global oil supply near December's demand; US distillates exports at a 40 mo low​; gasoline production at a 34 week low​

oil prices managed an increase for the tenth time out of the past eleven weeks despite a sharp selloff on Friday, as strength in equities, a weaker dollar, and strong Chinese demand bouyed prices...after rising 7.7% to a ten month high of $52.24 a barrel last week after the Saudis unilaterally cut their oil output, the contract price of US light sweet crude for February delivery opened higher on Monday but quickly turned lower as lockdowns spread and China saw its biggest daily increase in virus infections in more than five months, but came back to close a penny higher at $52.25 a barrel as pressure from a rising dollar and worries over a COVID-related hit to demand was overshadowed by optimism over prospects for near-term exports...oil prices started lower early Tuesday as traders remained concerned about climbing coronavirus cases globally, but turned higher to settle with a gain of 96 cents at $53.21 a barrel, as wall street rallied and the dollar weakened, raising the appeal of commodities priced in the currency....oil prices then rose overnightafter the API reported a surprisingly large crude inventory drawdown and hence opened higher Wednesday, but couldn't hold those gains even after the EIA also reported a larger than expected crude draw, ending down 30 cents at $52.91 a barrel after the U.S. dollar gained ground and inventories of gasoline and distillates rose more than expected...oil prices moved higher again on Thursday, boosted by a weaker dollar and bullish signs from Chinese import data and ended 66 cents, or 1.3%, higher at an 11 month high of $53.57 a barrel, buoyed by the ongoing Covid-19 vaccine rollout and expectations that the Biden administration’s proposed stimulus package would improve demand for crude...boosted by strong import data from China, oil prices opened higher on Friday, but quickly faded as the dollar rose and China ramped up lockdown measures to control its latest outbreak and tumbled more than 2% to end the session at $52.36 a barrel, down $1.21 on the day, but still up 12 cents on the week, as vaccine breakthroughs and Saudi Arabia’s earlier pledge to deepen output cuts continued to support prices...

natural gas price also saw a small increase this week as traders ​continue to bet that a polar air mass​ will arrive later this month....after rising 6.3% to $2.700 per mmBTU last week on forecasts for colder weather and greater heating demand later in January, the contract price of natural gas for February delivery opened 10 cents lower on Monday, following forecasts for mild weather and diminished heating demand, but rebounded in afternoon trading to finish 4.7 cents higher at $2.747 per mmBTU amid anticipation of a late-month Polar Vortex and a surge in frigid temperatures...natural gas prices surged 15 cents or more than 5%​​ early on Tuesday amid expectations for that intensifying cold air outbreak, but reversed in the afternoon when models showed “not quite as cold air into Western Canada, thereby pushing less impressive subfreezing air into the U.S. as well” in late January, with gas prices settling for a six-tenths of a cent gain at $2.753 per mmBTU...conflicting forecasts led to an erratic day of trading on Wednesday that saw natural gas prices swing between gains and losses several times before settling 2.6 cents lower at $2.727 per mmBTU, and then gas prices fell to their lowest in a week on Thursday on forecasts for milder weather and less heating demand over the next two weeks than was previously expected, even as the draw of ​natural ​gas from storage was larger than expected...on Friday, however, forecasts shifted back to greater expectations for a severe polar outbreak and stronger heating demand by late January, boosting gas prices by 7.1 cents to $2.737 per mmBTU, thus finishing 3.7 cents, or 1.4% higher on the week..

the natural gas storage report from the EIA for the week ending January 8th indicated that the quantity of natural gas held in underground storage in the US decreased by 134 billion cubic feet to 3,196 billion cubic feet by the end of the week, which left our gas supplies 126 billion cubic feet, or 4.1% higher than the 3,070 billion cubic feet that were in storage on January 8th of last year, and 218 billion cubic feet, or 7.3% above the five-year average of 2,978 billion cubic feet of natural gas that have been in storage as of the 8th of January in recent years....the 134 billion cubic feet that were drawn out of US natural gas storage this week was more than the average forecast of a 123 billion cubic foot withdrawal from an S&P Global Platts survey of analysts, ​and ​still more than the 126 billion cubic feet withdrawal from natural gas storage seen during the corresponding week of a year earlier, but it was quite a bit less than the average withdrawal of 161 billion cubic feet of natural gas that have typically been pulled out of natural gas storage during the same week over the past 5 years​...

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending January 8th indicated that despite an increase in oil imports and a decrease in oil exports, we still had to withdraw oil from our stored commercial ​crude ​supplies for the 7th time in the past eight weeks and for the 18th time in the past twenty-five weeks...our imports of crude oil rose by an average of 870,000 barrels per day to an average of 6,239,000 barrels per day, after rising by an average of 43,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 621,000 barrels per day to 3,011,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,228,000 barrels of per day during the week ending January 8th, 1,491,000 more barrels per day than the net of our imports minus our exports during the prior week...over the same period, the production of crude oil from US wells was reportedly unchanged at 11,000,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 14,228,000 barrels per day during this reporting week... 

meanwhile, US oil refineries reported they were processing 14,650,000 barrels of crude per day during the week ending January 8th, 274,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA's surveys indicated that a net of 464,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US....so based on that reported & estimated data, this week's crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 43,000 barrels per day more than what our oil refineries reported they used during the week...to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (-43,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a balance sheet fudge factor that they label in their footnotes as "unaccounted for crude oil", thus suggesting that there must have been an error or errors of that magnitude in the oil supply & demand figures that we have just transcribed....however, since last week's line 13 balance sheet adjustment was +495,000 barrels per day, indicating a week over week difference of 537,000 barrels per day in the fudge factor, the difference between those errors means any week over week comparisons of oil supply and demand figures reported here are pretty useless...still, since most everyone treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill or complete wells, we'll continue to report them as published, just as they're watched & believed to be accurate by most everyone in the industry.....(for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....

further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 5,625,000 barrels per day last week, which was still 14.9% less than the 6,611,000 barrel per day average that we were importing over the same four-week period last year.....the 464,000 barrel per day net withdrawal from our crude inventories was due to a 464,000 barrels per day withdrawal from our commercially available stocks of crude oil, while the oil supplies in our Strategic Petroleum Reserve remained unchanged....this week's crude oil production was reported to be unchanged at 11,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at 10,500,000 barrels per day, while a 3,000 barrel per day decrease to 511,000 barrels per day in Alaska's oil production had no impact on the rounded national total...last year's US crude oil production for the week ending January 10th was rounded to 13,000,000 barrels per day, so this reporting week's rounded oil production figure was 15.4% below that of a year ago, yet still 30.5% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016...    

meanwhile, US oil refineries were operating at 82.0% of their capacity while using those 14.650,000 barrels of crude per day during the week ending January 8th, up from 80.7% of capacity during the prior week, and matching the highest refinery utilization rate since March....however, since US refinery utilization averaged the lowest on record through 2020, the 14,650,000 barrels per day of oil that were refined this week were still 13.7% fewer barrels than the 16,973,000 barrels of crude that were being processed daily during the week ending January 10th of last year, when US refineries were operating at 92.2% of capacity...

despite the increase in the amount of oil being refined, gasoline output from our refineries was lower for the 6th time in 8 weeks, decreasing by 498,000 barrels per day to a 34 week low of 7,512,000 barrels per day during the week ending January 8th, after our gasoline output had decreased by 1,181,000 barrels per day over the prior week...and since our gasoline production was just beginning to recover from a multi-year low in the wake of this Spring's covid lockdowns, that further ​drop meant that this week's gasoline output was 19.1% less than the 9,281,000 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 124,000 barrels per day to 4,661,000 barrels per day, after our distillates output had increased by 146,000 barrels per day over the prior week....and since it was also just coming off a three year low, our distillates' production was 10.5% less than the 5,205,000 barrels of distillates per day that were being produced during the week ending January 10th, 2020...

even with the big drop in our gasoline production, our supply of gasoline in storage at the end of the week increased for the seventh time in nine weeks, for 11th time in 27 weeks, rising by 4,​395,000 barrels to 245,476,000 barrels during the week ending January 8th, after our gasoline inventories had ​increased by 4,519,000 barrels over the prior week...our gasoline supplies increased ​again ​this week even as the amount of gasoline supplied to US users increased by 91,000 barrels per day to 7,532,000 barrels per day, because our exports of gasoline fell by 285,000 barrels per day to 598,000 barrels per day, while our imports of gasoline fell by 62,000 barrels per day to 383,000 barrels per day....but even after this week's inventory increase, our gasoline supplies were 5.0% lower than last January 10th's gasoline inventories of 258,287,000 barrels, while about 1% above the five year average of our gasoline supplies for this time of the year... 

meanwhile, with the increase in our distillates production, our supplies of distillate fuels increased for the 6th time in 7 weeks and for the 22nd time in the past year, rising by 4,786,000 barrels to 152,029,000 barrels during the week ending January 8th, after our distillates supplies had increased by 6,390,000 barrels during the prior week....our distillates supplies rose again this week even though the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 668​,​000 barrels per day to 3,609,000 barrels per day, because our exports of distillates fell by 518,000 barrels per day to a 40 month low of 714,000 barrels per day while our imports of distillates rose by 44,000 barrels per day to 346,000 barrels per day....after this week's inventory increase, our distillate supplies at the end of the week were 10.9% above the 147,221,000 barrels of distillates that we had in storage on January 10th, 2020, and about 9% above the five year average of distillates stocks for this time of the year...

finally, even with the increase in our oil imports and the decrease in our oil exports, our commercial supplies of crude oil in storage (not including the commercial oil being stored in the SPR) fell for the 20th time in the past thirty-one weeks but for just the 23rd time in the past year, decreasing by 8,010,000 barrels, from 485,459,000 barrels on January 1st to 482,211,000 barrels on January 8th...but even after that decrease, our commercial crude oil inventories were still about 9% above the five-year average of crude oil supplies for this time of year, and about 47% above the prior 5 year (2011 - 2015) average of our crude oil stocks as of the second weekend of January, with the disparity between those comparisons arising because it wasn't until early 2015 that our oil inventories first topped 400 million barrels....since our crude oil inventories had generally been rising over the past two years, except for this autumn and during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of January 8th were still 12.5% more than the 428,511,000 barrels of oil we had in commercial storage on January 10th of 2020, and also 10.3% more than the 437,055,000 barrels of oil that we had in storage on January 11th of 2019, and 16.9% above the 412,654,000 barrels of oil we had in commercial storage on January 12th of 2018...  

OPEC's Monthly Oil Market Report

Thursday of this past week saw the release of OPEC's January Oil Market Report, which covers OPEC & global oil data for December, and hence it gives us a picture of the global oil supply & demand situation over the fifth month of the extended agreement between OPEC, the Russians, and other oil producers, wherein they have agreed to cut production by 7.7 million barrels a day from the 2018 peak, reduced from the 9.7 million barrels a day cuts they had imposed on themselves during May, June and July....before we look at what this month's report shows us, we should again caution that estimating oil demand while the course of the Covid-19 pandemic remains uncertain is pretty speculative, and hence the demand estimates we'll be reporting this month should again be considered as having a much larger margin of error than we'd expect from this report during stable and hence more predictable periods.. 

the first table from this monthly report that we'll check is from the page numbered 48 of this month's report (pdf page 58), and it shows oil production in thousands of barrels per day for each of the current OPEC members over the recent years, quarters and months, as the column headings indicate...for all their official production measurements, OPEC uses an average of estimates from six "secondary sources", namely the International Energy Agency (IEA), the oil-pricing agencies Platts and Argus, ‎the U.S. Energy Information Administration (EIA), the oil consultancy Cambridge Energy Research Associates (CERA) and the industry newsletter Petroleum Intelligence Weekly, as a means of impartially adjudicating whether their output quotas and production cuts are being met, to thereby avert any potential disputes that could arise if each member reported their own figures...

as we can see from the above table of their oil production data, OPEC's oil output increased by 278,000 barrels per day to 25,362,000 barrels per day during December, from their revised November production total of 25,083,000 barrels per day...however, that November output figure was originally reported as 25,109,000 barrels per day, which thus means that OPEC's October production was revised 26,000 barrels per day lower with this report, and hence December's production was, in effect, a rounded 252,000 barrel per day increase from the previously reported OPEC production figure (for your reference, here is the table of the official November OPEC output figures as reported a month ago, before this month's revisions)...

from the above table, we can see that a 136,000 barrels per day increase in Libyan production, an increase of 76,000 barrels per day in Iraq's output, and a production increase of 63,000 barrels per day from the Emirates were the major factors in OPEC's December output increase...while Libyan production is still recovering from their years of civil strife, Iraq and UAE were the two major producers who objected to the extension of the current production cuts in meetings in early December...that contentious meeting resulted in an OPEC agreement to increase production by 500,000 barrel per day in January, so it appears that Iraq, the Emirates, and a few others may be jumping the gun on that increase...

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 early in the pandemic, 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 to 7.7 million barrels per day for August and subsequent months, which is thus the agreement that covers OPEC's output in this month's report...however, war torn Libya and US sanctioned OPEC members Iran and Venezuela were exempt from the production cuts imposed by that agreement, and as you can see above, together with Iraq and the Emirates, those exempt members account for this month's production increase... 

since there has never seemed to be a published table or listing available of how much each OPEC member was expected to produce under the eased production cuts of August through December, we've been including the table that shows the October 2018 reference production for each of the OPEC members (as well as other producers party to the mid-April agreement), as well as the production level each of those producers was expected to cut their output to during May, June, and July...from the following table, we can easily compute the production quotas that each of the OPEC members was expected to hold to in December:

the above table shows the oil production baseline in thousands of barrel per day from which each of the oil producers was to cut from in the first column, a figure which is based on each of the producer's October 2018 oil output, ie., a date before the past year's and this year's output cuts took effect, and coincidently the highest ​monthly ​production of the era for most of the producers ​who are ​party to these cuts; the second column shows how much each participant had originally committed to cut during May and June in thousands of barrel per day, which was 23% of the October 2018 baseline for all participants except for Mexico, while the last column shows the production level each participant had agreed to after that cut...the producer's agreement for August through the end of this year amends the above such that each member would be allowed to ​reduce their production cut shown above (ie, the "voluntary adjustment" shown above) by 20%...for example, Algeria's "cut" was expected to be 241,000 barrels per day from May thru July, which would reduce their oil production to 816,000 barrels per day over that period...under the new agreement for August and the following months, Algeria would reduce their "cut" by 20%, or to 193,000 barrels per day, thus allowing them to produce 864,000 barrels per day during December...offhand, by comparing this table's allocation ​plus​ ​20% to the initial OPEC production table above, it appears that only Iraq, who's December production should have been limited to 3,804,000 barrels per day, is the only OPEC member to have exceeded their production quota for December...

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 January 2019 to December 2020, and it comes from page 50 (pdf page 60) of the November OPEC Monthly Oil Market Report....on this graph, the cerulean blue bars represent OPEC's monthly oil production in millions of barrels per day as shown on the left scale, while the purple graph represents global oil production in millions of barrels per day, with the metrics for global output shown on the right scale.... 

after the reported 278,000 barrel per day increase in OPEC's production from what they produced a month earlier, OPEC's preliminary estimate indicates that total global liquids production increased by a rounded 58 million barrels per day to average 92.93 million barrels per day in December, a reported increase which apparently came after November's total global output figure was revised down by 180,000 barrels per day from the 92.53 million barrels per day of global oil output that was reported a month ago, as non-OPEC oil production rose by a rounded 300,000 barrels per day in December after that revision, with oil production increases of 290,000 barrels per day from the OECD countries accounting for almost all of the non-OPEC production increase in December... after that increase in December's global output, the 92.93 million barrels of oil per day that were produced globally in December were 8.23 million barrels per day, or 8.1% less than the revised 101.16 million barrels of oil per day that were being produced globally in December a year ago, which was the 12th month of OPECs first round of production cuts (see the January 2020 OPEC report (online pdf) for the originally reported December 2019 details)...with this month's increase in OPEC's output, their December oil production of 25,362,000 barrels per day was at 27.3% of what was produced globally during the month, ​an increase from their revised 27.2% share of the global total in November.... OPEC's December 2019 production, which included 538,000 barrels per day from former OPEC member Ecuador, was reported at 29,444,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 3,544,000, or 12.2% fewer barrels per day of oil in December 2020 than what they produced a year earlier, when they accounted for 29.4% of global output... 

However, even after the increase in OPEC's and global oil output that we've seen in this report, there was still a ​mode​s​t s​hortfall in the amount of oil being produced globally during the month, as this next table from the OPEC report will show us...   

the above table came from page 25 of the December OPEC Monthly Oil Market Report (pdf page 35), and it shows regional and total oil demand estimates in millions of barrels per day for 2019 in the first column, and OPEC's estimate of oil demand by region and globally quarterly over 2020 over the rest of the table...on the "Total world" line in the fifth column, we've circled in blue the figure that's relevant for December, which is their estimate of global oil demand during the fourth quarter of 2020...

OPEC ​has estimated that during the 4th quarter of this year, all oil consuming regions of the globe ​had been using an average of 93.56 million barrels of oil per day, which is a 900,000 barrels per day upward revision from the 93.47 million barrels of oil per day they were estimating for the 4th quarter a month ago (note that we have encircled this month's revisions in green), still 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 92.93 million barrels million barrels per day during December, which would imply that there was a shortage of around 370,000 barrels per day in global oil production in December when compared to the demand estimated for the month..

In addition to figuring December's global oil supply shortfall that's evident in this report, the downward revision of 180,000 barrels per day to November's global oil output that's implied in this report, plus the 90,000 barrels per day upward revision to fourth quarter demand noted above, means that the 940,000 barrels per day global oil output shortage we had previously figured for November would now be revised to a shortage of 1,210,000 barrels per day..,similarly, the 2,420,000 barrels per day global oil output shortage we had previously figured for October would now be revised to a shortage of 2,510,000 barrels per day once we account for the the 90,000 barrels per day upward revision to fourth quarter demand...

However, note that in green we've also circled an downward revision of 200,000 barrels per day to third quarter demand, a quarter when there was also shortage of oil production as compared to demand....that downward revision to demand means that the 600,000 barrels per day global oil output shortage we had previously figured for September would now be revised to a shortage of 400,000 barrels per day, that the 1,730,000 barrels per day global oil output shortage we had previously figured for August would now be revised to a shortage of 1,530,000 barrels per day, and that the 3,050,000 barrels per day global oil output shortage we had previously figured for July would now be revised to an estimated shortage of 2,850,000 barrels per day...

Note that we've also circled a downward 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 downward revision to demand, our previous estimate that there was a surplus of 4,900,000 barrels per day in June would now be revised up to a 4,920,000 barrels per day surplus, that the oil surplus of 7,680,000 barrels per day that we had previously figured for May would have to be revised to a surplus of 7,700,000 barrels per day, and that the 16,430,000 barrels per day surplus that we had previously figured for April would have to be revised to a surplus of 16,450,000 barrels per day...  

Finally, note there was also an upward revision of 200,000 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 17,750,000 barrels per day we had previously figured for March would have to be revised to a still record global oil surplus of 17,550,000 barrels per day, that the 1,870,000 barrel per day global oil production surplus we had figured for February would now be a 1,670,000 barrel per day global oil output surplus, and that the 900,000 barrel per day global oil output surplus we last had for January would now be revised to a 700,000 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 17th time in the past eighteen weeks during the week ending January 15th, but for just the 19th time in the past 44 weeks, and hence it is still down by 53.0% over that forty-four week period....Baker Hughes reported that the total count of rotary rigs running in the US rose by 13 to 373 rigs this past week, which was still down by 423 rigs from the 796 rigs that were in use as of the January 10th report of 2020, and was also still 31 fewer rigs than the all time low rig count prior to 2020, and 1,556 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business....

