12% decline in October imports compared with September.
Oil soars 8% on promising COVID-19 vaccine results (Reuters) - Oil surged about 8% on Monday, its biggest daily gain in more five months, after Pfizer announced promising results for its COVID-19 vaccine. Brent crude LCOc1 settled at $42.40 a barrel, up $2.95, or 7.48%, while U.S. West Texas Intermediate crude CLc1 settled at $40.29 a barrel, rising $3.15, or 8.48%. Oil markets also rose after Saudi Arabia suggested it and other oil producers could adjust its current supply-cut pact, perhaps taking more barrels off the market if demand slumps in the winter as infections rise and before the vaccine is widely available. Fuel demand is down worldwide as a result of the pandemic, and with infections now surpassing 50 million globally, numerous nations, especially in Europe, are reimposing lockdowns to slow the virus’s spread. The vaccine news gave traders hope that the pandemic could be tamped down next year, which would help people resume normal life, boosting demand. “Oil particularly reacted to the news because of what it means,” said John Kilduff, partner at Again Capital in New York. “The pandemic is hitting transportation terrifically and 80% of crude oil barrels go to transportation fuel, so I think this is a logical response.” Both contracts rose more than $4 earlier in the session as traders sought to unwind bearish bets. Brent and WTI traded 148% and 139% of last session’s volumes, respectively. Pfizer said its experimental vaccine was more than 90% effective in preventing COVID-19, based on initial data, a victory in the battle against a pandemic that has forced lockdowns around the world.
Oil gains as vaccine hopes outweigh lockdown impact - Oil prices rose on Tuesday as hopes that a COVID-19 vaccine could be on the horizon outweighed the expected negative impact on fuel demand of new lockdowns to curb the virus. Brent crude futures rose 45 cents, or 1.1%, to $42.85, while U.S. West Texas Intermediate (WTI) crude futures gained 34 cents, or 0.8%, to $40.63. Both contracts jumped 8% on Monday, in their biggest daily gains in more than five months, after drugmakers Pfizer and BioNTech said an experimental COVID-19 treatment was more than 90% effective based on initial trial results. Mass rollouts, however, are likely to be months away and subject to regulatory approvals. "A viable vaccine is unequivocally game-changing for oil - a market where half of demand comes from moving people and things around," JP Morgan said in a note. "But as we have written previously, oil is a spot asset that must first clear current supply and demand imbalances before one-to-two-year out prices can rise." Prices were also boosted by comments from Saudi Arabia's energy minister, who said on Monday the Organization of the Petroleum Exporting Countries (OPEC) and its allies, together known as OPEC+, could tweak their supply cut pact if demand slumps before the vaccine is available. OPEC+ agreed to cut supply by 7.7 million barrels per day from August through December and then ease the cuts by around 2 million bpd in January. But the negative impact that renewed lockdowns in Europe are having on fuel demand, as well as rising Libyan production, kept prices in check. Traffic in London, Paris and Madrid fell sharply in November after a peak in October, according to data provided to Reuters by location technology company TomTom, that covered mobility until Sunday evening. France, the United Kingdom, Spain and Poland were under the strictest lockdowns in Europe, according to the Oxford stringency index that assesses indicators such as school and workplace closures, and travel bans. Meanwhile Libyan production has risen above 1 million bpd in recent days from 100,000 bpd in early September.
Oil prices tally back-to-back gains on optimism over vaccine - Oil futures finished higher Tuesday, building on the biggest one-day gain in more than five months on optimism over prospects for a COVID-19 vaccine, even as the continued spread of the disease undercuts fuel demand. "Oil funds got caught short as the demand outlook improves with hopes that we will get a coronavirus vaccine," said Phil Flynn, senior market analyst at The Price Futures Group. "The market was betting big on more extensions of lockdown and more demand destruction," he said in a Tuesday report. "While the vaccine is still months away, the trade must adjust for a demanding comeback that should come back faster than production." West Texas Intermediate crude for December delivery rose $1.07, or 2.7%, to settle at $41.36 a barrel on the New York Mercantile Exchange. January Brent crude , the global benchmark, added $1.21, or nearly 2.9%, at $43.61 a barrel on ICE Futures Europe. WTI jumped 8.5%, while Brent soared 7.5% on Monday after Pfizer Inc. (PFE) and Germany-based BioNTech SE (BNTX)announced their vaccine candidate was more than 90% effective in protecting people from COVID-19 in a trial. The news sparked a massive rally in stocks and other assets perceived as risky. Some analysts, however, questioned how much further upside for oil prices might be available in the near term as rising COVID-19 cases in Europe and the U.S. begin to weigh on consumer and business activity. "While a successful vaccination should ultimately support the return of oil demand to normal levels, a number of hurdles, from final approval, to the ramp-up of production, to logistics remain, but hope is that a timely development could stave off the necessity for further lockdowns in the future," wrote analysts at JBC Energy, a Vienna-based consulting firm, in a Tuesday note. The consultants said their road mobility indicator for Europe, meanwhile, had dropped to its lowest level since June, with data through Nov. 6 beginning to reflect the early stages of new lockdowns in France and Germany. Analysts at Commerzbank noted that Chinese crude oil imports fell in October to their lowest level since April, while Saudi Arabia granted further discounts to Asian customers for December shipments, "presumably because of the muted demand," they said. "At a discount of [50 cents] per barrel vs. the Oman/Dubai benchmark, customers are enjoying the highest discounts since June."
Oil rises slightly on hopes for COVID-19 vaccine, declining U.S. crude stocks - Oil prices rose slightly on Wednesday as hopes of an effective COVID-19 vaccine continued to bolster sentiment and an industry report showed U.S. crude inventories fell more than expected. Brent crude rose 0.16% to $44.53 a barrel, while U.S. West Texas Intermediate (WTI) crude settled up 9 cents, or 0.2%, to $41.45 a barrel. Both benchmarks gained nearly 3% on Tuesday. "This week's news about a coronavirus vaccine was encouraging and, alongside short-covering activity, strongly supported oil prices on Monday and Tuesday," said Giovanni Staunovo, oil analyst for UBS. The bank cautioned that European lockdowns and restored Libyan oil output could weigh on prices in the short term, but forecast oil at $60 a barrel by the end of 2021 based on the likelihood that producers would continue to rein in supply. U.S. crude stockpiles fell by 5.1 million barrels last week to about 482 million barrels, industry group data showed on Tuesday, compared with analysts' expectations in a Reuters poll for a reduction of 913,000 barrels. Both Brent and U.S. oil prices are up more than 13% this week since initial trials data showed the experimental COVID-19 vaccine being developed by Pfizer Inc and Germany's BioNTech was 90% effective. Although oil prices are supported by the positive news on the vaccine, the overall fuel demand outlook remains clouded as coronavirus restrictions are reimposed in Europe and United States. "Hopes of a return to pre-COVID normalcy next year have been given a huge boost this week. Before then, however, a difficult winter is on the cards. Infection rates are still accelerating in several parts of the world including the U.S.," said Stephen Brennock of broker PVM. Renewed restrictions in Europe and the United States to combat the coronavirus have slowed the pace of the fuel demand recovery, offsetting a rebound in Asian economies where consumption has almost returned to pre-COVID levels.
Oil CEOs believe a demand recovery is coming, but volatility is here to stay - Top energy chief executives say oil demand will recover next year, but they expect volatility to remain elevated, as the industry emerges from the reckoning of the coronavirus pandemic. "We face a lot of uncertainty," Total CEO Patrick Pouyanne told an invitation-only gathering of more than 30 senior oil and gas executives, who met virtually on Wednesday for the Abu Dhabi CEO Roundtable. "We all hope that demand will recover as quickly as possible," Pouyanne said. "Nobody knows exactly how long it will take to get out of the pandemic, when we'll have this vaccine, and how long it will take to reopen the global economy," he added. A source familiar with the discussions said the mood among the executives was more upbeat than the last meeting held in June, with news of a potential vaccine giving executives a boost of confidence. Leaders expressed a cautious optimism about the global economic recovery and discussed the need to focus on cost reductions and technology gains. "We should have optimism, and we should have a sense of reality," BP CEO Bernard Looney told the gathered executives. "We don't control the price of our product, but we do control our cost structure, our investment levels, and the efficiency of that," Looney added. "The fundamentals that we all learned as we were growing up in this industry will serve us well in the long run." The International Energy Agency (IEA) has previously said that this year's global energy demand decline will be seven times larger than the fall following the 2008/2009 financial crisis. Most analysts expect global oil demand will take several years to recover to pre-crisis levels of 100 million barrels per day. The roundtable, convened by Sultan Al Jaber, the UAE minister of industry and advanced technology and the ADNOC Group's CEO, is the highest-level forum for dialogue on key topics confronting the global energy landscape. It gives executives the opportunity to privately discuss the strength and speed of energy demand and the economic recovery. "The oil and gas industry has demonstrated remarkable resilience over the past few months, and we know the long-term fundamentals of the industry remain intact as the world will still need hydrocarbons for many decades to come," Al Jaber said.