The number of rigs drilling for oil increased by 12 rigs to 287 oil rigs this week, after rising by 8 oil rigs the prior week, leaving us with 386 fewer oil rigs than were running a year ago, and still less than a fifth 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 was up by 1 to 85 natural gas rigs, which was still down by 35 natural gas rigs from the 120 natural gas rigs that were drilling a year ago, and just 5.3% 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 or gas, one rig classified as 'miscellaneous' continue​d​ to drill in Lake County, California this week, while a year ago there were three such "miscellaneous" rigs deployed...

The Gulf of Mexico rig count was down by 1 to 16 rigs this week, with 15 of those rigs drilling for oil in Louisiana's offshore waters, up from 14 last week, and one drilling for oil offshore from Texas, down from 3 a week ago...the total was 4 fewer Gulf rigs than the 20 rigs drilling in the Gulf a year ago, when 18 Gulf rigs were drilling for oil offshore from Louisiana, one rig was drilling for natural gas in the Mississippi Canyon offshore from Louisiana, and one rig was drilling for oil offshore from Texas...since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week's national offshore rig figures are equal to the Gulf rig counts....however, in addition to those rigs offshore, there are now 3 rigs drilling through inland bodies of water this week, one in Lafourche Parish, south of New Orleans, another in St Mary parish, farther west along the southern Louisiana coast, and ​an​other in Chambers County, Texas, just east of Houston, while a year ago there was just one rig drilling on US inland waters..

The count of active horizontal drilling rigs was up by 12 to 332 horizontal rigs this week, which was still 377 fewer horizontal rigs than the 709 horizontal rigs that were in use in the US on January 17th of last year, and less than a quarter of the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, the vertical rig count was up by one to 19 vertical rigs this week, but those were also still down by 24 from the 43 vertical rigs that were operating during the same week a year ago....meanwhile, the directional rig count was unchanged at 22 directional rigs this week, and those were still down by 22 from the 44 directional rigs that were in use on January 17th of 2020....

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 January 15th, the second column shows the change in the number of working rigs between last week's count (January 8th) and this week's (January 15th) count, the third column shows last week's January 8th 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 17th of January, 2020..    

even as there were more changes in drilling activity this week than recently, most of the new rigs were concentrated in the Permian...checking for the details on the Permian in Texas from the Rigs by State file at Baker Hughes, we find that there were 8 new rigs added in Texas Oil District 8, which corresponds to the core Permian Delaware, and another rig was added in Texas Oil District 8A, which encompasses the northern counties in the Permian Midland, thus indicating that the Permian basin in Texas saw an increase of 9 rigs this week...since the national Permian rig count was up by 10, that means that the rig that was added in New Mexico must have been added in the far west reaches of the Permian Delaware, to account for the national Permian basin rig increase...elsewhere in Texas, there were 2 rigs added in Texas Oil District 1, which would account for the two rig increase in the Eagle Ford shale, and another rig added in Texas Oil District 10, which is usually indicative of a Granite Wash rig increase, but not this week, since the Granite Wash​ basin​ still shows no activity...rigs removed from Texas include one that ​had been drilling for oil offshore, and another pulled from Texas Oil District 6, which had been drilling in the Haynesville shale....the Haynesville shale still sho​w​s an increase, however, because two rigs were added in that basin in northern Louisiana; the other Louisiana rig increases were on inland waters and offshore...elsewhere, 2 oil rigs were added in Colorado, in the Niobrara chalk of the Rockies' front range, while oil rigs were pulled out of the Williston basin in Norht Dakota and from an unnamed basin in Oklahoma at the same time....this week's natural gas rig increase was in the aforementioned Haynesville shale, while the Marcellus shale showed no ​net ​change because while two rigs were pulled out of the Marcellus in Pennsylvania, two rigs were added in the Marcellus in West Virginia at the same time..

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Akron wants to sell mineral rights for the fracking of 475 acres of water shed land - Akron Beacon Journal - Akron Council has given initial approval of a deal to allow horizontal drilling and fracking under 475 acres of public land at the La Due Reservoir, which is upstream from the city’s main drinking water supply along the Cuyahoga River.“We’ve been working on this for probably a year and we’ve been watching the oil prices,” Public Service Director Chris Ludle told Council Monday during a committee meeting.If approved again by all of council on Jan. 25, the deal would add another red triangle to a map almost completely covered by red triangles — each representing an oil or gas well in Geauga County where the reservoir is located.Akron owns and manages about 33% of the Cuyahoga River shoreline through Portage and Geauga counties. The city protects wildlife and wetlands, manages the forestry and keeps the water shed fenced as part of a broader effort to safeguard the drinking supply. The gas well deal would allow the city to continue these environmental efforts while tapping into revenue streams locked thousands of feet below the surface where the Utica and Marcellus shale formation overlap in eastern Ohio.The deal would give the city a one-time payment of $500 and acre, or $237,500 total, Ludle said. In addition, the city would get 15% of the royalties for any producing wells. Drilling would not be permitted on the city’s 475 acres just south of the reservoir. Instead, the city said the operator, DP Energy Auburn LLC, would use adjacent, private property to drill down then turn horizontally to reach potential reserves below the city land. If the wells are dry, the contract says they would need to be capped after three years, at which point the city would take back the mineral rights.  DP Energy Auburn LLC could not be reached for comment. According to Ohio Secretary of State records, the company was incorporated to do business in Ohio on Jan. 1 by Patrick D’Andrea, an Akron attorney whose website says he “handles oil and gas, real estate development, and personal injury cases.”  Ludle said the 475 acres in question represent 3% of the public land around the reservoir. The deal would not allow the drilling company to access the land unless given city approval. And there would be no storage tanks, equipment or access roads installed on the city land.

Utica Shale Academy receives new industrial maintenance equipment— The new industrial maintenance equipment is ready for the students of the Utica Shale Academy and the school’s director Bill Watson said now they just need the students to return to be able to use it. Because of COVID-19 restrictions the students have been working on the portions of the program they can complete virtually and Watson said Tuesday much of that work is now done. The students need to be in the lab in order to complete the program this year. Watson said even if the school is unable to fully reopen, he is hoping to work with the county health department to get small groups students in the lab during separate times. The Utica Shale Academy industrial maintenance lab is located in Southern Local High School, where students are able to get hands on training in basic tools, electrical systems, pneumatics and hydraulics. Watson said they are very lucky to have found Matt Gates to teach the class, who really understands the maintenance systems overall and can also utilize the new technologies. Watson told the Utica Shale Academy board he is in the process of applying for two Remote X grants, a 21st Century Grant and another Equity Grant this year. One of those grants being sought would be used for purchasing virtual welding equipment for the same industrial maintenance lab, which would give students the opportunity to learn the technical parts of welding. There are currently 74 students at the Utica Shale Academy, including 24 seniors. The average attendance this year, despite many of the classes being held virtually, has been 75.22 days of the 80 possible. On Fridays, 34 of the students are attending classes through the New Castle School of Trades. As things have gone remote due to COVID-19, the school delivered 40 laptops to the students who needed them this year. Additionally, students in need are receiving meals every Wednesday throughout the county.

Critics, supporters weigh in on gas pipeline that would travel through Luzerne County -Supporters and critics of a proposed natural gas pipeline that would travel through Luzerne County had their voices heard Wednesday night during a virtual public hearing conducted by the Pennsylvania Department of Environmental Protection. The PennEast Pipeline Company is seeking to create a 120-mile pipeline from Dallas Twp. to New Jersey. It’s seeking DEP permits regarding sediment and erosion control and also water encroachment. Dozens of people from throughout Pennsylvania and New Jersey offered commentary during the hours-long virtual hearing. Those supporting the pipeline, like former Nanticoke Councilman Cameron Cox, testified that construction of the pipeline would be great for the economy. “These projects are huge job creators,” Cox said. “This is a no-brainer. We need to invest in infrastructure.” Phase 1 of the project is a 68-mile pipeline from Dallas Twp. to Bethlehem Twp. in Northampton County. Don Nealey, a resident of Bethlehem Twp., said he’s against the pipeline, as did representatives for groups like the Sierra Club. “My concern is related to safety,” Nealey said. Some of the critics said the pipeline would undoubtedly pollute the environment. They also said the project is unneeded. Several noted that several natural gas companies went bankrupt in the past year and prices are down due to a surplus of gas in the market. Phase 2 of the project would link the pipeline from Bethlehem Twp. to Mercer County, New Jersey.

DEC outlines violations at Dimes oil and gas wells in Allegany - — State environmental officials cited Dimes Energy in 2020 for several violations involving the drilling of oil and gas wells in the West Branch Road and Four Mile Road areas of the town of Allegany. The citations were for 160 separate violations — from leaking oil wells and sedimentation and erosion issues to failure to submit proper paperwork — but none were tied to the state Department of Environmental Conservation’s investigation into what caused the November 2019 explosion of a house on West Branch Road. However, Dimes hit the community and state’s radar following the blast that destroyed the home of Ron and Betty Jo Volz. As the Volz home had been in the vicinity of the drilling of Dimes’ wells in the West Branch and Four Mile area, neighbors voiced concerns of a connection between the oil well drilling and the explosion. Although the DEC has had an ongoing investigation of the incident and have monitored Dimes’ wells in that area, the agency currently has not found a connection between the company’s operation and the explosion. The DEC also has noted the Cattaraugus County Fire Investigation Team had concluded that combustible gas, from unknown sources, was found in the Volz water well and most likely caused the house explosion. TJ Pignataro of the DEC’s Office of Communications, Region, Buffalo, provided a statement from the agency which summarized violations found with oil and gas wells in Allegany drilled by Dimes before corrective action was taken. The statement, in part, noted the “DEC executed a consent order in August 2020 to hold Dimes Energy accountable for numerous violations associated with its Cattaraugus County-area oil and gas well operations. In addition, the consent order levies penalties up to $79,000, requires numerous corrective actions at its operations in Cattaraugus County, and includes an Environmental Benefit Project valued at least $60,000 that ensures the proper plugging of three orphan wells in the Allegany community.” The statement noted DEC inspected Dimes’ oil wells and associated facilities from late 2019 through this past summer, including petroleum bulk storage facilities in Cattaraugus County. “During these inspections of Dimes’ wells, field operations, and its administrative filings, 160 separate violations were revealed,” the statement said. “These violations included leaking oil wells, and associated pollution to the environment; inadequately identifying its wells, failing to remove pit fluids and cuttings from its well sites, failing to file temporary abandonment request forms, erosion and sedimentation violations, as well as having excessive vegetation and debris at its well sites.

Governor asked to intervene on Plum wastewater injection well - Community and environmental organizations have asked Gov. Tom Wolf to revoke a state issued permit for a shale gas fracking waste disposal well in Plum, saying the well could endanger public drinking water supplies in Pittsburgh and nearby communities. Protect PT, the Breathe Collaborative, and Citizens for Plum say in the letter to the governor that allowing the Penneco Sedat #3A class 2 waste injection well to operate will significantly increase the risk of toxic chemical and radioactive contamination of surface and groundwater, cause mine subsidence and increase chances of earthquakes. The letter, dated Wednesday, Jan. 13, and co-signed by 45 additional organizations and individuals, calls on the governor to nullify the state permit to protect the Allegheny River as a source of drinking water for the city of Pittsburgh and other communities. “With this urgent action,” the letter states, “you will protect our families, our communities and most importantly our water from the troubling, secretive, radioactive and toxic waste of the gas industry.” “It’s short-sighted to issue a permit and allow this well to operate given its long-term potential impact on city of Pittsburgh drinking water,” Gillian Graber, executive director of Protect PT, said in a virtual news conference Thursday. Delmont-based Penneco Environmental Solutions received a permit from the state Department of Environmental Protection in April 2020 that allows it to convert the former oil and gas well into a 1,900-foot deep wastewater disposal well that can accept more than 2.27 million gallons of briny, chemically contaminated fracking wastewater a month. The facility, which would be the first deep disposal well in Allegheny County, received a federal Environmental Protection Agency permit in March 2018. Opponents of the well, many of whom testified in opposition to the facility at public hearings, say in the letter to the governor that revocation of the state permit is warranted because of recently discovered structural deficiencies in the well, the potential for mine subsidence and earthquakes, and the disposal of radioactive wastewater that can cause cancer.

IN BRIEF: Penn. state senators sue over natural gas 'moratorium' by river commission | Reuters --Two Pennsylvania state senators filed a lawsuit Monday against the Delaware River Basin Commission in federal court claiming it has usurped the state’s legislative power by declaring a de facto moratorium on the construction and operation of wells for natural gas production in the parts of the Marcellus Shale formation encompassed by the basin.State Senators Gene Yaw and Lisa Baker as well as the Pennsylvania Senate Republican Caucus say that the federal interstate body, which oversees the Delaware River watershed in Pennsylvania, New Jersey, New York and Delaware, violates the underlying compact between the four states by prohibiting since 2010 the construction of gas wells within areas of the basin in Pennsylvania that overlap with the Marcellus Shale formation. They filed their complaint in U.S. District Court for the Eastern District of Pennsylvania.To read the full story on Westlaw Today, click here: bit.ly/2LosdST

Student activists protest in Hartford and demand state action to cancel natural gas plant in Killingly - — A couple of dozen youthful protesters angry at Connecticut’s steps toward approval of a natural gas plant in Killingly took their complaints to the Capitol Wednesday, demanding the project be halted. Environmental activists staged a “die-in,” lying down on the icy ground at the edge of Bushnell Park in Hartford to call attention to their opposition to the 650-megawatt natural gas-fired electric generating plant. They say Gov. Ned Lamont and Energy and Environmental Protection Commissioner Katie Dykes are undermining their own clean energy policies by permitting the Killingly plant. “Do you want the plant to be a stain on your legacy?” asked Mitchel Kvedar, a UConn student and a leader of Sunrise Connecticut, a climate action group of college and high school students. Shutting down the plant isn’t simple: New England energy policy restricts state officials and the region’s grid operator operating in complicated energy markets. Will Healey, spokesman for the Department of Energy and Environmental Protection, said pending permits are required by law and officials respect the concerns of opponents. Dykes is calling for New England’s grid operator, ISO-New England, to revamp energy markets to bring them more in line with clean energy goals, he said. ISO has said states control power plant construction and that the objective of New England’s competitive wholesale markets is to select the lowest-cost, most efficient resources to provide reliable power.

Mass. building gas ban movement expands after 2020 setback | S&P Global Market Intelligence - A Boston-area push to restrict natural gas use in new construction is evolving into a statewide campaign for building electrification mandates. A dozen towns and cities across Massachusetts have partnered with the Rocky Mountain Institute, or RMI, to advocate for the right to require all-electric construction in their communities. The communities ultimately aim to change Massachusetts law, allowing local governments to pursue climate goals through building electrification. The campaign follows Attorney General Maura Healey's July 2020 decision to strike down the East Coast's first building gas ban in Brookline, Mass. Based on a pioneering Berkeley, Calif., ordinance, the Brookline bylaw blocked building permits for construction or major renovations that included gas piping for space and water heating. SNL Image Healey's ruling was a blow to lawmakers and activists advancing similar legislation in nearby Arlington, Cambridge and Newton. The ruling established that state utility law preempts town bylaws and exposed city ordinances to legal peril. Following Healey's decision, building electrification backers regrouped and workshopped alternative pathways to achieve building electrification. The effort coincided with the formation of the RMI's Massachusetts Building Electrification Accelerator, a partnership among the RMI, Bay State climate activists and local officials. Twelve cities have publicly joined the accelerator: Amherst, Arlington, Ashland, Belmont, Brookline, Cambridge, Concord, Ipswich, Lexington, Melrose, Salem and Worcester. Several other municipalities have engaged with the project but have not yet publicly announced their affiliation. Accelerator participants stressed that their goal is not to receive permission on a community-by-community basis. Instead, they aim to demonstrate widespread support for electrification mandates through several shared strategies, making it untenable for the state Legislature to oppose them. Participants also intend to draw attention to the lack of policy options available to local governments seeking to help the state achieve its goal of reaching net-zero greenhouse gas emissions by 2050. 

Forest Service grants pipeline's request to pass through Jefferson National Forest - The U.S. Forest Service has approved, for the second time, Mountain Valley Pipeline’s pathway through the Jefferson National Forest. A decision from James Hubbard, undersecretary of natural resources and the environment for the U.S. Department of Agriculture, was posted to the forest’s website early Monday morning. About three hours later, a coalition of environmental groups sued, seeking to have the permit set aside for a second time. Hubbard’s decision came more than two years after the 4th U.S. Circuit Court of Appeals vacated Mountain Valley’s permit, ruling that the Forest Service did not take into account the amount of erosion and sedimentation that would be caused by running the largest natural gas pipeline in Virginia along steep mountain slopes. After more than two years of review, the agency issued a new permit that in large part mirrors its 2017 approval for the buried pipeline’s route through two sections of the forest — in Giles and Montgomery counties and Monroe County, West Virginia — that total 3.5 miles. The decision “redeems the Forest Service’s commitment to ensure the pipeline minimizes impacts and meets standards for sustainability and conservation of natural resources,” the service said in a news release. But that will likely be a question for the 4th Circuit, where the Sierra Club and seven other environmental groups brought their latest challenge Monday. Mountain Valley “still can’t show that there’s any way to build this pipeline without violating the laws that protect our national forests and clean water,” said Nathan Matthews, senior attorney for the Sierra Club. No construction can start in the forest until Mountain Valley has obtained all state and federal authorizations. The joint venture of five energy companies building the pipeline must still obtain a right of way from the U.S. Bureau of Land Management, which was struck down in the same 2018 decision that invalidated the Forest Service’s permit. Meanwhile, another permit that governs nearly 1,000 stream crossings for the pipeline was stayed Oct. 16 by the 4th Circuit, which is considering a legal challenge of that authorization by the U.S. Army Corps of Engineers. Also pending is a third lawsuit that seeks to overturn a decision by the U.S. Fish and Wildlife Service, which ruled last September that the pipeline is not likely to jeopardize protected species of fish and bats.Critics said Monday’s decision was made by a political appointee who rushed to get the matter finalized before President Donald Trump’s departure from office Jan. 20.

Pipeline opponents sue to reverse Forest Service decision (WDBJ) - Opponents of the Mountain Valley Pipeline have filed suit to reverse a Forest Service decision allowing construction of the Mountain Valley Pipeline on 3.5 miles of the Jefferson National Forest.On Monday, a coalition of conservation groups said they were petitioning the federal court of appeals to strike the Forest Service decision.“The Forest Service and BLM bowed to political pressure and rushed these decisions,” said David Sligh, Conservation Director of Wild Virginia. “They failed in their most basic duty, to rely on facts and science to make decisions that fully protect our national treasures.” A spokesperson for the Mountain Valley Pipeline released the following statement Monday, after the U.S. Forest Service released a decision allowing the controversial natural gas pipeline to cross 3.5 miles of the Jefferson National Forest. “The U.S. Forest Service posted a record of decision regarding MVP’s routing through the Jefferson National Forest, which the project team is currently reviewing. This decision by the USFS is one element of the ROW approval process, and the information will now be reviewed by the Bureau of Land Management and the FERC, the timeline for which is uncertain. Upon approval, and before construction would begin in the Jefferson National Forest, we will also need to consider other relevant factors, such as weather and availability of government oversight. Currently, MVP is continuing with its construction activities outside the JNF, within the constraints of winter weather conditions and in compliance with all environmental regulations and guidelines. In addition, the team remains focused on maintaining the project’s enhanced erosion & sedimentation controls that have been effectively put in place. MVP remains confident in its targeted full in-service date of late 2021.” The USDA Forest Service issued a final Record of Decision that amends the Jefferson National Forest Land and Resource Management Plan (Forest Plan) to allow the Mountain Valley Pipeline project to move forward.Click here to read the fill Record of Decision.The Record of Decision modifies certain standards in the Forest Plan to accommodate the pipeline construction and requires measures to minimize environmental impacts, according to the USDA. The Forest Service will also provide a letter of concurrence for the MVP Project to the Bureau of Land Management. Mountain Valley, however, is not authorized to undertake activities related to construction on national forest lands until the company has obtained all Federal and State authorizations outstanding for the entire project. The Bureau of Land Management is responsible for approving pipelines that cross federal lands under the jurisdiction of two or more federal agencies but must have the concurrence of the involved agencies.