IEA says Covid vaccine 'unlikely to ride to the rescue' of world oil market for some time— The International Energy Agency (IEA) on Thursday cut its 2020 global oil demand forecast and said it does not expect the prospect of a coronavirus vaccine to significantly boost demand "until well into next year." In its latest closely-watched monthly report, the IEA said it now expects world oil demand to contract by 8.8 million barrels per day this year. That reflects a downward revision of 0.4 million barrels from last month's assessment. The Paris-based energy agency trimmed its near-term outlook on weak historical data and a resurgence of Covid-19 cases in Europe and the U.S. For 2021, the IEA said world oil demand growth will rise by 5.8 million barrels per day, representing an upward revision of 0.3 million barrels from last month. Oil prices have notched three consecutive trading sessions of gains since Pfizer and BioNTech said Monday that early results showed their vaccine candidate was more than 90% effective in preventing Covid infections. It is hoped a safe and effective vaccine could help bring an end to the coronavirus pandemic that has claimed over 1.28 million lives worldwide. Huge challenges remain before a Covid-19 vaccine can be rolled out, but oil markets cheered the news, hoping it could lead to increased energy demand in the coming months. "However, it is far too early to know how and when vaccines will allow normal life to resume. For now, our forecasts do not anticipate a significant impact in the first half of 2021," the IEA said. International benchmark Brent crude futures traded at $43.66 a barrel on Thursday morning, down around 0.3%, while U.S. West Texas Intermediate crude stood at $41.33, roughly 0.35% lower. The IEA's latest report comes shortly before an energy alliance of some of the world's most powerful crude producers will meet to discuss the next phase of oil production policy. OPEC and non-OPEC allies, known collectively as OPEC+, are scheduled to hold talks on Dec. 1. In the face of ongoing lackluster global demand for oil, the group had agreed to a record supply cut of 9.7 million barrels per day starting on May 1. The cut was subsequently scaled back to 7.7 million in August and OPEC+ has said it plans further tapering next year. "With a Covid-19 vaccine unlikely to ride to the rescue of the global oil market for some time, the combination of weaker demand and rising oil supply provides a difficult backdrop to the meeting of OPEC+ countries," the IEA said. "Unless the fundamentals change, the task of re-balancing the market will make slow progress."
Oil falls on coronavirus surge, unexpected U.S. crude stockpile rise (Reuters) - Oil prices fell on Thursday, weighed down by the surge in coronavirus cases that is hampering the global economy, along with an unexpected rise in U.S. crude stockpiles. Oil futures tracked with U.S. equities, which also fell on pandemic concerns. Europe is grappling with a sharp increase in infections and new social restrictions. In the United States, new cases have surpassed 100,000 per day for several days, and more than a dozen states have doubled their caseloads in the last two weeks. Brent crude fell 27 cents to settle at $43.53 a barrel, while U.S. West Texas Intermediate (WTI) crude fell 33 cents to settle at $41.12 a barrel. “When stocks gave up gains, oil followed,” . “It’s a very nervous market.” U.S. government data added to the bearishness, as crude inventories rose by 4.3 million barrels last week, compared with an expected fall of 913,000 barrels. Both contracts rallied this week after data showed an experimental coronavirus vaccine being developed by Pfizer and BioNTech was 90% effective, raising hopes that the pandemic will be brought under control. Even with that development, though, oil demand remains shaky. The International Energy Agency (IEA) said global oil demand was unlikely to rise significantly until well into 2021, if the vaccine is successful.