Groups Appeal Alabama Public Service Commission’s Approval of $1+ Billion Gas Expansion | Southern Environmental Law Center —Energy Alabama, GASP, and the Southern Environmental Law Center are appealing the Public Service Commission’s approval of Alabama Power’s petition for its single largest capacity increase ever, with a price tag for customers of over $1.1 billion.The groups have filed an appeal in state court challenging the Commission’s decision allowing Alabama Power to increase its natural gas capacity by over 1800 megawatts, including building a new gas plant at the Barry Electric Generating Plant in Mobile County, while failing to approve a proposal to add 400 megawatts of solar plus battery energy storage projects.In September, the groups petitioned the Commission to reconsider its determination that this capacity increase is needed, especially in light of the economic slowdown caused by the pandemic; its decision to saddle customers instead of utility shareholders with the risk that the assets will become stranded; and its denial of the solar plus storage projects, which the utility’s own analysis showed had the most value for customers. The Commission denied the petition.Starting January 1, Alabama Power’s electric rates are increasing for all 1.48 million residential, commercial, and industrial customers, raising the average residential monthly bill by about $4. As a result of the new natural gas capacity, bills are expected to increase further starting in 2023.“Alabamians already pay some of the highest energy bills in the country and the pandemic has only worsened the financial hardships many are facing,” said Keith Johnston, Director of SELC’s Birmingham office. “Now the Commission is allowing Alabama Power to go forward with an unjustified, massive amount of new capacity that will further increase electricity rates, putting added strain on customers.”The Alabama Attorney General’s office raised concerns in the Commission proceedings that the proposed gas plants could become stranded or uneconomic as a result of new emission standards or changes in technology, and recommended that the Commission impose a condition requiring that Alabama Power and its shareholders bear any stranded costs associated with its proposal instead of customers.

Low Natural Gas, Oil Prices Break Two-Year Uptrend for Proved US Reserves, Says EIA - A two-year trend of rising proved reserves of natural gas and oil in the United States ground to a halt amid a decline in prices in 2019, according to the Energy Information Administration (EIA). Natural gas proved reserves decreased 1.9% year/year in 2019 to 494.9 Tcf from 504.5 Tcf. This is the first annual decrease in proved gas reserve in the United States since 2015, but reserves remain at their second highest level ever, the agency said. Total U.S. gas production increased 9.8% year/year. Lower 48 basins fared better. Proved gas reserves from unconventional U.S. plays increased to 71% at year-end 2019 from 68% in 2018. The largest net gain by volume in 2019 occurred in Ohio, which grew by 10.4 Tcf. The EIA said the increase was driven by continuing development of the Utica/Point Pleasant shale play in the Appalachian Basin. The largest net decrease in proved gas reserves in 2019 was in Texas, which was down 12 Tcf in the period. The EIA said net downward revisions of reserves in the Eagle Ford and Barnett shales contributed the most to the annual drop. Declines in the Haynesville Shale also contributed to the steep decreases in Texas. Meanwhile, the annual average spot gas price at the benchmark Henry Hub decreased from 2018 by 21.5% from $3.35/MMBtu to $2.63/MMBtu, according to EIA. EIA collects independently developed estimates of proved reserves from a sample of operators of U.S. oil and natural gas fields with its Form EIA-23L. The agency uses the sample to further estimate the portion of proved reserves from operators that do not report. Responses were received from 372 of 412 sampled operators, which provided coverage of about 90% of proved reserves of oil and natural gas at the national level. On the oil side, proved reserves increased 367 million bbl in 2019, while proved reserves of lease condensate produced from gas wells dropped 313 million bbl, according to EIA. This yielded a net gain of 54 million bbl of proved reserves of crude and lease condensate to 47.1 billion bbl at year-end 2019, which is at the record level set in 2018. U.S. oil and condensate production increased 12.7% from 2018 to 2019. Alaska producers reported the largest net increase, adding 259 million bbl of proved reserves of oil and lease condensate in 2019, while producers in New Mexico saw the second-largest net increase of 226 million bbl. Texas rounded out the Top 3 with a 179 million bbl gain, with extensions and discoveries in the Permian Basin of southeastern New Mexico and West Texas contributing the most, according to EIA. Colorado recorded the biggest decline in proved reserves of crude and condensate, falling 154 million bbl in 2019. Meanwhile, the annual average spot price for a barrel of West Texas Intermediate oil at Cushing, OK, decreased 15.1% in 2019, to $55.77/bbl from $65.66 in 2018. “Spot market prices are not necessarily the prices used by operators in their reserve estimates for EIA because actual prices received by operators depend on their particular contractual arrangements, location, hydrocarbon quality and other factors,” EIA said. “However, spot prices do provide a benchmark or trend indicator.”

Polar Vortex Potential, LNG Strength Bolster February Natural Gas Futures - Natural Gas Intelligence - Natural gas futures slipped early on Monday following forecasts for mild weather and diminished heating demand. However, they rebounded in afternoon trading and finished in the green amid anticipation of a late-month surge in frigid temperatures. The February Nymex gas futures contract settled at $2.747/MMBtu, up 4.7 cents day/day after falling more than 10 cents in morning trading. March gained 4.7 cents to $2.703. With conditions mostly mild Monday, NGI’s Spot Gas National Avg. shed 3.5 cents to $2.745. “The forecast continued its warming trend over the weekend, due to a couple of factors,” Bespoke Weather Services said. “One is that the nearer-term forecast, with no quality cold source anywhere in North America, rolled forward warmer. The other reason is that, once we do see a true cold source develop up in Canada, it looks to impact the less populated western U.S. rather than the eastern half, keeping national demand no better than near normal.” Bespoke said it removed 15 gas-weighted degree days from its projections Monday compared to Friday’s forecast. Major weather models, however, showed negative North Atlantic Oscillation “tendencies into late month” that could lead to cold in the West shifting eastward and driving more demand. This “keeps the medium-range pattern interesting,” the firm added. National Weather Service meteorologists said a harsh winter chill could still blanket large swaths of the country near the end of January. They pointed to the potential for a polar vortex – a cold snap that develops in the atmosphere above the North Pole and sends harsh blasts of freezing temperatures throughout the Northern Hemisphere. This would drop temperatures in North America as well as Europe and Asia, key destinations for U.S. liquefied natural gas (LNG) exports. LNG volumes, while steadily strong, dipped below 11 Bcf over the weekend and into Monday after hovering above that near-record threshold over several days last week, NGI data show. Low temperatures are already hanging near zero or below in parts of Asia, fueling robust heating demand and need for U.S. gas. Should an intense winter chill wash over the Lower 48 as well later this month, analysts expect domestic heating demand to surge and cut quickly into U.S. stockpiles. “Even with the bearish weekend model shift, the year/year storage surplus is still likely to largely evaporate this month,” 

Natural Gas Futures Advance on Potential for Harsh Winter Freeze; Cash Prices Jump - Natural gas prices surged early on Tuesday amid expectations for intensifying U.S. liquefied natural gas (LNG) export demand and increased anticipation of subfreezing air descending from Canada and covering large parts of the Lower 48 in late January. After spiking about 15 cents in morning trading, the February Nymex gas futures contract gave back much of the gains in the afternoon following midday weather runs that showed lighter intensity in the coming cold. When the dust cleared, however, the prompt month was up six-tenths of a cent day/day and settled at $2.753. March rose four-tenths of a cent to $2.707.  NGI’s Spot Gas National Avg. advanced 18.0 cents to $2.925. While the American weather model was colder than the European, both early Tuesday called for a heavy dose of cold by late next week. Meteorologists were forecasting a pattern akin to what became known as the 2014 polar vortex. It sent widespread blasts of freezing air from the North Pole across much of the Northern Hemisphere. A repeat in late January could result in frigid air blanketing North America, Asia and Europe, fueling stronger domestic demand and continued robust demand for U.S. LNG.NatGasWeather said prices were boosted early by the “hype of cold now for Jan. 23-26.” Major models in the afternoon, however, showed “not quite as cold air into Western Canada, thereby pushing less impressive subfreezing air into the U.S. as well” in late January… “Of course, the data could flip back colder overnight and will be watched very closely by market participants.”Despite evolving views on its intensity and breadth, a looming chill is likely to develop in the western and central United States by late in the month, forecasters said, and this type of pattern historically has proven capable of driving Arctic cold across the East and as far south as Texas.

US weekly gas storage withdrawal beats estimates at 134 Bcf | S&P Global Market Intelligence - Storage operators withdrew a net 134 Bcf from natural gas inventories in the Lower 48 during the week ended Jan. 8, compared to a five-year-average withdrawal of 161 Bcf, the U.S. Energy Information Administration reported.The pull, which beat the 123 Bcf forecast by an S&P Global Platts analyst survey, brought total working gas supply in the Lower 48 to 3,196 Bcf, or 126 Bcf above the year-ago level and 218 Bcf above the five-year average.  By region:

• * In the East, storage levels slid 39 Bcf on the week at 726 Bcf, down 0.1% from a year ago.
• * In the Midwest, stockpiles were down 44 Bcf at 879 Bcf, 2% higher than a year earlier.
• * In the Mountain region, inventories fell 8 Bcf at 188 Bcf, 16% higher than a year ago.
• * In the Pacific region, inventories declined 4 Bcf at 278 Bcf, 17% above the year-ago level.
• * In the South Central region, inventories were down 37 Bcf at 1,126 Bcf, 4% above a year earlier. Of that total, 327 Bcf of gas was in salt cavern facilities and 799 Bcf was in non-salt-cavern facilities. Working gas stocks fell 1.8% in salt cavern facilities from the week before and were down 3.7% in non-salt-cavern facilities.

US natural gas futures fall on mild weather -  US natural gas futures fell to their lowest in a week on Thursday on forecasts for milder weather and less heating demand over the next two weeks than previously expected. That decline came even though liquefied natural gas (LNG) exports remained near record levels and last week’s storage draw was slightly bigger than expected. The US Energy Information Administration (EIA) said utilities pulled 134 billion cubic feet (bcf) of gas from storage during the warmer than usual week ended January 8. That was bigger than the 128-bcf draw analysts forecast in a Reuters poll and compares with a decrease of about 91 bcf in the same week last year and a five-year (2016-2020) average withdrawal of 161 bcf. Front-month gas futures fell 6.1 cents, or 2.2%, to settle at $2.666 per million British thermal units, their lowest close since Jan. 4. Data provider Refinitiv said output in the Lower 48 US states averaged 91.5 billion cubic feet per day (bcfd) so far in January. That matches December’s eight-month high but falls short of the all-time monthly high of 95.4 bcfd in November 2019.

Strong Finish Caps Solid Run for Weekly Natural Gas Prices - NGI’s Weekly Spot Gas National Avg. for the Jan. 11-15 period climbed 10.5 cents to $2.820, led by hubs in the Northeast. As the trading week closed, Tenn Zone 6 200L was up 73.0 cents to $4.220 and Dracut was ahead 49.5 cents to $4.175. Elsewhere, Henry Hub finished up 6.5 cents to $2.750, while Enable East gained 9.0 cents to $2.625. Generally comfortable conditions across most regions of the Lower 48 were expected for the third week of January, minimizing the odds of strong national heating demand. The final week of January, however, holds promise for intense cold settling in over the Northwest and Plains before moving east. This could result in several days of freezing temperatures over large swaths of the country. “We view the Jan 26-29 period as one of the best chances this winter for cold to finally come through,” NatGasWeather said Friday. Meteorologists are anticipating a polar vortex – a cold snap that develops in the atmosphere above the North Pole and sends harsh blasts of freezing temperatures throughout the Northern Hemisphere. Should this develop, it could drop temperatures in Europe and Asia, as well, adding to already strong demand for U.S. liquefied natural gas (LNG). Though views on its intensity varied during the latest covered week, a polar vortex-induced chill is likely to develop in the western and central United States, forecasters said, and this type of pattern historically has proven capable of driving Arctic cold across the East and as far south as Texas. Natural gas futures yo-yoed throughout the week, as traders tried to balance bearish weather trends against continued strong LNG demand and a bullish storage report from the U.S. Energy Information Administration (EIA). Futures rallied early in the week after meteorologists predicted the severe and sustained winter freeze that could blanket large swaths of the Lower 48 late in January. Futures, however, lost ground Wednesday and Thursday as weather models shifted warmer. Forecasts continued to show cold blasts late in January but the duration and reach of the freezing temperatures was scaled back, with uncertainty about cold Canadian air pushing out of the central United States into the East and South. By Friday, however, forecasts tilted back to stronger expectations for severe winter conditions and robust heating demand by late January, boosting futures in the week’s final day of trading by 7.1 cents. The February Nymex contract settled at $2.737/MMBtu on Friday, up 1.4% from the prior week’s finish.

Natural Gas 'Bridge Fuel' Narrative to Face Tougher Scrutiny Under Biden - With natural gas projected to play a major role in the global energy mix for decades to come, the incoming Biden Administration would need to mitigate the fuel’s environmental impacts as much as possible in order to fulfill his climate agenda, the most ambitious of any U.S. president in history. As a result, the industry likely faces more pressure than ever, especially with a Democrat-controlled Senate, to prove gas can be a bridge fuel to a low-carbon economy. Over the short term, this would require clamping down on methane leakage throughout the gas value chain, and on carbon-dioxide (CO2) emissions from combustion of the molecule. Methane, the main component of natural gas, is about 84 times more potent as a greenhouse gas during the first two decades after its release than CO2, according to the Environmental Defense Fund (EDF). The gas industry, including national oil companies, supermajors, independents, midstreamers and utilities, has stepped up voluntary efforts to plug methane leaks and reduce routine gas flaring and venting amid growing calls from investors to take meaningful action on climate. However, as techniques for measuring greenhouse gas (GHG) pollution have improved, the challenge appears increasingly daunting. A recent EDF study, for example, found that annual oil and gas methane emissions in New Mexico stand at an estimated 1.1 million metric tons, about five times higher than what current Environmental Protection Agency (EPA) data suggest. Venting and flaring, meanwhile, reached record high levels in the United States during 2019. So far, only Alaska and Colorado have banned routine flaring and venting in the upstream segment. Venting contributes to methane emissions, as does incomplete combustion during the flaring process, while flaring converts methane to CO2. More broadly, climate change — practically an afterthought during the 2016 presidential campaign — has taken on a more prominent role in political discourse, as seen during the debates between Biden and President Trump. And while natural gas is the cleanest fossil fuel, it increasingly has been under the microscope as its share of the energy mix grows. “The world has changed a lot in four years,” “I think the industry is starting to really wake up to the fact that they have to deal with this black eye, which is methane…if they want to survive.”

Enbridge to Michigan: We won’t shut down Line 5 -- Enbridge Energy will not comply with Gov. Gretchen Whitmer’s order to shut down the controversial Line 5 pipeline by May, a company executive told state officials Tuesday. In a letter to Whitmer and Department of Natural Resources Director Dan Eichinger, Vern Yu, Enbridge’s executive vice president and president of liquids pipelines, questioned Michigan’s rationale for ordering the shutdown and maintained that “the Dual Pipelines will continue to operate safely until they are replaced on completion of the Tunnel Project.” Enbridge is awaiting permits in that project, which aims to replace the aging dual span pipes at the bottom of the Straits of Mackinac with a new pipe running through a tunnel beneath the lakebottom. Enbridge officials have said they plan to start building the tunnel this year and finish by 2024, but the company is still awaiting state and federal permits it needs to begin construction. Citing a litany of easement violations and broader concerns that the pipeline poses a dire risk of an oil spill, Whitmer notified Enbridge in November that she was revoking and terminating the 1953 easement that allows the company to operate Line 5 in the Straits. Whitmer ordered the Straits portion shut down by May. In a statement Tuesday, Eichinger called Enbridge’s letter an “attempt to power wash” a history of easement violations and said state officials “look forward to making our case in court, not via letters and press releases.” “Enbridge cannot unilaterally decide when laws and binding agreements apply and when they do not,” Eichinger said. “We stand behind our efforts to protect the Great Lakes, and we stand behind the substance of the November 2020 revocation and termination of the Easement.” After campaigning for office in 2018 on promises to shut down Line 5, Whitmer had faced mounting pressure to act since the company revealed in June that the pipeline had sustained “significant damage” from what was later revealed to be a probable anchor strike from a vessel owned by one the company’s contractors. In tandem with Whitmer’s shutdown order, state Attorney General Dana Nessel filed a lawsuit in Ingham County Circuit Court seeking to back up Whitmer’s action. “Enbridge has imposed on the people of Michigan an unacceptable risk of a catastrophic oil spill in the Great Lakes that could devastate our economy and way of life,” Whitmer said in a statement at the time. “That’s why we’re taking action now.”Enbridge responded quickly with a federal lawsuit seeking a ruling that federal pipeline safety regulations trump Michigan’s authority over Line 5. The company has asked the U.S. District Court for the Western District of Michigan to dismiss Nessel’s Ingham County suit.

LSP commends SCOTUS rejection of suit against frac sand ban - Land Stewardship Project has expressed satisfaction with the U.S. Supreme Court’s recent decision to not overturn Winona County’s frac sand ban. On Monday, the court elected to not hear Minnesota Sands, LLC’s suit, which could have resulted in the ban eventually being uplifted. Minnesota Sands LLC, citing Southeast Minnesota Property Owners, claimed the ban violates equal protection, due process and private property rights. It added that silica sand has been mined in the state for over 100 years and that it is unique because it is “extremely” hard and round and made up of quartz, which makes it valuable for use in energy production around the country. The frac sand ban was passed in 2016 and Minnesota Sands, LLC subsequently sued in an attempt to overturn the decision. The Winona County District Court upheld the decision a year later, as did the Minnesota Court of Appeals in 2018, the Minnesota Supreme Court in 2020 and most recently the U.S. Supreme Court this past Monday. Back in October when Minnesota Sands, LLC announced it had filed a petition with the U.S. Supreme Court, LSP called the move “disappointing, but unsurprising.” “The land has inherent value, and the health of the land and of people are interconnected,” LSP said at that time. “All decisions about land use must be made with the needs of the future in mind.” “The people of Winona County have understood for many years that the frac sand mining, processing, and transport industry offers no benefit to rural communities and is too harmful to be allowed to operate in their communities.”

Fracking Ban Proposal Re-Emerges In Florida –  – After the issue made little progress last year, Florida Senate Minority Leader Gary Farmer, D-Lighthouse Point, began a renewed effort Tuesday to ban fracking in Florida. Farmer filed a bill (SB 546) that would ban hydraulic fracturing — known as fracking — to extract oil and natural gas. The proposal also would ban a process known as matrix acidization, which uses many of the same chemicals as in hydraulic fracturing but dissolves rocks with acid instead of fracturing them with pressurized liquid. Farmer’s proposal is filed for the legislative session that starts March 2. It comes after years of efforts by some lawmakers and environmentalists to prevent the possibility of fracking in Florida. But the Legislature has rejected proposed bans, including bills last year that cleared only one Senate committee and no House committees.

Texas Oil-Gas Lobby Seeks Infrastructure Jolt to Boost Industry - Texas’s oil and gas lobby is calling on lawmakers to expand the state’s energy infrastructure and renew an economic development program, saying the moves are “essential to the state’s continued growth and success.” The requests are part of a three-part “roadmap to recovery” designed to drive greater investment in the industry as it recovers from the pandemic, said Todd Staples, president of the Texas Oil and Gas Association, or TXOGA. The group also wants lawmakers to keep oil and gas innovators at the table for “science-based policy and rational discussions related to environmental issues.”

Texas oil and gas group says new taxes, regulations will crimp rebound - With the storied Texas oil and gas sector still recovering from the devastating economic fallout of the coronavirus pandemic, the industry's main lobbying group is urging state lawmakers not to put any new obstacles in its path. Todd Staples, president of the Texas Oil & Gas Association, said calls for increased taxes on production, known as severance taxes, should be resisted during the 2021 legislative session that begins this week, as should environmental regulations that aren't "rational" and based on what he called firm science. "When Texas oil and gas is healthy, all Texans are winners, and in a substantial way," Staples said Monday, speaking to reporters a day before the legislative session was set to start. Energy prices took a nosedive early last year when the pandemic first hammered the global economy. West Texas Intermediate crude oil, the U.S. benchmark, fell below $20 a barrel in March for the first time in 18 years — after beginning 2020 near $60 — and the state's rig count slumped to more than a 50-year low. Prices since have recovered, with oil trading recently around $52 a barrel. But they also have been volatile, and the energy sector overall is still reeling from lost revenue, bankruptcies and job cuts. In November, for instance, about 191,000 Texans were directly employed in the industry category that includes oil and gas extraction, according to the most recent figures available from the Texas Workforce Commission — 50,000 fewer than in the same month a year earlier. The downturn also has taken a bit out of the state budget. Texas Comptroller Glenn Hegar is projecting that revenue from the oil production tax will come in at $5.9 billion during the state's current two-year budget cycle, about 18% less than $7.2 billion in the previous two-year cycle. Hegar's forecast calls for the figure to rebound somewhat, to $6.5 billion, in the 2022-2023 budget cycle, based on his projection that oil will average $49 a barrel in 2022 and $55 in 2023. Staples, a Republican who formerly served as Texas agriculture commissioner, didn't comment specifically on Hegar's price projections Monday, saying a wide range of estimates exists.Still, he said the sector has been on a positive trajectory since the depths of the pandemic-induced downturn, so state lawmakers must be careful not to knock it off course. “Oil and natural gas are essential and irreplaceable," Staples said, an assertion he called evident even amid the pandemic. "While oil prices plummeted in the wake of the pandemic, the need for products made from oil and natural gas skyrocketed," he said. "Nearly every in-demand product we need to be safe and save lives, from face shields and other (personal protective equipment) to ventilators and hand sanitizers, is made from oil and natural gas.”

Summit's Permian Natural GasConduit Gets FERC OK to Start Construction –=- Federal regulators have approved the start of construction on all but a small portion of Summit Midstream Partners LP’s 135-mile Double E natural gas pipeline that would connect Permian Basin supplies to the Gulf Coast. Summit CEO Heath Deneke touted the “efficiency with which this project has achieved its key milestones” and confirmed the pipeline’s expected 2021 in-service before the end of this year. “Our world-class development team has maintained its focus on delivering the Double E project on time and under budget and has been instrumental in advancing the project and taking another step toward start-up,” Deneke said. In its Tuesday notice to proceed order, FERC said general construction activities associated with Double E may proceed, except for nine milepost ranges along Lines L100, T100 and T200. The Federal Energy Regulatory Commission said no construction activities would be permitted in those areas until the pipeline “requests follow-up permission to construct in these areas” and they are approved. Houston-based Summit sanctioned Double E in June 2019 to transport 1.35 Bcf/d from the Permian’s Delaware sub-basin to the Waha hub in West Texas and beyond. The midstreamer moved forward with the project after securing “sufficient” binding commitments for long-term, firm transportation service to various receipt points in New Mexico’s Eddy and Lea counties and the West Texas counties of Loving, Ward, Reeves and Pecos. From Waha, Double E would connect with “multiple current and planned takeaway pipelines” to demand centers south, according to Summit. Mexico Gas Price Index - Learn More ExxonMobil, an anchor shipper, has a 30% stake in the project. Double E is the second joint venture between Summit and ExxonMobil. ExxonMobil’s XTO Energy Inc. and Summit teamed up in 2017 to develop and operate an associated gas gathering and processing system to serve Permian operators in New Mexico. FERC, which authorized Double E in October, said the pipeline also is authorized to implement “project cultural resources treatment plans/mitigation measures, including archaeological data recovery.” Summit indicated that Double E has been granted the necessary rights-of-way on federal lands from the Department of the Interior’s Bureau of Land Management and has entered into memorandums of agreement regarding treatment and mitigation measures at certain cultural resource sites with FERC and the state historic preservation officers of New Mexico and Texas.

Feds Decline Comment on Exxon Permian Probe Report -- Exxon Mobil Corp. slumped after a newspaper report said the company is being investigated by the U.S. Securities and Exchange Commission for allegedly overvaluing a key asset in the Permian Basin. The probe stems from a whistleblower complaint that during a 2019 internal assessment workers were forced to use unrealistic assumptions about how quickly wells could be drilled to reach a higher valuation, the Wall Street Journal reported, citing people familiar with the matter. At least one of the workers who complained was fired in 2020, the Journal said. In response, Exxon said the reported claims are “demonstrably false” and that the company “stands by” its statements to investors. Still, the probe may cast a shadow over Exxon’s efforts to turn a corner after its shares posted their worst annual performance in 40 years in 2020 amid a collapse in oil prices. Chief Executive Officer Darren Woods has been forced to slash spending, and last month the company said it will write down the value of North and South American natural gas fields by as much as $20 billion. Exxon fell as much as 6% before paring losses to trade 4.1% lower at $48.25 at 12:12 p.m. in New York, snapping a nine-day rally. The SEC declined to comment. The SEC probe “shows the fragile foundation for the company’s $15 billion dividend. It’s a difficult case to prove, as oil companies are allowed to set their own assumptions on asset valuation, but suggests the company’s pre-pandemic plan to double underlying earnings by 2025 may be more aspirational than tangible.”  It’s not the first time Exxon has been probed by the SEC over how it values assets. In 2016, Exxon was questioned by the regulator about why the company appeared immune from the multi-billion write downs affecting the rest of the industry. The issue was resolved without any action being taken. The SEC requires oil companies to report with reasonable certainty the volume of reserves in wells that are profitable at a price set by the agency the year before. Those wells must be drilled within five years of being added to a company’s books. The calculations take into account the rate at which a well’s production is likely to decline, how closely the wells are drilled, land and capital costs, as well as the price per barrel of crude.

Investigation Reveals Damaged Pipeline Caused 2018 Natural Gas Explosion That Killed Dallas Girl  The National Transportation Safety Board met on Tuesday to determine the cause of a 2018 natural gas explosion that killed a 12-year-old girl in northwest Dallas. The federal agency declared the probable cause of the 2018 fatal explosion was a natural gas leak from a pipe that was damaged during a replacement done over 20 years ago. Jennifer Homendy, a national transportation safety board member, said procedures and decisions by Atmos Energy — the neighborhoods' natural gas provider — contributed to the explosions. “Contributing to the explosion was Atmos Energy Corporation’s insufficient wet weather leak investigations procedures. Contributing to the severity of the explosion was Atmos Energy Corporation’s inaction to isolate the affected main and evacuate the houses," Homendy said. "Contributing to the degradation of the pipelines system was Atmos Energy Corporation’s inadequate integrity management program." This same leak caused two other fires on the same street — Espanola Drive — days prior to the fatal explosion. The gas-related problems forced 300 families in the area to evacuate. The crack in the main pipeline led to numerous gas leaks throughout the neighborhood that went undetected. During the week of Feb. 23, 2018, the temperature in Dallas ranged from 32 to 54 degrees and there was heavy rainfall. Atmos Energy, said those conditions made it difficult to investigate or quickly repair multiple leaks. “They could have tested the customer piping. In this case it turned out they could have also tested the customer piping all the way to the appliances,” said Sara Lyons, the investigator in charge, who looked into the response by Atmos Energy. This led the investigations team to take an in-depth look at the energy company's protocols when customers file complaints or incidents happen. They found insufficient training and resources are given to employees and that there are no clear protocols on how to access damages.

US Midstream Possibly Normalizing in 2021, but Overbuild Still Major Problem, Say Experts -- The North American oil and natural gas midstream sector is certainly not “out of the woods,” but 2021 could look relatively “normal” in 2021, according to Raymond James & Associates Inc. Though driven largely by supply, the Raymond James team remains bullish on the price outlook across the hydrocarbon spectrum. The analysts said the demand-pull environment “still looks attractive” in 2021 and beyond, with the recovery in U.S. liquefied natural gas (LNG) exports adding to a “solid base.” U.S. LNG exports “have recovered massively thanks in part to soaring Asian prices — as about as good of a recovery play as one can find within the U.S. midstream space,” said the Raymond James team, led by analysts Justin Jenkins and J.R. Weston. Furthermore, natural gas liquids (NGL) markets are expected to tighten and support gathering and processing (G&P) and pricing, according to the analysts, with G&P offering investors the most “bang for their buck” going forward. Propane markets, meanwhile, are “very tight,” though the budding optimism in the market “might be a touch excessive.” Additionally, the firm said with demand/export growth on deck and some supply headwinds, ethane recovery “should happen everywhere” other than the Bakken Shale — “perhaps providing more of a volume tailwind than would have otherwise been expected.” On the refined products side, the Raymond James team sees demand improving through 2021, with the real inflection occurring around mid-year. “This improvement should benefit our refining coverage, and higher utilization rates should flow through as higher volumes across the midstream value chain.” Operationally, the analysts said it’s general consensus that the Permian Basin would lead the next leg of performance among midstreamer companies, but the Bakken/Denver-Julesburg Basin needs prices around $50/bbl to work. “We are now there, but will it hold?” analysts said. The firm noted that the decision by the Organization of the Petroleum Exporting Countries and their allies may offer some support. Analysts noted that dry gas may play a role in the eventual supply response, with Haynesville Shale activity possibly picking up more quickly than the Marcellus/Utica shales. On a macro level, Raymond James said while the U.S. economy’s flip from lockdown to reopen mode jump-started the midstream sector late last year, inflation, its impact on the U.S. dollar and how this corresponds to oil prices could benefit the energy sector more broadly in the year ahead. Meanwhile, possible shifts in the U.S. tax regime should favor master limited partnerships primarily, and midstreamers’ contractual ability to pass through inflation to customers has become a “widely under-appreciated item.”

Oil executives in Oklahoma say they're making plans for what they say will be a tough era — Nine days until the inauguration of President-elect Joe Biden, and oil executives in Oklahoma are making plans for what they say will be a tough era. Biden promised a carbon-neutral nation by 2050. KOCO 5 asked executives how they’re feeling. “Get rid of the oil and gas companies? Will you remember that, Texas? Will you remember that, Pennsylvania, Oklahoma?” President Donald Trump said during one of the presidential debates. That comment during the heated debate between Trump and Biden sparked some interest among Oklahomans. “The oil industry pollutes scientifically,” Biden said during the debate. Biden further explained he wanted to move away from fossil fuels and rely on green energy. Dewey Bartlett, with the Oklahoma Energy Producer Alliance, said regardless of his political beliefs, he panicked when he heard Biden say he plans to move away from fossil fuels. “We’ll be having problems. Everyone will be having problems,” Bartlett said. “That would not only devastate Oklahoma, that would devastate the entire country.” According to ABC News, energy companies stockpiled enough drilling permits for western public lands to keep pumping oil for years. Biden wants to end new drilling on those same lands as part of his overhaul of how Americans get energy. “He wanted to not allow any more drilling on federal lands, on public lands,” Bartlett said. But that’s not happening in Oklahoma because the oil and gas companies don’t operate on too many federal lands. Instead, Bartlett said they feel like sitting ducks, waiting to find out what types of regulations Biden might put into place. “There are a lot of unknowns when it comes to the Biden administration. But I can say it’s not going to be good,” Bartlett said.

New Trump rule expected to cut costs for public lands drilling -The Trump administration is finalizing a rule that will lessen the amount of money oil and gas companies that drill on public lands and in public waters pay to the federal government. The rule will make changes to the way that these royalties are calculated and, according to the administration, is expected to result in an annual decrease of $28.9 million in royalty collections. The rule, promulgated by the Interior Department’s Office of Natural Resources Revenue, notes that this figure is less than 0.5 percent of the total federal oil and gas royalties it collected in 2018. The industry has argued that a previous rule on how the royalties are calculated was burdensome and created uncertainties.  Opponents of the changes, however, argue that the new rule helps fossil fuel companies and harms taxpayers. “This is a blatant attempt to reopen loopholes for the oil and gas industry and allow them to skirt royalty payments owed to American taxpayers for publicly owned resources,” said Jesse Prentice-Dunn, the policy director at the Center for Western Priorities.“It’s just an open and shut case of delivering benefits to the oil and gas industry at the expense of the American people,” Prentice-Dunn added. The rule allows companies that extract oil and gas from water that’s 200 meters deep or more to deduct certain costs. It will also allow the consideration of mitigating circumstances when royalty payments are late.The rule would also use the average weekly benchmark price for the commodities rather than the highest weekly benchmark prices to calculate royalty payments for certain sales. Measures that were previously proposed as part of the rule to remove hard caps on transportation and processing deductions did not make it into the final version, though the department will allow lessees to request allowances for extraordinary processing circumstances.  The rule follows a 2019 letter from an oil and gas industry group seeking changes to the way that the royalties are calculated. The letter takes issue with matters that were addressed in the new rule, saying that gas benchmark prices were “unattainable” and arguing that subsea extraction requires additional transportation and should thus receive an allowance.  “API strongly urges the Department to consider a new rulemaking to correct these issues and to establish policies that truly do provide valuation simplicity and certainty,” API senior policy adviser Emily Hague wrote at the time.

Oil companies lock in drilling, challenging Biden on climate –  (AP) — In the closing months of the Trump administration, energy companies stockpiled enough drilling permits for western public lands to keep pumping oil for years and undercut President-elect Joe Biden's plans to curb new drilling because of climate change, according to public records and industry analysts. An Associated Press analysis of government data shows the permit stockpiling has centered on oil-rich federal lands in New Mexico and Wyoming. It accelerated during the fall as Biden was cementing his lead over President Donald Trump and peaked in December, aided by speedier permitting approvals since Trump took office. The goal for companies is to lock in drilling rights on oil and gas leases on vast public lands where they make royalty payments on any resources extracted. Biden wants to end new drilling on those same lands as part of his overhaul of how Americans get energy, with the goal of making the nation carbon neutral by 2050. Companies submitted more than 3,000 drilling permit applications in a three-month period that included the election, according to data from the U.S. Bureau of Land Management. Officials approved almost 1,400 drilling applications during that time amidst the pandemic. That's the highest number of approvals during Trump's four-year term, according to AP's analysis. In Colorado, a dozen permits are approved or pending to drill in Pawnee National Grassland, a birding destination where wildflowers and cactuses bloom below the buttes. In Wyoming’s Thunder Basin National Grassland, a prairie expanse that abounds with wildlife and offers hiking, fishing and hunting, oil companies EOG Resources and Devon Energy — which amassed the most federal permits this year — have permission to drill three dozen wells among fields of sage brush. The administration issued more than 4,700 drilling permits in 2020 — comparable to approval numbers from early last decade when oil topped $100 a barrel, roughly twice the current price. Making it easier to drill was a centerpiece of Trump's effort to boost American energy production in part by enticing companies onto lands and offshore areas run by the U.S. departments of Interior and Agriculture. Under Trump, crude production from federal and tribal lands and waters increased sharply, topping a billion barrels in 2019. That was up by almost a third from the last year of the Obama administration. But this year the coronavirus pandemic and crashing oil prices caused many companies to curtail their activity. With markets still in flux and oil producers slashing budgets, major companies nevertheless have been acquiring enough permits to keep pumping through Biden’s upcoming term. The government approved about 500 new drilling permits in September, more than double the same month in 2019.The oil industry’s fear is that Biden will follow through on campaign pledges and make it impossible or much harder to drill on public lands. “You go from having a champion in the White House, who steers the entire federal apparatus to wanting you to be successful, to someone who is hostile to the industry,”

American Petroleum Institute Chief Promises to Fight Biden and the Democrats on Drilling, Tax Policy - It’s a tough time for the nation’s oil and gas industry. Last year was among its least profitable in memory, and companies are bracing themselves for a new president focused on climate change, a Congress controlled by Democrats who increasingly shun their financial support and a world beginning to look past fossil fuels towards a cleaner energy future in which they will become smaller players, if not obsolete. That was the unspoken backdrop for a speech Wednesday by Mike Sommers, head of the American Petroleum Institute, who said that his industry was confident about its future and prepared to fight back against policies that President-elect Joe Biden had promised as a candidate, including a halt to new drilling on public lands and the elimination of billions of dollars in industry tax breaks. Speaking at API’s annual “State of American Energy” event, broadcast by video this year, Sommers asserted that his industry remains an essential part of the nation’s energy sector and economy. He noted that it continued operating throughout the pandemic and produced materials that go into face masks, gowns and other medical equipment.  He also offered a point-by-point rebuttal of policies promised by Biden and the Democrats that would limit his industry’s production and pollution, foreshadowing the looming fights they are likely to face as they try to enact a new agenda phasing out fossil fuels. A prominent part of that platform is Biden’s pledge to halt new oil and gas development on federal lands by ending new leasing or permitting for such projects. Sommers said API would do all it could to fight such a move, including leaning on members of Congress and potentially challenging a ban in court. And he tried to frame the issue not just as a threat to his industry, but to the economy. “If lawmakers curtail resource development and energy prices spike,” he said, “it’s working people and consumers who will suffer.”  Biden and clean energy advocates have argued that developing renewable energy and retrofitting buildings to be more energy efficient can generate millions of new jobs and tax revenues, without the pollution that comes from fossil fuels.  But Sommers, as part of his presentation, showed a video of a teacher in New Mexico, who warned that if drilling on federal lands were curtailed, her district would be forced to lay-off teachers and increase class sizes. The choice of New Mexico was noteworthy. Federal land in the blue state is home to part of the booming Permian Basin, which also stretches into Texas.Biden has nominated Rep. Deb Haaland, a New Mexico Democrat, to head the Interior Department, which oversees drilling on federal lands. Haaland, who is Native American, traveled to the Standing Rock Sioux camps to support the protests against the Dakota Access Pipeline in 2016, and she has expressed support for halting fossil fuel development on federal lands.