Oil Prices Falter on Surprise Build and Fed Warning -- Oil dropped after an unexpected increase in U.S. stockpiles and a Federal Reserve warning that a vaccine may not be enough to get the economy back on track. Futures in New York fell 0.8% after Federal Reserve Chair Jerome Powell’s remarks, erasing gains of as much as 1.8% in a volatile session. American’s crude inventories increased by 4.28 million barrels last week, the government said Thursday, while most analysts surveyed by Bloomberg expected a decline. Slowing refining activity also didn’t bode well for oil demand. “We won’t be getting stimulus until at least January, so that’s hit all the markets,” said John Kilduff, a partner at Again Capital LLC. “Oil needs the economy to be revived and supported to get people spending and traveling at least to a degree.” The International Energy Agency cut its forecast for global oil demand earlier, saying the coronavirus vaccine breakthrough won’t quickly revive markets. The constantly evolving state of demand recovery taking place at varying speeds around the world adds to the challenges facing OPEC+ when it meets at the end of the month to decide on its output strategy. While renewed lockdowns in Europe have coincided with weakening road travel, particularly in France and the U.K., it’s a mixed demand picture globally. India -- whose consumption dwarfs both countries -- posted its first annual increase since February and a return in Chinese buying interest is helping spur an oil buying frenzy. Earlier in the trading session, crude rose after OPEC+ signaled it might not phase out its output curbs so fast next year. “Vaccine or not, OPEC’s not really counting on oil demand to recover here in the next six months.” West Texas Intermediate for December delivery fell 33 cents to settle at $41.12 a barrel. Brent for January settlement lost 27 cents to $43.53 a barrel. Despite the surprise build in U.S. crude stockpiles, the EIA report also showed declines in both gasoline and distillate inventories. Distillate stockpiles dropped for eight straight weeks, pushing supplies down from a decade seasonal high.
Oil falls on rising Libya output, coronavirus surge (Reuters) - Oil prices fell about 2% on Friday, pressured by swelling output from Libya and fears that rising coronavirus infections may slow the recovery in the global economy and fuel demand. Hopes for a vaccine kept crude futures on track for a second straight weekly gain. Brent crude LCOc1 fell 75 cents, or 1.7%, to settle at $42.78 a barrel. U.S. West Texas Intermediate (WTI) crude futures CLc1 fell 99 cents, or 2.4%, to end the session at $40.13 a barrel. For the week, both notched gains of more than 8%. Libyan oil production has risen to 1.2 million barrels per day (bpd), a Libyan oil source told Reuters, up from the 1.0 million bpd reported on Nov. 7 by the country’s National Oil Corp. Signs of rising production in the U.S. added to bearish sentiment. U.S. oil rigs rose 10 to 236 this week, according to Baker Hughes data, their highest since May. Also pressuring prices, U.S. government data showed crude inventories rose by 4.3 million barrels last week. Analysts had expected a draw of 913,000 barrels. “In essence, some of the feel-good factor from the Pfizer vaccine has worn off and disappointing EIA figures have created a bit of a downward correction,” Harry Tchilinguirian, head of commodity research at BNP Paribas, said. “However, OPEC+ is prepared to tweak its production and we’re still waiting for the trial results of other vaccines that may be easier to distribute since they won’t need such cold storage.” New coronavirus infections in the United States and elsewhere are at record levels and tightening restrictions should lead to fuel demand recovering more slowly than many had hoped.