The Big Oil Money Behind Congress Members Who Fueled Attack - Two of the key ingredients for the violent insurrection were 123 House Republicans who signed onto a Texas lawsuit full of baseless claims and legal theories and more than a dozen Republican senators who invoked conspiracy theories to challenge the election results. Many of those people are in power thanks to the political donations of none other than Chevron. The company is hardly alone; other fossil fuel companies and the industry’s main trade group have also plunged money into the coffers of those who objected to a free and fair election. Earther pulled data directly from the Federal Election Commission for individual donations and aggregator site Open Secrets to see just how much corporate PACs of Chevron and Exxon, two of the largest oil companies in the U.S., and the American Petroleum Institute, the main trade group, gave members of Congress who helped inspire Wednesday’s violence with their actions and rhetoric. We also reached out to these entities to see if they would continue to fund the campaigns of any members of Congress who challenged the election results.In Chevron’s case, the company’s corporate PAC donated $745,000 to those House members over the past decade and more than $127,000 to the seditious senators. Senators Ted Cruz and Josh Hawley, who led the push to challenge election results in states they don’t represent and cheered on protesters, each received $10,000 from Chevron’s PAC in 2018. Cruz also enjoyed a $15,000 donation from the company’s PAC for his Senate run in 2012. Those donations went to helping re-elect Cruz and elect Hawley. On the House side, the PAC has spent $58,000 keeping House Minority Whip Steve Scalise in office. Scalise, who is intimately familiar with politically motivated violence having been shot at a House softball practice in 2017, baselessly saidprior to the riots that “there have been serious questions about the integrity of the electoral process.” Other recipients include Rep. Dan Crenshaw ($11,000), who put out a Mission Impossible-style video glorifying attacking political enemies ahead of the Georgia runoff; Rep. Kevin Brady ($56,500), who began to question the election before the results were even fully in; and Rep. Mark Mullwayne ($17,500), who called the attack on the Capitol a false flag even as police were trying to clear the mob. Exxon was just as generous as Chevron was with Cruz, giving him $25,000 over the course of his tenure in the Senate. The company goes way back with Sen. Marsha Blackburn, who said she would challenge the results before backing down after the violence; their first donation to her goes back to 2003 when she was running for the House, and they’ve donated to her in every election since, records show. Over the past decade, Exxon’s PAC has kicked nearly $1.5 million to guilty House members, basically twice Chevron’s investment in ending democracy. Scalise ($44,000) again cleaned up as did Brady ($52,000), It’s also given to Rep. Mo Brooks ($5,000), who also went the false flag route on the attack and also thinks sea level rise is caused by rocks falling into the ocean (sorry, but it’s my favorite fact); Rep. Barry Loudermilk ($17,000), who wanted to decertify Georgia’s results presidential results, which is very convenient for him since he represents a Georgia district; and Rep. Elise Stefanik ($33,500), one of the few women in the Republican caucus to challenge the results, whom Trump praised during impeachment proceedings as a “new Republican Star [sic].”

U.S. Supreme Court Tosses Review of Minnesota County Fracture Sand Ban - - The U.S. Supreme Court on Monday denied a petition that sought to overturn a Minnesota county ordinance banning the mining of silica sand, which is used in some Lower 48 well completions. Minnesota Sands LLC, which filed its initial lawsuit in 2017, was challenging an adverse ruling by the Supreme Court of Minnesota regarding Winona County’s ban imposed in 2016 (No. A18-0090). Five years ago Winona County banned sand mining that was commercially “valuable for use in the hydraulic fracturing of shale to obtain oil and natural gas.” However, the county still allowed the same silica sand to be mined for “local construction” uses. Minnesota Sands President Rick Frick at the time the company filed the initial lawsuit said, “Banning this type of mining based on the end use of this resource is not only unconstitutional, it takes away the rights of landowners and defies common sense…” The ban has not changed the fact that the energy industry in the U.S. has dramatically recovered from recent economic challenges and there is now a growing need for the kind of silica we are lucky to have here. “It has instead hurt people here and ignores the fact Minnesota already has a very rigorous and thorough approval and review process for any mining project.” A divided Supreme Court of Minnesota last year ruled against the company and held that the ban did not violate the U.S. Constitution’s Commerce or Takings clauses. Minnesota Sands appealed to the U.S. Supreme Court, arguing a “conflict with clear rulings” for similar lawsuits. In addition, Minnesota Sands said the state ruling threatened “an industry that is vital to the nation’s energy supply.”

Protesters gather at Line 3 construction site in Aitkin County - Opponents of the Line 3 oil pipeline replacement project gathered Saturday in northern Minnesota to protest its construction across northern Minnesota. By mid-morning, a couple hundred people had gathered near Palisade in Aitkin County, where the controversial pipeline Enbridge Energy is building is expected to cross under the Mississippi River. Opponents of the project, who call themselves water protectors, carried signs and walked down a county road. Some Native women danced in jingle dresses, a healing tradition. “There's a lot of folks that came to bring their prayers and to stand for the rivers for our future generations against big oil." The group later traveled to just south of Hill City, where they blocked traffic on U.S. Highway 169. Eight people were arrested; law enforcement officials said seven people were booked on possible charges of gross misdemeanor trespass on critical infrastructure, and the eighth person was cited and released for failing to leave an unlawful assembly.Enbridge Energy started construction on the 338-mile pipeline in December after receiving the necessary permits. Opponents have filed a federal suit seeking to halt construction on the project. The pipeline construction project is expected to employ more than 4,000 skilled workers. Supporters say it will bring additional tax revenue to northern Minnesota in a slow economy.

Line 3 protesters chain themselves together in piece of pipe (AP) — Two people accused of chaining themselves together inside a piece of pipe to protest construction of the Enbridge Energy Line 3 oil pipeline replacement in northern Minnesota were arrested Thursday morning, authorities said. Cass County Sheriff Tom Burch said the incident took place about 10:30 a.m. in McKinley Township, west of the town of Backus. He said the protesters were taken into custody without incident and face charges of trespassing and obstructing. About a dozen protesters showed up at the site. One man was arrested for refusing to leave the area and one woman was arrested for violating conditions of release on a previous arrest, Burch said. Line 3 starts in Alberta, Canada, and clips a corner of North Dakota before crossing northern Minnesota en route to Enbridge’s terminal in Superior, Wisconsin. The 337-mile (542-kilometer) line in Minnesota is the last step in replacing the deteriorating pipeline that was built in the 1960s. Construction on Thursday morning was interrupted “for about an hour or two,” Burch said. “I can’t emphasize enough how respectful the protesters are,” Burch said. “It makes everybody’s job and this whole issue a lot easier.”

Water Protectors Arrested in Minnesota After Chaining Themselves Inside Enbridge Line 3 Pipe - Water protectors were arrested Thursday after halting construction at a Minnesota worksite for Enbridge's Line 3 project by locking themselves together inside a pipe segment. "After moving to Minnesota to attend college and study environmental science, I was excited to be in a place where people valued protecting the Earth and finding a viable future. What I found, however, was a state that had formed 'ambitious' climate goals yet endorsed one of the dirtiest fossil fuels, tar sands oil," water protector Abby Hornberger said in a statement. "I realized that Indigenous ways of knowing and practicing harmony with the environment are continuously ignored." KFGO reports that Cass County Sheriff Tom Burch said two protesters who were taken into custody on Thursday now face charges of trespassing and obstructing. Hornberger explained that "the Line 3 pipeline far outweighs all clean energy initiatives and progress being made in renewable energies. Line 3 will destroy Minnesota's essential clean water resources for future generations and will ultimately drive us into climate doom. Education and spreading awareness is no longer enough to create meaningful change for me." "Enbridge's last-ditch effort to build fossil fuel infrastructure is killing people and the planet. I refuse to be complicit in settler colonialist practices, and feel that I have to put my body on the line to protect Indigenous communities' sovereignty and all of our futures," Hornberger added. "This is not just an issue relevant to some, it affects each of us on a deeper level that goes beyond our daily lives. It determines if we will have a livable future." Indigenous and environmental activists have long opposed the Canadian company's efforts to replace an aging oil pipeline with a larger one running from Alberta, through North Dakota and Minnesota, to Wisconsin — noting Enbridge's track record on spills and that cultural maps indicate "numerous sacred and significant sites lie in the path of the Line 3 project." Minnesota Gov. Tim Walz has come under fire from Indigenous and climate leaders in recent months as the state has approved key permits that Enbridge needs to complete the new Line 3, especially given the Democratic governor said publicly in February of 2019 that projects like this one "don't just need a building permit to go forward, they also need a social permit."  As some water protectors on Thursday protested inside a pipe segment a few miles from a man camp in Backus, "dozens more held space," according to the Giniw Collective. The group also pointed out that "Enbridge is working 24 hours per day at several worksites, as a pending injunction to halt work while tribally led lawsuits are heard has yet to be decided."Water protector Andrew Lee said that he participated in the action against Line 3 on Thursday "to protect the treaties that my ancestors failed to uphold." "I've learned over the course of this year that Tim Walz isn't going to protect us, the government of Minnesota isn't going to protect us, and the federal government isn't going to protect us," Lee continued. "I believe it is my duty, as a colonizer and as a person with the privilege, to do so, to put my body on the line to stop the Enbridge Corporation from building this pipeline."

Stopping Trump’s Last Pipeline Will Take All of Us - Winona LaDuke - In normal times, about 100 souls live in this small Northern Minnesota town on the banks of the Mississippi River where we are making our stand against one of the largest tar sands pipeline projects in North America. Known as Line 3, it has the potential to carry 915,000 barrels a day of dirty oil over 1000 miles, from Alberta in Canada to Superior, Wis. Palisade is the kind of place where most people know one another a couple of generations back, a town with a tiny main street and just one café. Now there are about 400 workers here—most from out of state—rolling heavy trucks and equipment down icy, windy unfamiliar roads every day. This small town is nestled in the deep woods and muskegs of Aitkin County, the lands of the Chippewa of the Mississippi, as my people are known. Akiing, the Anishinaabe word for “the land to which the people belong,” is half land and half water. Waters deep and shallow filled with wild rice, sturgeon and muskies, and all the mysteries of the deep waters. This is the only place in the world where wild rice grows. Each year in succession the manoomin returns, the only grain native to North America. This is the homeland of the Anishinaabe. And here Enbridge, the largest pipeline company in the world, is hell-bent on jamming through their Line 3 Pipeline, the company’s most massive project, under the cover of this Covid winter as fast as they can—before we can stop them and before the world takes notice.From the Water Protector Center at the edge of the pipeline route, Water Protectors gather. We hear the pounding all day long. The constant roar of heavy machinery as it rips through the forest and the wetlands. It’s brutal work, and dangerous as hell. Two weeks ago, Jorge Lopez Villafuerte was killed in the Enbridge Pipeyard, run over by a forklift. He came here from Utah for work. Instead, he found death. Enbridge halted work in the area for less than four hours—and then the pounding began again.Then there’s the armed forces, the sheriff’s office, and the Minnesota Department of Natural Resources (DNR) who have deployed here. Their wages are paid by Enbridge. That’s because Minnesota noted the $38 million bill for Standing Rock, and decided just to pay in advance. A Canadian corporation paying for the police in Minnesota. It looks like an occupation. It feels like an occupation. With all the violence that entails. First the big dozers came, then the excavators, backhoes, and buncher fellers. That last one just sort of walks through the forest, beheads a tree, drops the top to one side, and then comes back for the rest of the tree. This is how Enbridge rolls through a forest. They are gunning for the rivers now, heading straight for them: the Mississippi, the Willow, the Shell, the Little Shell, the Crow Wing: 22 rivers crossings in all. They are coming with something called a High Directional Drill. So they can drill under the river, just like they did at Standing Rock, at the Cannonball River. It feels a lot like a rape.We have been fighting this pipeline for seven years. And so far we’ve held it off in the courts and through the permitting process. The carbon output would be equivalent to opening 50 new coal plants—more carbon emissions than the entire current Minnesota economy. And all this for a dying industry. Energy companies and investors are fleeing the tar sands. Keystone XL is doomed, Dakota Access is in a legal mess (federal courts have ruled that its Environmental Impact Statement is inadequate). Enbridge itself is putting 400,000 barrels a day less through its main lines than they did a year ago. But the company still wants to sell this last pipeline. The Last Tar Sands Pipeline. Our governor, Tim Walz, took the bait. Minnesota needs real infrastructure: water, sewer, and bridges. But we’re getting a climate bomb pipeline instead.

Williams County gas processing plant, pipeline complete - Construction has finished on a natural gas processing plant west of Williston. Outrigger Energy II's Bill Sanderson Gas Processing Plant can handle up to 250 million cubic feet of natural gas per day. It's a cryogenic facility, meaning it can go further than some of the other processing plants in the state by cooling the gas enough to separate out ethane and propane from methane, the main component of raw natural gas. An 80-mile pipeline starting in southeastern Williams County connects to the facility. It will pick up natural gas from wells along the way, including from anchor customer XTO Energy, a subsidiary of ExxonMobil. The pipeline system and processing plant are not yet operational but likely will be later in 2021, as oil and gas production is expected to pick up, said Alex Woodruff, executive vice president and chief commercial officer for Outrigger. North Dakota's oil and gas output fell in 2020 amid a price collapse brought on by the coronavirus pandemic, though prices have slowly trickled back up in recent months. West Texas Intermediate crude, the U.S. pricing benchmark, hit $53 per barrel Thursday. Many oil watchers say $55 per barrel is needed to spur more drilling in North Dakota. "While Williston Basin activity levels clearly slowed due to the 2020 crude oil pricing and COVID-19 environments, we are seeing substantial interest from producers to accommodate future drilling plans as crude oil prices near sustainable levels for the Basin," Outrigger CEO Dave Keanini said in a statement. "Our assets are perfectly situated to provide producers with a competitive midstream option for both new development and volumes that are currently flaring due to infrastructure constraints."

Large power plant slated for Williston area to harness Bakken's ethane supply - A large power plant is slated to go in west of Williston that would run on ethane, an abundant component of natural gas produced in the Bakken. The developer, Bakken Midstream Natural Gas, hopes to begin construction of the $400 million facility in 2022. CEO Mike Hopkins said the plant will help alleviate the wasteful flaring of excess natural gas, provide a cheap source of electricity and help lure more “value-added” projects to the region to make use of natural gas liquids such as ethane. North Dakota produces about 350,000 barrels per day of ethane, according to the North Dakota Pipeline Authority. Ethane makes up 20% of the content of raw natural gas, which is extracted alongside oil from deep underground. Ethane and other natural gas liquids are separated from methane -- the main component of natural gas -- at processing facilities scattered throughout the Bakken. Ethane and other parts of the gas stream such as propane and butane exist in liquid form and are exported via pipeline to markets in other states. State leaders, along with the oil and gas industry, have for several years sought to attract projects to North Dakota that make use of natural gas liquids in the Bakken. “What North Dakota does not have is a lot of the infrastructure, in fact most of the infrastructure you’d want to see,” Hopkins said. Bakken Midstream formed in 2018 with a mission to develop such projects, even securing a $200,000 investment from the North Dakota Department of Commerce in 2019. State leaders have long discussed a desire to establish a petrochemical industry in North Dakota that would use ethane and other liquids. Petrochemical projects such as plastics manufacturing can be enormous in scope, and Hopkins said Bakken Midstream settled first on the power plant in an effort to achieve “something relatively near-term.” Construction is expected to take two years. Creating infrastructure for ethane in North Dakota could make the state more attractive to other companies seeking to build ethane-based projects, Hopkins said. Bakken Midstream considered focusing on developing a large gas-fired power plant, but it shifted gears to ethane given recent advances in turbine technology allowing for power generation from the substance. Using ethane to run a large power plant is a relatively new concept. It’s been used before in Asia, but on a smaller scale, Hopkins said. The Williston Basin Energy Center will have a capacity of hundreds of megawatts, he said. “It’s going to be running pretty much 24/7 as a baseload plant,” he said.

OPEC, shale output needs to rise to offset possible year-end supply squeeze: Vitol CEO | S&P Global Platts — OPEC and shale oil output will need to rise this year to help offset a potential supply squeeze by the year-end as the markets play catch-up with 2019 demand levels, the CEO of Vitol said Jan. 13. "The market is fast forwarding to a point where demand kind of catches up with where it was in 2019," Russell Hardy told the Global UAE Energy Forum 2021 organized by Gulf Intelligence. "With that catch-up, we are going to need more OPEC oil and we may need some more shale oil as well, so the market is anticipating that and it's trying to ultimately get ahead of a potential supply problem later on in the year." OPEC+ members, excluding Kazakhstan and Russia, decided to keep their output in February and March steady from January after two days of contentious talks this month. Saudi Arabia, however, surprised the market by announcing a voluntary 1 million b/d cut for February and March that has helped buoy Brent prices to nearly touch $57/b, an 11-month high. OPEC and its nine allies, led by Russia, decided in December after days of heated negotiations to ease their stringent quotas by a collective 500,000 b/d for January, instead of the originally scheduled 2 million b/d tapering. Vitol is forecasting oil demand will increase by 6 million-6.5 million b/d in 2021 -- "an enormous change," said Hardy. "Demand, it is going to get covered by additional OPEC+ production," he said. "Those increases are coming but are coming probably a tad more slowly than we might have anticipated a couple of months ago because of the virus effect here in Europe." Several European countries are in lockdown as a resurgent COVID-19 pandemic spreads through the continent. However, the roll-out of the vaccine and a cold winter are offsetting the impact of lockdowns on oil demand and prices. The US Energy Information Administration revised its crude price forecast higher in its monthly Short-Term Energy Outlook released Jan. 12 amid tightened supply outlooks and upward-trending demand projections. The EIA now expects Brent crude prices to average at around $52.75/b in 2021, up $4.25/b from its December forecast, and at $53.42/b in 2022, and the WTI spot price to average at around $49.75/b in 2021, up $4/b from its most recent report, and at $49.79/b in 2022.6:14 PM

Arctic Refuge oil lease sale an act of desperation - The first step in recovering from any addiction is to tell the truth — admit the addiction, admit its consequences. This is something we still seem unwilling to do with our addiction to oil, particularly here in Alaska. The Trump administration’s rush to drill for oil in the Arctic National Wildlife Refuge is the desperation of a junkie looking for one more fix. The lease sale this week, long-sought by oil proponents, attracted bids on only 11 of the 22 tracts offered, mostly from the State of Alaska itself. Bids totaled only about $14 million, half of which will be returned to the State of Alaska. The sale was an embarrassing bust, a spectacular humiliation for the State of Alaska and the Trump administration. For decades, oil advocates have desperately wanted to drill for oil on the Arctic Refuge coastal plain, hoping there may be eight billion barrels there. But the Refuge is also one of the most sublime Arctic wilderness areas on Earth, home to thousands of caribou, polar bears, grizzly bears, muskox, and birds, and an important subsistence region for Alaska Native peoples. Most Americans feel that oil beneath the Arctic Refuge coastal plain should stay right where it is – in the ground. Many banks agree, and will no longer finance Arctic oil projects. Against overwhelming nationwide opposition, Alaska’s Republican congressional delegation inserted the Arctic Refuge drilling provision into the 2017 tax act, ludicrously asserting that revenues from the lease sales would help offset the huge tax cuts in the bill. They won’t come close. And as president-elect Biden has promised to permanently protect the Arctic Refuge from drilling, the Trump administration rushed to hold the Refuge oil lease sale just two weeks before leaving office. Worried that no major oil companies would bid, the State of Alaska bid on eleven Refuge tracts itself, although under federal law it is almost certainly an ineligible bidder. In fact, except for two small independent bids, the state was the only bidder. The Department of Interior’s Inspector General is already investigating the propriety of the state’s bids. This is a spectacular humiliation for oil advocates who long wanted this sale. Alaska’s continuing resistance to embracing an oil-free future is a bit like the last Japanese soldier refusing to surrender until almost 30 years after the end of WWII. As an energy analyst once said: “The Stone Age didn’t end for lack of stones, and the oil age will end long before the world runs out of oil.” And now the oil age is winding down, many in Alaska can’t seem to grasp this fact.

LNG Canada Conduit Coastal GasLink, Other BC Energy Projects Temper Labor Force on Covid Outbreak - Construction schedules are under review in British Columbia (BC) for its entry into the global natural gas export market as a result of labor force limits that provincial public health authorities adopted to counter the impacts from the pandemic. “Long-term impacts to the overall schedule continue to be assessed,” said TC Energy Corp. Vice President Tracy Robinson. Robinson also is president of the Coastal GasLink (CGL) supply pipeline underway across the province that would move gas to the Royal Dutch Shell plc-led liquefied natural gas (LNG) export project, LNG Canada. CGL initially would transport more than 1.7 Bcf/d from the Montney, Horn River and Cordova basins in the Dawson Creek area. At the northern Pacific coast terminal construction in Kitimat, LNG Canada construction manager Vince Kenny and JGC I Fluor JV director Berni Molz said a staged work plan is being devised to comply with the provincial pandemic control order. “As work at site progresses with a reduced workforce, our focus will be on environmentally sensitive, regulatory required, and time-sensitive work scopes,” said Kenny and Molz. “We remain committed to delivering first cargo by the middle of this decade.” Work plans are also being crafted for BC’s approval at Coastal GasLink, Robinson said. “In the immediate term there will be significant impacts to our ability to ramp up our workforce and progress project construction.” The construction labor limits, ordered at the end of 2020, followed Covid-19 outbreaks in December across industrial activity areas served by BC’s Northern Health Area. The directive affects not only activity at CGL and LNG Canada. LNG Canada last March had reduced its workforce by half as the pandemic began spreading across North America. Three other big energy construction projects included in the BC directive are BC Hydro’s Site C Dam near Fort St. John, the Trans Mountain Pipeline oil supply expansion, and the Rio Tinto Kemano power plant to serve a Kitimat aluminum smelter. The rules allowed this year’s planned CGL construction labor force to start at 400 workers in early January and grow in stages to 1,223 as of February. The LNG Canada quota started at 512, increased to 1,162 as of next week (Jan. 20), and is open to grow later. Although the Trans Mountain project has to adapt to similar public health restrictions, the oil pipeline’s sponsors have informed the Canada Energy Regulator that its BC construction schedule has not changed. No worker quotas have been ordered on the expansion project’s Alberta legs.

Big Panama with a Purple Hat Band - Propane Price Squeeze, Panama Canal Rules Fluster Market - It’s been a chaotic start to the new year for propane. In the past 12 days, the Mont Belvieu price is up over 15%, closing on Tuesday at 87 cents/gallon — the highest since October 2018. The usual culprit of winter weather has something to do with it, but not just in North America. Over the past couple of weeks, frigid temperatures in Asia, along with supply cutbacks from the Saudis, have supported U.S. propane exports to those markets, further tightening the U.S. supply/demand balance. But as is often the case these days, the market has another complicating factor. Delays transiting the Panama Canal have stacked up VLGCs — the vessels carrying U.S. propane to Asia — on both the Atlantic and Pacific sides of the waterway, pushing up charter rates to levels not seen in years. And on top of that, new transit-scheduling rules from the Panama Canal Authority will shove VLGCs to the back of the line, potentially making it even more difficult to get through the canal without significant delays. Today, we’ll explore these developments and what they may portend for the remaining weeks of winter.As we blogged about in November and December (Now You See It), the possibility for a propane price squeeze has been coming at us for several weeks. Even though the U.S. entered the propane winter season with healthy inventories, exports have been running at all-time highs and stocks have been declining rapidly. We were concerned that average days-supply, when calculated using both domestic demand and exports, had dropped to a five-year low, and that the market could get very tight, warning that “the wild ride for propane prices seen in the fourth quarter could get wilder still.”And it has. In Mont Belvieu, as mentioned above, the price of propane blasted into the stratosphere during the first few days of the New Year, reflecting not only cold weather in the U.S., but skyrocketing prices in Asia due not only to record- or near-record-low temperatures in Japan, South Korea, and northeastern China, but also to shipping and global supply issues. We’ll get back to that in a minute. But first, let’s consider how propane prices have behaved so far in 2021.

EXCLUSIVE-U.S. tells European companies they face sanctions risk on Nord Stream 2 pipeline (Reuters) - The U.S. State Department this month told European companies which it suspects are helping to build Russia’s Nord Stream 2 gas pipeline that they face the risk of sanctions as the outgoing Trump administration prepares a final round of punitive measures against the project, two sources said on Tuesday. “We are trying to inform companies of the risk and urge them to pull out before it’s too late,” The U.S. source said the State Department is expected to issue a report by Thursday or Friday on companies it believes are helping the Russia-to-Germany pipeline. Companies that could be in the report include ones providing insurance, helping to lay the undersea pipeline, or verify the project’s construction equipment, the source said. The companies could be at risk of U.S. sanctions under existing law if they do not stop work. Zurich Insurance Group could be listed in the report, the source said. The company did not immediately respond to a request for comment. The $11 billion pipeline, one of Russia’s most important projects in Europe, has sparked tensions between Washington and Moscow. The Trump administration opposes Nord Stream 2, which would deprive Ukraine of lucrative transit fees, saying it would increase Russia’s economic and political leverage over Europe. The administration has also pushed exports of U.S. liquefied natural gas to Europe, a fuel that competes with pipelined gas from Russia. The Kremlin says Nord Stream 2, led by state energy company Gazprom, is a commercial project. Germany, Europe’s biggest economy, also says the pipeline is simply commercial. It needs gas as it shuts coal and nuclear plants on environmental and safety concerns. U.S. President-elect Joe Biden opposed the project when he was vice president under Barack Obama. It is uncertain whether he would be willing to compromise on the project after Jan. 20 when he takes over.

NS2 Set to Finish Bulk of Work on One Line in June-- Nord Stream 2 AG plans to complete major construction work on one of two branches of the controversial Russian gas link in the first half of 2021, despite U.S. sanctions that have threatened its completion for over a year. The section of pipe could be largely finished as soon as June, as the operator of Nord Stream 2 starts some testing in Danish waters on Friday, according to a schedule seen by Bloomberg that was confirmed by people familiar with the process. Construction of the 1,230-kilometer (764-mile) gas pipeline that will deliver Russia’s natural gas to Germany was halted after U.S. sanctions in December 2019, when all but 160 kilometers of the link had been put in place. The U.S. -- which has tightened restrictions -- maintains that the gas link, owned by a unit of Gazprom PJSC, gives Moscow too much leverage over Europe. Construction of a 2.6-kilometer section in German waters resumed and was finished last month amid risks of tighter U.S. restrictions. Recovery of the already laid pipes in Danish waters will start in the second half of January and the new laying operation there will start around the same time, according to the schedule. The pipelaying vessel Fortuna is expected to complete works in Danish seas by the middle of the last week of May, and then start in German waters with construction going through to June, according to the document. While the assumed speed of Fortuna’s pipelaying is 0.4 kilometers per day, completing the first line may take longer as it depends on the results of a drilling survey and weather conditions. Germany’s Maritime and Hydrographic Agency is still evaluating the request of Nord Stream 2 to move forward with works in German waters, according to a spokeswoman. The Danish and German regulators declined to comment on the schedule. Nord Stream 2 didn’t immediately respond to Bloomberg requests for comments.

Big freeze exposes Asia's underlying energy crisis: Kemp - Northeast Asia has been hit by a midwinter energy crisis as an extended period of temperatures much lower than normal across the region has strained supplies of coal, gas and electricity to breaking point. China has been forced to restrict power in multiple provinces, Japan has appealed for voluntary restraint, and LNG prices have surged to record highs as generators and utilities scramble for spot cargoes. Freezing temperatures may have been the trigger for the crisis, but it reveals a deeper lack of resilience in regional energy systems caused by the rapid transition to gas for space heating and power generation. Japan has failed to restart or replace nuclear generation a decade after the Fukushima disaster, which has left the country with too little generation capacity and excessive reliance on imported gas. China’s rapid transition from coal to gas for urban heating systems has tightened gas supplies while the rapid growth in household and industrial electricity consumption is straining the electrical grid. More broadly across Asia, rapid growth, rising incomes and surging electricity demand is stretching generation systems and availability to import enough LNG at peak times. Every energy crisis has four elements: 1) pre-crisis erosion of spare production capacity and/or inventories in the face of rapidly increasingly consumption; 2) failure to appreciate the increasing risk and take timely preventive action; 3) a short-term trigger that turns potential shortage into actual shortage; and 4) panicked over-reaction when the shortages finally arrive. The energy crisis that has hit Asia in 2020/21 exhibits many of the same characteristics as crises that hit Britain in 1946/47 and the United States in 1973/74. The common thread in all three is that abnormal weather or a supply disruption aggravated an underlying energy shortage and brought the crisis to a sudden head; signs of a crisis had been evident months earlier but were not acted upon with sufficient urgency.

Venezuela Refuels Its Territorial Dispute With Guyana in Area With Massive Offshore Oil Find - Political tensions between Guyana and Venezuela are escalating in a longstanding border dispute over an area that comprises two-thirds of the smaller English-speaking South American country. The area in question is the resource-rich Essequibo province, where energy giant ExxonMobil began oil exploration in 2008. The company recently discovered significant oil and gas reserves in Guyana, placing the country on the threshold of an economic boon.On January 9, Venezuelan president Nicolás Maduro announced that he would “reconquer” the province, which is situated to the west of Guyana's Essequibo River. While the area's riches include gold, diamonds and timber, the focus of Venezuela's claim is offshore—the location of ExxonMobil's massive Liza oil field, which the company estimates will produce approximately 120,000 barrels of oil per day. In its project overview, ExxonMobil describes the area as part of the Stabroek Block, calling it “the first significant oil find offshore Guyana.”The discovery of Guyana's oil and gas resources has made the country the newest kid on the block in the global energy industry, whereas Venezuela is a well-established player. Despite the fact that Venezuela enjoys the largest oil reserves in the world, with more than 300 billion barrels, the nation has been teetering on the brink of socio-economic collapse for the past several years. The crisis grew deeper in 2017, after the country's Supreme Court of Justice nullified its National Assembly.In 2019, President Maduro ordered that charges of treason be slapped on opposition leader Juan Guaidó for allegedly agreeing to forego Venezuela's claim to the Essequibo province. The renewed push from Venezuela follows the inauguration, on January 5 this year, of a pro-Maduro National Assembly, the legitimacy of which is being questioned by the opposition.Meanwhile, Guyana's president Irfaan Ali called Maduro's claim “a legal nullity,” On the heels of joint United States/Guyana coast guard exercises on January 8, Admiral Craig Faller, Commander of the US Southern Command, arrived in Guyana on January 11 for a three-day visit—a signal that the outgoing Trump administration's interest is firmly aligned with Guyana's.

Exxon’s Mega Oil Finds In Guyana Are Just The Beginning - Like many global oil majors ExxonMobil is under considerable pressure because of the significant fallout from the COVID-19 pandemic, sharply weaker oil prices and the threat of peak oil demand. There are growing fears that Exxon, because of its tremendous debt burden, is a zombie company. These are generally companies that are not generating sufficient operating income to cover its interest expenses. While Exxon is struggling because of the prolonged slump in oil prices reporting a $2.4 billion loss for the first nine months of 2020 and deteriorating cashflow it is not yet a zombie company. The global oil supermajor has several levers at its disposal to boost profitability and cash flow, key being the improved outlook for oil prices along with Exxon’s globally diversified portfolio of quality energy assets. In response to sharply weaker oil prices and the need to boost profitability Exxon announced during November 2020 that it intended to prioritize capital spending for high value assets, key among them being its operations in the Guyana-Suriname Basin located in offshore South America.   Exxon made its first Guyana oil discovery in the offshore Stabroek Block during May 2015. By December 2019, the integrated energy major had commenced production at the Liza oilfield with the capacity to pump 120,000 barrels daily. During September 2020, Exxon made its 18th oil discovery in the Stabroek Block and upgraded its estimate of recoverable oil resources to more than 8 billion barrels.  That month Exxon announced it will proceed with developing the Payara oilfield, in the Stabroek Block, which will come on-line in 2024 possessing the capacity to pump 220,000 barrels daily. By December 2020 Exxon had achieved its production goal for the Liza field and the company anticipates producing more than 750,000 barrels daily from the 6.6-million-acre Stabroek Block by 2026. This is a highly profitable asset for the integrated oil major, even with weaker oil prices, because of its particularly low breakeven costs. According to partner Hess, which has a 30% interest in the block alongside Exxon’s 45% and CNOOC's 25%, the Liza oilfield is pumping crude oil at a breakeven price of $35 per barrel, and this will fall further. Hess claims that the breakeven price for the second FPSO to be deployed, Liza Unity which is scheduled to commence operations in 2022, will pump crude at an even lower breakeven price of around $25 per barrel. With an API gravity of 32 degrees and 0.58% sulfur content, the crude oil produced from the Liza field is relatively easily and cost effectively refined into high quality low sulfur content fuels. That will ensure that it does not sell at a significant discount to the international Brent price benchmark.

Total Makes Significant Oil Find -Total has announced that it and Apache Corporation (Nasdaq: APA) have made a “significant” new oil and gas discovery at the Keskesi East-1 well in Block 58 off the coast of Suriname. The well was drilled at a water depth of about 2,380 feet and was said to have encountered a total of 206 feet of hydrocarbons, comprising 190 feet net of black oil, volatile oil, and gas pay in good quality Campano-Maastrichtian reservoirs, and 16 feet of net volatile oil pay in Santonian reservoirs. Drilling is still ongoing for deeper Neocomian aged targets, Total revealed. The company’s latest find follows previous discoveries at Maka Central, announced in January last year, Sapakara West, announced in April last year, and Kwaskwasi, announced in July last year, Total highlighted. “We are delighted to announce this new discovery, which confirms this first exploration campaign as a full success and adds to the proven resource base” Kevin McLachlan, the senior vice president of exploration at Total, said in a company statement. Pursuant to the terms of its joint venture agreement, Apache transferred operatorship of Block 58 to Total S.A. on Jan. 1, 2021. Back in December 2019, Total announced that it had signed an agreement with Apache to acquire a 50 percent working interest and operatorship in the “highly prospective Block 58 offshore Suriname”. In addition to its discoveries offshore Suriname, Total has also made notable finds in other areas of the globe recently. At the end of October last year, for example, the company announced a significant gas condensate discovery on the Luiperd prospect, which is located on Block 11B/12B in the Outeniqua Basin off the southern coast of South Africa. Total also made a gas discovery with the Bashrush well on the North El Hammad license in July 2020 and a gas and condensate discovery in the North Sea in March 2020

The Most Important Oil Find Of The Next Decade Could Be Here - A potential high upside opportunity in the oil and gas sector is unfolding that offers one of the most attractive risk/reward profiles this industry has seen in quite a while.This opportunity is with a small oil explorer sitting on a supermajor-sized oil and gas basin...and yet the company is still currently flying very much under Wall Street’s radar. Reconnaissance Energy Africa is a small $300+ million company that has secured petroleum licenses for an entire sedimentary basin in Namibia and Botswana...two extremely resource-friendly countries with very low royalties fees.This basin – as deep as the Permian – could prove to be one of the world’s last-ever giant onshore oil discoveries.   And as a new basin, the potential is likely for Conventional Oil and Gas. No Fracking, normal production profiles, low water requirements which means low cost per barrel.And Recon Africa has secured the petroleum licensing rights to the entire basin.With one of the world’s largest onshore, undeveloped hydrocarbon basins – whose potential has been analyzed and acknowledged by some of the industry’s most sought-after experts – the oil that is hoped to be discovered by Recon Africa could ultimately prove to be worth tens of billions.This isn’t an investment with simply ordinary profit potential. We’re talking about a true “lottery ticket” – potentially the largest oil discovery in the last 20 to 30 years. They just have to make that big discovery.  And, again, one small-cap company has secured the rights to all of it.

Nigeria's Forcados crude exports on force majeure due to pipeline closure: Shell  -— Loadings of Nigeria's key export grade Forcados are on force majeure due to the shutdown of the Trans Forcados pipeline, terminal operator Shell said late Jan. 14. The force majeure took effect from 1000 local time (0900 GMT) on Jan. 14, a Shell spokesperson said. A representative at Heritage said the Trans Forcados pipeline had initially shut down for "maintenance services" but "community disturbances" had disrupted the exercise. The pipeline therefore remained shut for longer than scheduled, leading to Shell declaring force majeure, the source said. Forcados is a gasoil-rich sweet crude blend and is one of Nigeria's top export grades. Output has averaged around 250,000 b/d over recent months. Nigerian oil output has fallen sharply in the past six months as it has come under pressure to adhere to its OPEC+ cut obligations. Some of the country's key grades have had faced outages. Exports of Qua Iboe are also currently on force majeure due to production issues triggered by a fire at the Qua Iboe terminal in mid-December. Exports of Brass River were on force majeure from late November to mid-December after a sabotage attack on an oil and gas pipeline. Nigeria's crude and condensate production slumped to around 1.66 million b/d in 2020 from 2.04 million b/d in 2019, according to S&P Global Platts estimates. This was its lowest annual output figure since 2016 when militancy in the Niger Delta pushed output to as low as 1.60 million b/d. Last week, a coalition of former oil rebels in the Niger Delta, now known as the Reformed Niger Delta Avengers, threatened to resume attacks on oil installations in the country's main oil producing region. A presidential amnesty program for militants to maintain peace in the Niger Delta remains in place but there are concerns that militancy might be picking up again.

LNG-Asian spot prices rise to record high = (Reuters) - Asian spot prices for liquefied natural gas (LNG) jumped nearly 50% this week to a record high, based on available data going back to 2009, as logistical issues disrupt supply to the world’s top consuming region. The average LNG price for February delivery into northeast Asia LNG-AS is estimated to be around $21.45 per million British thermal units (mmBtu), according to pricing agency S&P Global Platts, up 47% from the previous week ($14.60). The price is a record high since Platts started assessing the Japan-Korea-Marker (JKM) in Feb. 2009, which combines deals from some of the world’s biggest consumers and became the reference price for spot deals. Spot Asian LNG prices led the global energy complex last year, gaining more than 140% on booming demand and outages in key suppliers. The rally this week - eight months after the JKM fell to an all-time low of $1.82/mmBtu - partially results from strong demand for heating during a colder-than-average winter and a shortage of supply in key producing countries such as Malaysia. Japanese power generators are reducing run rates on their gas plants as they compete with LNG buyers across northern Asia. Demand is also expected to grow in China. In addition, there have been logistical constraints in bringing supply from the United States and Europe to the Pacific.