Oil Prices End the Week Higher Despite Hiccups -- Oil declined for a second session as rising Covid-19 cases threatened to derail demand with tougher restrictions in major U.S. cities on the horizon. Futures fell 2.4% in New York on Friday, but still posted the largest weekly gain in a month as optimism from news of a potential Covid-19 vaccine breakthrough jolted markets earlier in the week. Despite the measure of hope for the long-term, U.S. cities from the West to East coasts have imposed stricter measures to slow surging case counts, raising concerns that the virus will further crimp demand for fuel. Gasoline futures also slumped. “In the U.S., the virus spread is exponential and right now many states are probably going to be forced to deliver stricter measures and return to lockdowns,” . “That’s going to cripple economic activity and put further pressure in the short-term as far as the crude demand outlook goes.” Before concerns over lockdowns set in, futures also got support from signs the OPEC+ alliance is inching closer to delaying a planned output increase in January. But downbeat demand forecasts from the International Energy Agency and OPEC have clouded hopes of a recovery. At the same time, governors of states along the U.S. West Coast issued travel advisories, following measures recently imposed in New York and Chicago. Meanwhile, crude supply in Libya is rising. The country’s production rose to 1.145 million barrels a day on Friday, according to a spokesman for its state-run National Oil Corp. Prices West Texas Intermediate for December delivery lost 99 cents to settle at $40.13 a barrel. The contract rose 8.1% this week. Brent for January settlement slid 75 cents to $42.78 a barrel Gasoline for December delivery declined 2.7% to $1.1254 a gallon In Europe, where motorway traffic is down by almost 50% in some countries, demand is stuttering anew. That’s impacting crude, with six supertankers of unwanted North Sea oil continuing to float in the region. Meanwhile, vehicle miles traveled on U.S. highways fell last week in another sign Americans are keeping off the roads amid the pandemic. Refining margins were left behind in the oil market rally that lifted not only headline prices this week, but also led to strong moves along the forward curve. The combined refining margin for gasoline and diesel, which is a rough gauge for the profitability of processing a barrel of oil, slid on Friday for a third straight session to near $8 a barrel. Refineries typically need the so-called crack to be above $10 a barrel to turn a profit from processing crude.
Coronavirus pandemic intensifies humanitarian disaster in Yemen - In war-torn Yemen—devastated by five years of a US- and EU-backed war led by Saudi Arabia—the coronavirus pandemic is exhibiting its murderous potential. Doctors there report a death rate of 20 to 30 percent among those infected. Intensive care physician Tankred Stöbe from the aid organization Doctors Without Borders told the German newspaper Tagesspiegel of the dramatic consequences of the pandemic . The pandemic, he noted, has swept through the bitterly poor and war-ravaged country “like a deadly desert storm.” Stöbe estimates a 30 percent mortality rate among COVID-19 patients, the highest in the world. A significant lack of testing renders the official figures—just over 2,000 confirmed cases and 600 deaths—meaningless. “The vast majority of patients have suffocated in their homes without being counted, diagnosed or treated.” Many Yemenis live far from a clinic and are left to fend for themselves if infected with the coronavirus. The virus spreads virtually unchecked. “There is hardly a family that has not been affected by the pandemic,” Stöbe reports. Doctors Without Borders erected a specialized COVID-19 clinic whose 40 beds were immediately filled. “The mortality was very high because patients came too late,” Stöbe explained. “The average length of stay was five days—but not because people recovered, but because they died.” The clinic contends with a chronic shortage of personnel and materials. Moreover, the staff must transport oxygen bottles across residential districts devastated by war. The high mortality rate is primarily due to the preexisting, unimaginable humanitarian catastrophe in the country from a years-long civil war and an imperialist-backed bombing campaign. Saudi Arabia has waged an unrelenting air war in Yemen since March 2015 aimed at toppling the Huthi rebel government and reimposing the puppet regime of imperialist stooge Abd Rabbuh Mansur Hadi. The United States, France, Great Britain and Germany have all supported this murderous war, directly or indirectly. As such, the German government has exported over €1 billion in weaponry to countries participating in the war. Stöbe described the situation now unfolding in Yemen as an “unbelievable tragedy.” Bombing and live fire continue on a daily basis: “Tens of thousands have already died. Millions have been displaced.” Were the criteria and legal principles of the Nuremberg Trials to be applied to Yemen, the politicians responsible for these crimes against humanity would be tried in court and locked behind bars. Sentences handed down in Nuremberg after the Second World War sent the surviving leaders of the Third Reich to the gallows or a lifetime in prison.
Russia, Turkey negotiate cease-fire in Armenian-Azeri war over Karabakh - On November 10, a cease-fire backed by Moscow and Ankara went into effect in the six-week war between Armenia and Azerbaijan over the disputed Nagorno-Karabakh region. Unlike previous truces negotiated by Russian, French and US officials which collapsed immediately, this cease-fire has so far held. This appears to be largely because, unlike previous ceasefires, it has support from the Azeri government and its main international backer, Turkey. The two former Soviet republics have repeatedly waged fratricidal wars over the Karabakh, which first broke out in 1988 in the run-up to the Stalinist regime’s 1991 dissolution of the Soviet Union. Whereas Armenia took over the Nagorno-Karabakh in the 1988-1994 war, however, the current cease-fire agreed by Russian, Armenian and Azeri officials makes substantial concessions to Azeri territorial demands, handing much of the Karabakh to Azerbaijan. Recent weeks saw major Azeri advances, relying on devastating strikes from Turkish and Israeli high-altitude drones. Evading Armenia’s older air defense systems with tactics worked out against Syrian and Russian forces in the decade-long NATO proxy war in Syria, they destroyed Armenian missile batteries, artillery and armored vehicles. After Azeri forces reported this weekend that they had captured Shusha, Nagorno-Karabakh’s second-largest city, Armenia agreed to a ceasefire. According to the truce, Armenian and Azeri troops are to initially remain on their current positions. As 1,960 Russian peacekeepers with armored vehicles and equipment deploy along the contact line, however, Armenian troops will withdraw. Armenia will retain those parts of the Karabakh it currently holds, including the capital, Stepanakert. It must also return to Azerbaijan the districts of Agdam and Kalbajar, which it took over during the 1988-1994 war, by November 20. The deal also calls to secure complex land routes through the mountainous region. Azerbaijan is to guarantee the security of the Lachin Corridor linking Stepanakert to Shusha and then to Armenia. The corridor will be patrolled by Russian peacekeepers. Armenia will guarantee the security of land routes from Azerbaijan via Armenia to the Nakhchivan Autonomous Republic, a landlocked Azeri-administered enclave separated from Azerbaijan by Armenian territory.
Turkish and Israeli Drones Enable Azerbaijan's Decisive Victory Over Armenia -- Defense analysts believe that Turkish and Israeli drones have helped Azerbaijan achieve decisive victory against Armenia. "Azerbaijan’s drones owned the battlefield in Nagorno-Karabakh — and showed future of warfare" says the Washington Post headline as tweeted by drone warfare expert Franz-Stefan Gady. Low-cost Azeri drones killed thousands of Armenian soldiers in Nagorno-Karabakh and destroyed hundreds of Armenian tanks and artillery pieces, giving a huge advantage to Azerbaijan and forcing the Armenian surrender. Armenian Prime Minister accused Pakistan of sending troops to help Azerbaijan in the conflict. Pakistan rejected Armenian allegations and congratulated Azerbaijan on its victory. Azeris deployed a variety of drones in their war against Armenia to wrest control of Nagorno-Karabakh, a region that is legally part of Azerbaijan but controlled by Armenians. Azeris used Turkish Bayraktar drones which are large and reusable drones. They also Kamikaze drones made by Israel which are small and designed for one-time use in destroying targets. The small Israeli-made suicide drones are sometimes also referred to as "loitering munitions". Michael Kofman, military analyst and director of Russia studies at CNA, a defense think tank in Arlington, Va. is quoted by the Washington Post as saying, “Drones offer small countries very cheap access to tactical aviation and precision guided weapons, enabling them to destroy an opponent’s much-costlier equipment such as tanks and air defense systems.” “An air force is a very expensive thing,” he added. “And they permit the utility of air power to smaller, much poorer nations.”In 2019, dozens of cheap drones were deployed against Abqaiq and Khurais oil fields to cut Saudi Aramco's production by half, according to multiple media reports. Saudi and US officials have blamed Iran for the destructive hit. This was the first time that cheap drone swarms loaded with explosives dodged sophisticated air defense systems to hit critical infrastructure targets in the history of warfare.
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