Winter LNG Boom Means Most Expensive Cargo Ships in History - An unprecedented shortage of liquefied natural gas tankers has made them the most expensive ships ever hired to ferry commodities. Spot rates have more than tripled in the past month, with BP Plc last week paying $350,000 a day to charter an LNG tanker to pick up a cargo from the U.S. The previous high for any kind of commodity carrier was set in late 2019 when a crude supertanker was booked for daily earnings of $308,000, according to data compiled by Clarkson Research Services Ltd., a unit of the world’s biggest shipbroker. Bullish factors have struck the LNG shipping market: robust Asian spot gas demand in a cold winter, record-high exports from U.S. projects and -- perhaps most importantly -- delays to traverse the Panama Canal. Vessels have been forced to take longer routes to Asia, increasing transport time and significantly curbing the amount of available vessels in the Atlantic. “These are historically high levels,” said Per Christian Fett, global head of LNG at shipbroker Fearnleys A/S. “We are getting a lot of requirement where we really struggle to find a suitable vessel.” Spot LNG tanker rates in the Atlantic basin rose to a record $322,500 a day on Friday, up $99,000 from Jan. 5, according to Spark Commodities, which takes assessments from LNG shipbrokers. Meanwhile, the Pacific spot tanker rates increased to $221,750 a day, according to Spark. The high in daily earnings recorded by Clarkson Research is for commodity-carrying vessels, not container ships that transport finished goods. The same factors have pused prices for prompt cargoes to records. Japan-Korea Marker, the regional benchmark, rose almost 32% to $28.221 per million British thermal units on Monday, according to S&P Global Platts.

Trucked LNG Prices Spiked in China as Cold Gripped Region in December, Says Wood Mackenzie - Cold weather and a scramble to secure natural gas supplies in Asia are impacting more than only power generators, as spot prices for trucked liquefied natural gas (LNG) in China skyrocketed last month, according to Wood Mackenzie. The consultancy said spot prices in the LNG transport space nearly doubled in only three weeks in the Hebei, southern Jiangsu and southern Guangdong regions. According to delivered price indices, trucked LNG peaked at $28.00/MMBtu on Dec. 21 in the Hebei and Jiangsu regions. Prices then dropped sharply and increased with another cold snap in late December, Wood Mackenzie said. China has worked to increase domestic natural gas production and implement more flexibility on the demand side following shortages in recent years, establishing seasonal pricing, winter gas contracts and interruptible demand, Wood Mackenzie added. The national oil companies also said heading into the winter that the country would be well stocked with natural gas supplies, but a perfect storm in Asia was building starting in late November, leaving the gas market stretched. “The price spike came as a huge surprise to market participants,” said Wood Mackenzie research director Miaoru Huang. “Before winter started, consensus was that there would be a well supplied market with subdued trucked LNG prices, as was the case for most of 2020. As a result, trucked LNG supply had been tightened to make room for piped gas in the current winter season.” Winter gas demand has increased due to a strong economic recovery following the outbreak of Covid-19 in China. Continuing coal-to-gas switching among residential users and extremely cold weather this winter, where temperatures have dropped to some of their lowest in decades, also have contributed to the rise. Finally, logistical issues contributed to the spike as roads were frozen and an import terminal in southern China was knocked offline until late December after a fire. Wood Mackenzie said LNG makes up less than 20% of China’s gas demand each year. However, the firm said prices are highly sensitive to market balance, especially during the winter.

China's Bohai Bay energy terminals on alert as sea ice slows ships  (Reuters) - Chinese ports and marine safety authorities are on high alert as an expansion of sea ice makes it tougher for ships to berth and discharge at key energy product import terminals along the coast of northern Bohai Bay. A cold wave sweeping the northern hemisphere has plunged temperatures across China to their lowest in decades, boosting demand for power and fuel to historic highs in the world’s largest energy consumer. “The sea ice situation is more severe this year than the same period in previous years,” said Wang Jun, a professor specialising in transport issues at Dalian Maritime University. “It could impede sailing and docking for vessels, no matter how big they are.” Weather officials warned against severe frost this week in the region, with sea ice stretching 45 to 55 nautical miles at Liaodong Bay and 10 to 20 nautical miles at Bohai Bay, close to levels that could prompt temporary bans on shipping. Last weekend, the marine safety bureau in northern Hebei sent several tugboats to the aid of vessels, such as LNG tanker Clean Planet and coal bulk tanker Agia Eirini Force, trapped in sea ice that was 1 meter (3 ft) thick, to help bring them to Caofeidian and Huanghua ports, state television said. The Agia Eirini Force is seen leaving China on Tuesday but Clean Planet’s latest location has not been updated, shipping data on Refinitiv Eikon showed. Marine authorities and ports in Tianjin, Hebei and Liaoning province are closely monitoring weather conditions and sending drones and ice-breaking tugs to clear the fairway for expected vessels, they said.

Goldman Flips On NatGas, Warns Of Bullish "Perfect Storm"  - Goldman Sachs has flipped on their bearish natural gas stance to a bullish one. Goldman's Samantha Dart's reasoning behind the view shift is due to a combination of factors including "supply disruptions, shipping delays, and strong LNG demand, supported by heavy nuclear maintenance in Japan and a cold start of the year in NE Asia, have significantly tightened the LNG market." Prices of the supercooled fuel in especially Asia have reached astronomic heights in recent days. The most critical LNG markets are in Asia and Europe, which comes as a polar vortex split that has dumped Arctic air in both regions, boosting natgas prices. Goldman points out LNG Asian benchmark JKM has jumped to a fresh all-time high of $32/mmBtu today as the "market struggle to ration demand while supply takes weeks to move incremental Atlantic Basin supply into Asia." While LNG prices are soaring in Asia, cold weather in Europe has led to the Dutch Title Transfer Facility (TTF) physical short-term gas and gas futures contract to soar 29% higher to $9.43/mmBtu in the last two days. Goldman suggests that "even deeper-than-expected drop in NW European LNG deliveries, we now see European balances even tighter." Colder-than-average temperatures have provided significant support for European natgas demand. "TTF price forecasts skewed to the upside," Goldman said, adding that it's due to "weather-driven tightness realized thus far." We see risks to our revised TTF price forecasts skewed to the upside as, given the LNG and weather-driven tightness realized thus far, we believe that even a warm turn to the weather would not be enough to take this year's storage path towards a capacity breach. This effectively eliminates the risk that TTF may need to sell off this winter to once again close the US LNG export arb. Hence, with warm weather risks less relevant, we update our weather scenario analysis to focus on colder-than-average scenarios only. Importantly, our previous iteration of this analysis had already shown the explosive potential for TTF prices. -Goldman Colder weather in Europe has also resulted in Spanish natgas prices hitting a record high.

Perfect Storm Driving Meteoric Rise in Asian LNG Prices Could Happen Again - On the supply side, you’ve had a series of global supply outages rolling on since late summer in Australia, Malaysia, Qatar, Nigeria, Trinidad and Tobago, and Norway. Generally, the supply picture has been underperforming relative to historic levels, and that has basically increased northeast Asia’s call on Atlantic Basin cargoes coming out of the United States and the European market. Those are some of the more expensive supplies for the Asian market, which has been driving prices up. There’s also been growth in Asian demand as the region has handled the pandemic better than countries in the West, which has left economic activity less disrupted. There’s also been very intense cold, which has really been driving things up in the last few weeks. We have been seeing this particularly acutely in Japan in recent days. In the meantime, China has been building up coal-to-gas switching, adding millions and millions of households that have now switched onto the gas market. A lot of the cargoes we’ve seen taken out of the European market have supplied the Chinese market in particular. The freight picture is extremely tight right now, with a recent record rate to charter an LNG vessel of $350,000/day. Last summer, we were around $30,000-40,000/day to charter a vessel. You’re really having to pay through the nose right now to convince another company to sublet you their vessel. There has been a big increase among portfolio players and aggregators buying up shipping capacity, so there’s not that much left over in the spot market when things are very tight. There are people trying to get spot vessels to close this arbitrage to make reloads from Europe to Asia, but they’re having to pay to do so. When you have U.S. cargoes going across the Atlantic to Europe, you don’t need that many vessels to deliver a certain amount of LNG, but when those vessels are going to Asia, you need about double the shipping tonnage. When a large proportion of U.S. LNG is going to Asia, it’s going via the Panama Canal and capacity to get through the waterway is being maxed out. There has been an increase in wait times outside of the Panama Canal of up to 10 days, which then adds to the shipping costs and the Japan Korea Marker (JKM) has to go even higher to attract those cargoes. The cargoes are also bypassing delays at the Panama Canal by going around the Cape of Good Hope, the longest possible way U.S. cargoes can get to northeast Asia. And as a final recourse, that hasn’t been enough to satisfy northeast Asian demand. The market is now unlocking European reloads to go to Asia, which is another very long shipping route. In order for the JKM to price on those deliveries from Europe to northeast Asia, buyers are having to pay a substantial shipping cost. We are so tight right now at the end of January, start of February — and it takes about a month to get a cargo out of the Atlantic Basin — that it is virtually impossible to get a cargo on short enough notice to close the arbitrage. You can only really get a cargo into northeast Asia from the Atlantic Basin by the second half of February into March. The record prices we’re seeing amid this cold snap really represent an inability to get a marginal cargo and a real scramble to convince someone else in northeast Asia to not take delivery of their cargo, but to give it to someone shorter on supply.

Goldman Discovers An Unexpected Source Of Demand For 1 Million b/d Of Oil - Having recently turned even more bullish on the oil market, bringing forward up its year-end $65 Brent price target to the summer on Monday, overnight Goldman's commodity team turned even more bullish on oil, "discovering" an unexpected source of oil demand in the near term, which could lead to even higher oil prices in coming days. Specifically, according to to Goldman's Damien Courvalin, global oil demand will be boosted by at least 1 million b/d in the coming weeks as cold weather spurs the use of diesel for power generation.As Courvalin explains, frigid temperatures in Asia and Europe in the face of LNG supply issues have led to a surge in local gas prices. Specifically, the record-high JKM prices we discussed yesterday..... have moved well past diesel substitution in power generation although the rally in TTF this week is still short of fuel oil parity. Goldman believes this substitution-induced price surge could lead to at least a 1 mm b/d boost to global oil demand in coming weeks, with an upside potential of 1.5mb/d (especially if TTF prices rally past $10/mmBtu).Goldman based this estimate on the precedent of the 2017 cold winter, grossing up OECD data to the rest of Asia. As the bank explains, "a simple top-down weather model on Asia and EU winter heating demand confirms that the recent cold wave would boost demand by 1mb/d, even before the impact of additional fuel substitution under such extreme price dislocations (with working-from-home dynamics pointing to a potentially even stronger demand impact)." The steady decline in oil burn power generation capacity in recent years ultimately limits the magnitude of this substitution, likely explaining the magnitude of the JKM gas rally which is now solving for end-demand destruction in the LNG trucking and industrial sectors. This in turn will provide additional support to on-road diesel and LPG demand, according to Courvalin.To be sure, such demand support will be transient, with higher expected LNG arrivals in coming weeks and milder Asian weather forecasts. That said, assuming even a mere three-week impact, this transitory demand spike "will nonetheless help offset half of the c.1.5 mb/d decline in global transportation demand" that Goldman expects in January due to spreading lockdowns (with the split polar vortex potentially leading to additional cold spells).

OPEC maintains 2021 oil demand growth forecast, warns outlook clouded by pandemic fears — Oil producer group OPEC on Thursday kept its 2021 forecast for global crude demand growth unchanged, but warned uncertainties over the impact of the coronavirus pandemic remain high. The closely watched oil market report comes as Covid cases continue to surge worldwide, with new lockdowns imposed in Europe and parts of China. In recent weeks, optimism about the mass rollout of coronavirus vaccines appears to have been tempered by the resurgent rate of virus spread. It has resulted in oil producers trying to orchestrate a delicate balancing act between supply and demand as factors including the pace of the pandemic response continue to cloud the outlook. "Uncertainties remain high going forward with the main downside risks being issues related to COVID-19 containment measures and the impact of the pandemic on consumer behavior," OPEC said Thursday. "These will also include how many countries are adapting lockdown measures, and for how long. At the same time, quicker vaccination plans and a recovery in consumer confidence provide some upside optimism." The 13-member group said it expected global oil demand in 2021 to increase by 5.9 million barrels per day year on year to average 95.9 million barrels per day. The forecast was unchanged from last month's assessment. The group said world oil demand growth in 2020 declined by 9.8 million barrels per day year on year to average 90 million barrels per day. The group noted the fall was marginally less than expected in December. OPEC said its 2021 forecasts "assume a healthy recovery in economic activities including industrial production, an improving labour market and higher vehicle sales than in 2020." "Accordingly, oil demand is anticipated to rise steadily this year supported primarily by transportation and industrial fuels," the group said. OPEC and its non-OPEC allies, an alliance sometimes referred to as OPEC+, cut oil production by a record amount in 2020 in an effort to support prices, as strict public health measures worldwide coincided with a fuel demand shock. OPEC+ initially agreed to cut output by 9.7 million bpd, before easing cuts to 7.7 million and eventually scaling back further to 7.2 million from January. OPEC kingpin Saudi Arabia has since said it plans to cut output by an extra 1 million barrels per day in February and March to stop inventories from building up.

Oil prices fall on renewed coronavirus concerns as China cases mount - Oil prices fell on Monday on renewed concerns about global fuel demand amid strict coronavirus lockdowns in Europe and new movement restrictions in China, the world's second-largest oil user, after a jump in cases there. Brent crude oil futures fell 46 cents, or 0.84%, to $55.52 a barrel after earlier climbing to $56.39, its highest since Feb. 25, 2020. Brent rose in the previous four sessions. U.S. West Texas Intermediate (WTI) slipped 21 cents, or 0.4%, to $52.03 a barrel. WTI rose to its highest in nearly a year on Friday. "Covid hot spots flaring again in Asia, with 11 million people (in) lockdowns in China Hebei province... along with a touch of FED policy uncertainty has triggered some profit taking out of the gates this morning," Stephen Innes, chief global market strategist at Axi, said in a note on Monday. Mainland China saw its biggest daily increase in COVID-19 cases in more than five months, the country's national health authority said on Monday, as new infections in Hebei province, which surrounds the capital Beijing, continued to rise. Shijiazhuang, Hebei's capital and epicentre of the new outbreak in the province, is in lockdown with people and vehicles barred from leaving the city as authorities move to curb the spread of the disease. Most of Europe is now under the strictest restrictions, according to the Oxford stringency index, which assesses indicators such as travel bans and the closure of schools and workplaces. Still, the oil price losses were curbed by plans for U.S. President-elect Joe Biden to announce trillions of dollars in new coronavirus relief bills this week, much of which will be paid for by increased borrowing. Crude prices remained supported by Saudi Arabia's pledge last week for a voluntary oil output cut of 1 million barrels per day (bpd) in February and March as part of a deal under which most OPEC+ producers will hold production steady during new lockdowns. "Oil is still pricing in a great deal of optimism linked to the rollout of Covid-19 vaccines," Innes said. "Demand will always improve as the vaccines roll out, and the supply side is under control thanks to OPEC+ and Saudi Arabia's continued efforts."

Oil erases loss to end near unchanged | Morningstar - Oil futures erased an early loss, with the U.S. benchmark eking out a tiny gain to close at a 10-month high as pressure from a rising dollar and worries over a COVID-related hit to demand was overshadowed by optimism over prospects for near-term exports.West Texas Intermediate crude for February delivery rose a penny to finish at $52.25 a barrel on the New York Mercantile Exchange, the highest close for a front-month contract since Feb. 21. March Brent crude , the global benchmark, dropped 33 cents, or 0.6%, to settle at $55.66 a barrel a barrel on ICE Futures Europe.WTI's outperformance of Brent -- the March WTI contract -- also rose by a cent to close at $51.51 a barrel-- comes as Iraq, Kuwait, and the United Arab Emirates all followed Saudi Arabia's lead and raised prices to Asia customers in recent days, noted Robert Yawger, director of energy futures at Mizuho Securities, in a note."The move opens the door for U.S. producers to fill the void and export more barrels to Asia," he said, noting that Bloomberg reported U.S. Gulf crude exports to Asia rose by 33.8 million barrels in December from 28.6 million barrels in November.Brent, meanwhile, felt pressure on renewed concerns about rising coronavirus cases around the world, resulting in tighter lockdowns, as well as a bounce for the U.S. dollar.Oil surged last week, with both Brent and WTI trading at levels last seen in early February, boosted in part by Saudi Arabia's surprise decision to cut production by 1 million barrels a day in February and March.  The dollar was higher versus major rivals. lifting the ICE U.S. Dollar Index , a measure of the currency against a basket of six major rivals, by 0.4%. The index has fallen sharply since last March and hit a more than 2 1/2-year low last week before beginning to push higher as yields on Treasury notes rose last week.Commodities and the dollar often show an inverse relationship. A weaker dollar makes commodities priced in the greenback less expensive to users of other currencies, while a stronger dollar makes them more expensive. Meanwhile, the U.S. saw at least 208,338 new cases of COVID-19 reported on Sunday, according to a New York Times tracker, and counted at least 1,777 deaths, numbers that may be underreported due to lower weekend staffing. On Friday, the U.S. set a single-day record of more than 300,000 new cases. In the past week, the U.S. has averaged 254,866 cases a day, numbers that experts had warned would materialize if Americans traveled in large numbers during the recent holiday season. February natural-gas futures rose 4.7 cents, or 1.7%, to end at $2.747 per million British thermal units. February gasoline declined 2.15 cents, or 1.4%, finishing at $1.5208 a gallon. February heating oil shed 0.6 cent, or 0.4%, to close at $1.5735.

Oil prices sapped by rising virus cases; anticipated drop in U.S. inventory stems losses - Oil prices slipped on Tuesday as investors remained concerned about climbing coronavirus cases globally, but expectations of a drawdown in crude oil inventory in the United States for a fifth straight week kept losses in check. Brent crude oil futures slipped 10 cents, or 0.2%, to $55.56 a barrel by 0500 GMT, while U.S. West Texas Intermediate (WTI) fell 8 cents, or 0.2%, to $52.17 a barrel. Worldwide coronavirus cases surpassed 90 million on Monday, according to a Reuters tally, as nations around the globe scramble to procure vaccines and continue to extend or reinstate lockdowns to fight new coronavirus variants. In Asia, Japan is planning to widen a state of emergency beyond its capital Tokyo to stem the spread of Covid-19 while China is implementing movement curbs in some parts of the country. "I think the market will be rapid to conclude that yesterday's modest pullback in price, provided the virus spread in China remains contained, was but a blip on the radar screen," said Stephen Innes, chief global market strategist at Axi in a note, citing the prospect of increased economic stimulus in the United States. President-elect Joe Biden, who takes office on Jan. 20 with his Democratic party in control of both Houses, has promised "trillions" in extra pandemic-relief spending. U.S. crude oil stockpiles likely fell for a fifth straight week, while refined products inventories were seen up last week, a preliminary Reuters poll showed on Monday. The poll was conducted ahead of reports from industry group American Petroleum Institute later on Tuesday and the Energy Information Administration (EIA), the statistical arm of the U.S. Department of Energy, on Wednesday. Brent could rise to $65 per barrel by summer 2021, Goldman Sachs said, driven by Saudi cuts and the implications of a shift in power to the Democrats in the United States. The Wall Street investment bank had previously predicted oil would hit $65 by year-end.

Light Crude Ends Session Above $53  | Rigzone -- Oil rose to a fresh 10-month high with a weaker dollar providing support to a market already boosted by expectations for tightening global supply. Futures climbed 1.8% in New York on Tuesday as a declining dollar raised the appeal for commodities priced in the currency. The six-day rally, the longest stretch of gains since May, has also been aided by Saudi Arabia’s pledge last week to slice output in the coming months. “It’s been a dynamic bull trend and the market continues to anticipate inventories are going to be drawn pretty sharply as a result of the Saudi production cutbacks,” “But, at some point, when you get into these bull moves, the market tends to overshoot where the equilibrium price is.” Oil has been on a tear after OPEC and its allies agreed to keep curbing their output, building on a rally at the end of last year on Covid-19 vaccine breakthroughs. Yet, the return to normal for both crude and fuel demand remains some ways off, as the world’s vaccination effort is still in the early stages. Global crude consumption will likely stagnate until May, and both vaccine production and vaccination rates would need to be ramped up “massively” if the world is to transition to normality this year, consultant FGE wrote in a report. Meanwhile, gasoline demand next year won’t reach pre-pandemic levels, though diesel should eclipse its 2019 performance, the U.S. Energy Information Administration wrote in a monthly report. Yet, Brent’s rally faces “formidable resistance” from $58 a barrel to $60 a barrel, Bank of America Global Research said in a report. Technical indicators like the 14-day Relative Strength Index signal both oil benchmarks are overbought. West Texas Intermediate for February delivery rose 96 cents to settle at $53.21 a barrel. Brent for March settlement gained 92 cents to end the session at $56.58 a barrel. Oil is also rallying along its forward curve after Saudi Arabia’s announcement to unilaterally cut production. Brent’s nearest contract has grown its premium to the following month to 9 cents a barrel, compared to a discount of 7 cents at the start of last week. The closely-watched spread between its closest two December contracts has also strengthened, signaling growing expectations for the supply and demand balance to improve. “Getting us to April with these cuts puts us at a point where, one, seasonal demand typically starts to pick up and, two, we’ll have had a couple of months of vaccinations under our belt as a global economy, so maybe getting past the worst of the shutdowns,”. “That’s certainly changing the tenor of the market to one of tightness compared to ample supply.”

Oil Algos Confused By Crude Draw, Major Product Build, Weak Demand -After ramping notably overnight (after API reported a big surprise crude draw), WTI tumbled back below $53 this morning as the dollar strengthened, and as Bloomberg reports, even with Saudi Arabia’s pledge to unilaterally cut oil output, the supply picture remains precarious. Oil inventories for the Organization for Economic Co-operation and Development are 160 million barrels above the five-year average, according to OPEC Secretary-General Mohammad Barkindo.  API:

• Crude -5.821mm (-1.9mm exp)
• Cushing -232k
• Gasoline +1.876mm
• Distillates +4.433mm

DOE

• Crude -3.248mm (-2.65mm exp)
• Cushing -1.975mm
• Gasoline +4.395mm
• Distillates +4.786mm

Crude stocks fell slightly more than expected last week (though less than API reported), but product stocks saw major builds...  Graphics Source: Bloomberg   Gasoline Demand is sliding once again, as is its seasonal tendency, but this is significantly worse than last year... With oil prices back above $50, and rig counts on the rise, US production was expected to begin rising (after stagnating at 11mm b/d for a month) but it still has not...

Oil prices extend gains after U.S. inventory drop -- Oil prices rose on Wednesday, with U.S. crude gaining for a seventh day, after an industry report showed a further drop in inventories and investors shrugged off worsening developments in the pandemic. U.S. West Texas Intermediate (WTI) was up 40 cents, or 0.8%, at $53.61 a barrel by 0128 GMT after gaining nearly 2% on Tuesday. Brent crude was up 47 cents, or 0.8%, at $57.05, having risen 1.7% in the previous session. Both benchmarks are trading at the highest since February, before the coronavirus outbreak in China began spreading across the world and billions of people went into lockdowns to prevent a pandemic that is now in a deadlier second wave. Prices are shrugging off the latest developments in Europe and the United States where death tolls and new infections keep rising, with the focus on rollouts of vaccines, however patchy, but risks to the market remain. "U.S. shale producers' response to the rally in oil represents the most significant near-term supply risk for oil," said Stephen Innes, chief global market strategist at Axi. Falling inventories and rising oil prices are likely to tempt U.S. drillers back into the fray, especially as Saudi Arabia and other major producers cut their output, effectively ceding market share to American producers. Crude inventories in the U.S. dropped by 5.8 million barrels last week to around 484.5 million barrels, data from the American Petroleum Institute showed late on Tuesday. That was more than analysts' expectations in a Reuters poll for a fall of 2.3 million barrels.

Oil snaps 6-day winning streak as U.S. dollar rises, product inventories build - Oil futures ended lower in a choppy session, snapping a six-day winning streak for the U.S. benchmark, after the U.S. dollar gained ground and inventories of gasoline and distillates rose more than expected. West Texas Intermediate crude for February delivery fell 30 cents, or 0.6%, to $52.91 a barrel on the New York Mercantile Exchange. WTI's six-day winning streak was the longest since May, according to Dow Jones Market Data. March Brent crude , the global benchmark, fell 52 cents, or 0.9%, to close at $56.06 a barrel on ICE Futures Europe. Both benchmarks finished Tuesday at their highest since Feb. 21. "The decline came just as WTI hit its highest level in around a year, which may have contributed to some profit-taking," said Craig Erlam, senior market analyst at OANDA. "Near-term risks remain for oil markets, with COVID causing huge problems in many countries which means we're likely to see more restrictions for longer." The Energy Information Administration said U.S. crude inventories fell by 3.2 million barrels last week, slightly less than the 3.8 million barrel drop expected by analysts surveyed by S&P Global Platts. It was also smaller than the 5.8 million fall said to be reported by the American Petroleum Institute late Tuesday. Gasoline inventories increased by 4.4 million barrels last week, according to EIA, while distillate stocks rose 4.8 million barrels. The S&P Global Platts analysts had forecast a 3.2 million barrel rise in gasoline stocks and a 2.8 million barrel rise in distillate inventories. The overall trend for supply, and oil production, "still is on a downward trajectory," said Phil Flynn, analyst at Price Futures Group, in a note. "The oil market trend towards our near-term target of $55 is intact and while we may see a pullback from that area, this summer, prices will be much higher." The U.S. dollar was on a firmer footing Wednesday, with the ICE U.S. Dollar Index , a measure of the currency against a basket of six major rivals, up 0.3%. The dollar fell sharply in 2020 and extended losses into January, trading at levels last seen in April 2018. Commodities often show an inverse correlation to the dollar. February natural-gas futures fell 2.6 cents, or 0.9%, to $2.727 per million British thermal units. February gasoline dropped 0.42 cent, or 0.3%, to end at $1.5488 a gallon, while February heating oil rose 0.22 cent, or 0.1%, to finish at $1.5989a gallon.

Oil prices climb on Chinese data, dollar weakness - (Reuters) - Oil prices edged higher on Thursday, boosted by a weak dollar and bullish signals from Chinese import data but pressured by renewed worries about global oil demand due to surging coronavirus cases in Europe and new lockdowns in China. Brent crude oil futures rose 36 cents, or 0.6%, to settle at $56.42 a barrel. U.S. West Texas Intermediate (WTI) ended 66 cents, or 1.3%, higher at $53.57. The U.S. dollar index slumped after U.S Federal Reserve Chair Jerome Powell struck a dovish tone, saying the U.S. central bank is not raising interest rates anytime soon. A weaker greenback makes dollar-denominated oil cheaper for holders of foreign currencies. Raising hopes of increased oil demand was a hefty U.S. COVID-19 relief package, which President-elect Joe Biden is due to unveil on Thursday. “With energy values strengthening as the dollar weakened today, the oil market was able to advance late session in sympathy with stronger equities,” Jim Ritterbusch, president of Ritterbusch and Associates, said. World stocks indexes climbed to record levels and U.S. bond yields edged higher on Thursday as investors focused on Biden’s pandemic aid proposal. “Oil specific fundamentals still appear supportive enough to push the complex into new high territory within the next couple of trading sessions,” Ritterbusch said. China’s total crude oil imports rose 7.3% in 2020, with record arrivals in the second and third quarters as refineries expanded operations and low prices encouraged stockpiling, customs data showed. Still, the world’s second-largest oil consumer reported its biggest daily jump in new COVID-19 cases in more than 10 months. Governments across Europe have announced tighter and longer coronavirus lockdowns, with vaccinations not expected to have a significant impact for the next few months. The Organization of the Petroleum Exporting Countries left its forecast for world demand unchanged, saying oil use will rise by 5.9 million barrels per day this year to 95.91 million bpd, following a record 9.75 million bpd contraction last year due to the pandemic. Oil producers face an unprecedented challenge balancing supply and demand as factors including the pace and response to COVID-19 vaccines cloud the outlook, said an official at the International Energy Agency (IEA). Saudi Arabia, for example, is throttling oil supply to some Asian buyers, refinery and trade sources told Reuters, while Russia plans to ramp up output this year, according to Russian media.

Oil Futures Gain Amid $2T Stimulus Hopes  | Rigzone -- Oil rose to a new 10-month high in New York on expectations that a potential $2 trillion economic relief packaged could get Americans consuming more fuel. U.S. benchmark crude futures advanced 1.3% on Thursday. President-elect Joe Biden’s advisers recently told allies in Congress about the cost of the package, CNN reported. A weaker dollar also boosted the appeal of commodities priced in the greenback. A stimulus package will be “putting direct money into people’s pockets,” said Josh Graves, senior market strategist at RJ O’Brien & Associates LLC. “In general, it’s going to allow them to travel more and do more things,” helping support crude demand. Crude’s recent gains have stoked concern among some investors that the rally is ahead of itself. Technical indicators suggest oil is likely due for a pullback, with the global Brent benchmark on its longest run of overbought days since 2012. Rising U.S. jobless claims point to the bumpy road ahead for a true recovery in consumption. Europe’s oil demand is also off to a sluggish start to the new year as renewed lockdowns to curb the spread of Covid-19 limit the use of road fuels. There are also signs that physical markets are softening in Asia, with Abu Dhabi’s Murban crude at a discount to its benchmark despite continued OPEC+ cuts. “To the extent the Covid situation is continuing to push back, it’s a weight on the market,” said John Kilduff, a partner at Again Capital LLC. “This is just a bit of a breather, given how we’ve come so far so fast.” West Texas Intermediate for February delivery rose 66 cents to settle at $53.57 a barrel. Brent for March settlement gained 36 cents to end the session at $56.42 a barrel. In Asia, China’s economic recovery gathered pace in December as exports jumped, pushing the trade surplus to a record high. At the same time, Oil imports, however, fell about 15% compared with November. While the China import data “has many traders and analysts scratching their heads,” it seems to be “more of a timing issue rather than a structural change in demand from the world’s biggest oil importer,” said Ryan Fitzmaurice, commodities strategist at Rabobank. Meanwhile, Royal Dutch Shell Plc’s Nigeria unit declared a force majeure on the country’s flagship Forcados crude oil, after the grade’s pipeline was halted in the wake of leaks. Forcados is the country’s biggest crude export system, with shipments through the terminal running at rate of between 200,000 and 250,000 barrels a day.

Oil drops over 2% on China lockdowns, U.S. stimulus concerns  (Reuters) - Oil prices fell more than 2% on Friday, with both contracts posting a loss on the week as concerns about Chinese cities in lockdown due to coronavirus outbreaks tempered a rally driven by strong import data from the world’s biggest crude importer.  Brent fell $1.32, or 2.3%, to settle at $55.10 a barrel. U.S. West Texas Intermediate crude settled down $1.21, or 2.3%, at $52.36 a barrel. Both benchmarks, which hit their highest in nearly a year earlier in the week, posted their first weekly declines in three weeks, with Brent down 1.6% on the week and U.S. crude down about 0.4%. While producers are facing unparalleled challenges balancing supply and demand equations with calculus involving vaccine rollouts versus lockdowns, financial contracts have been boosted by strong equities and a weaker dollar, which makes oil cheaper, along with strong Chinese demand.  These positives were called into question on Friday as the dollar rose and China ramped up lockdown measures. A nearly $2 trillion COVID-19 relief package in the United States unveiled by President-elect Joe Biden may increase oil demand from the world’s biggest crude consumer. Still, some analysts said the move may not be enough to stoke demand. “In terms of being able to talk about demand, Asia was the only bright spot,” . “This renewed lockdown is striking at the heart of the demand picture in Asia. It’s trouble.”  Crude imports into China were up 7.3% in 2020, with record arrivals in two out of four quarters as refineries increased runs and low prices prompted stockpiling, customs data showed on Thursday. But China reported the highest number of daily COVID-19 cases in more than 10 months on Friday, capping a week that has resulted in more than 28 million people under lockdown as it suffered its first coronavirus death on the mainland since May. “The COVID-19 pandemic’s spread is taking centre stage again and traders are getting increasingly worried about the long duration of European lockdown and about the new restrictions (in) China,”

Oil Holds Near 10-Month High On Optimism Over U.S. Stimulus Plan -- Oil slid by the most in three weeks as a stronger dollar and weak U.S. economic data stoked concerns over an economic rebound. Futures in New York tumbled 2.3% on Friday after a rally in oil earlier in the week pushed the benchmark into overbought territory. The U.S. dollar strengthened, reducing the appeal of commodities priced in the currency. U.S. consumer sentiment cooled more than forecast in January and other economic data such as sluggish retail sales and producer prices also portray the obstacles still facing the country as it emerges from the pandemic. Meanwhile, President-elect Joe Biden said he will ask Congress for $1.9 trillion to fund immediate relief for the U.S. economy that has been pummeled by the pandemic. But the large price tag and inclusion of initiatives opposed by many Republicans set up the aid package for a drawn out legislative battle. “We’ve had a lot of strength in a number of different markets and now we’re getting a pullback,” Ultimately, oil markets need “driving to go up. If people have money and no place to spend it, it doesn’t make any difference.” Despite the pullback in oil futures, vaccine breakthroughs and Saudi Arabia’s pledge earlier this month to deepen output cuts are expected to support prices. JPMorgan Chase & Co. said a “nasty deficit” could emerge in the oil market later this year. Meanwhile, technical indicators had been flashing warnings signs all week. The 14-day Relative Strength Index for both U.S. and global benchmark crude futures traded above 70 this week in a sign they were overbought, though both slipped under that level Friday. A “short-term pullback” is likely in store for “oil prices, given the recent loss of support from a number of key factors,” “With that said, the dips may be shallow as investor appetite for commodities appears to be increasing rapidly following the recent bullish oil calls and talk of a commodity super-cycle from some of the larger and more prominent U.S. investment banks.”

Iran Will Expel UN Inspectors If US Sanctions Aren’t Lifted -- Iranian MP Ahmad Amiribadi Farahani announced over the weekend that if the US does not lift sanctions against Iran, as required under the P5+1 nuclear deal, by February 21, the Iranian parliament is mandating the expulsion of all IAEA inspectors from the country, and will suspend the Additional Protocol.This comes on the approach of president-elect Joe Biden’s inauguration, and with some expectations he’d be looking to engage Iran diplomatically, the ultimatum may be an effort to force Biden to engage early, and make a deal quickly.The US isn’t a party to the P5+1 deal at this point, but there’s been a lot of hope Biden would want to return. There has been no public announcement, and Sen. Menendez (D-NJ) claimed in October Biden would hold out for a tougher deal.Since this comment is coming from an MP and making reference to parliament’s bill to expand the nuclear program, it’s not clear this is being sent on behalf of the Rouhani government, or if it is just hardliners trying to stir things up.Rouhani is more diplomacy-minded than the hardliners, and has resisted parliament’s calls to escalate the civilian nuclear program. Nothing that’s been done has anything to do with a military dimension to the nuclear program, and despite Israeli spin, the inspectors can continue to verify nothing is being diverted outside of civilian use. Expelling the inspectors would be a huge escalation, even though it too would be reversible, and would certainly be presented by US hawks and their supporters as a provocation worth starting a war over. If Biden hasn’t made a deal by then and this expulsion happens, it could put major pressure on him to react negatively, and move away from the diplomatic track. That may be what the hardliners intend, as many of them openly scorn the idea of diplomacy in the first place.

France says Iran is building nuclear weapons capacity, urgent to revive 2015 deal (Reuters) - Iran is in the process of building up its nuclear weapons capacity and it is urgent that Tehran and Washington return to a 2015 nuclear agreement, France’s foreign minister was quoted as saying in an interview published on Saturday. Iran has been accelerating its breaches of the nuclear deal and earlier this month started pressing ahead with plans to enrich uranium to 20% fissile strength at its underground Fordow nuclear plant. That is the level Tehran achieved before striking the deal with world powers to contain its disputed nuclear ambitions. The Islamic Republic’s breaches of the nuclear agreement since President Donald Trump withdrew the United States from it in 2018 and subsequently imposed sanctions on Tehran may complicate efforts by President-elect Joe Biden, who takes office on Jan. 20, to rejoin the pact. “The Trump administration chose what it called the maximum pressure campaign on Iran. The result was that this strategy only increased the risk and the threat,” Le Drian told the Journal du Dimanche newspaper. “This has to stop because Iran and - I say this clearly - is in the process of acquiring nuclear (weapons) capacity.” The agreement’s main aim was to extend the time Iran would need to produce enough fissile material for a nuclear bomb, if it so chose, to at least a year from roughly two to three months. It also lifted international sanctions against Tehran. Western diplomats have said Iran’s repeated breaches have already reduced the “breakout time” to well below a year. Iran denies any intent to weaponise its nuclear programme.

South Korea Seeks Qatari Help to Release Tanker-- South Korea has asked Qatar for “maximum support” to secure the release of an oil tanker seized by Iran this month. Deputy Foreign Minister Choi Jong-Kun made the appeal during a visit to Doha, the Qatari capital. He met Foreign Minister Mohammed Bin Abdulrahman Al Thani, the Yonhap News Agency reported on Thursday. Choi traveled to Doha from Tehran after fruitless talks over the South Korean-flagged Hankuk Chemi, an oil-products tanker detained by the Islamic Revolutionary Guard Corps on Jan. 4. He also discussed billions of dollars of Iranian money trapped in South Korea due to U.S. sanctions. Qatar shares the world’s biggest natural gas field with Iran and has maintained close ties with the country even as other Gulf Arab nations such as Saudi Arabia and the United Arab Emirates have backed U.S. attempts to isolate it. Relations between Tehran and Seoul have been strained since the U.S. banned countries, including major Asian customers, from buying Iranian petroleum. Iran says it has at least $7 billion from oil sales stuck in South Korea and that it needs the money to purchase goods including coronavirus vaccines. South Korea has shown a “lack of will” to release the oil funds and should avoid “politicizing” the Hankuk Chemi, Iran’s Deputy Foreign Minister Abbas Araghchi said on Sunday. Iran said the ship was violating marine environmental laws, something its operator has denied. Around 20 crew members are being held with the ship at Iran’s Bandar Abbas port.Chinese Cities in Lockdown as Police Warn People Not to Spread 'Rumors' — The ruling Chinese Communist Party (CCP) on Tuesday placed a city of five million people in lockdown amid a resurgence of COVID-19 cases in several locations around the country. All 4.9 million residents of Langfang city in the northern province of Hebei were ordered to stay home, as the authorities prepared to roll out a mass testing program in the city. Langfang's lockdown follows that of Shijiazhuang, provincial capital of Hebei, whose 11 million population have been under lockdown for several days. In Hebei's Xingtai city, the CCP issued a directive calling for donations from the private sector to support the healthcare industry during the pandemic. A Jan. 10 directive signed by the CCP's United Front Work Department, which mobilizes support outside of the ruling party, called on local authorities in nearby Nangong city to "levy pandemic supplies from private entrepreneurs, including single beds, mattresses, quilts, pillows, buckets, medical waste bags, and so on." An employee who answered the phone at the department confirmed the report. "Our entire supply network has been cut off, so we can't bring in supplies from elsewhere now," the employee said. "Some people can drive themselves to Xingtai ... and we coordinate to let them in, but most cars aren't being allowed into Hebei right now, and can't even get onto the highway without a pass; it's all blocked." "That's why the [truck] drivers don't want to come here."