Strategic Petroleum Reserve approaching a 19 year low; oil + products supplies drop to an 83 month low; total oil product demand sets a record high, led by distillates demand at 18+ year high; global oil shortage at 1,210,000 barrels per day in November as OPEC output falls 563,000 barrels per day short of quota; demand revisions now indicate oil shortage for all of 2021
oil prices ended lower for the seventh time in eight weeks this week as the rapid spread of the Omicron virus variant began to impact oil demand.. after rising 8.2% to $71.67 a barrel last week on hopes that Omicron would not be as detrimental to demand as initially feared, the contract price for US light sweet crude for January delivery opened higher on Monday and rose almost 2% in early trading after OPEC raised their forecast for world oil demand for the first quarter of 2022, but then began falling as new doubts emerged about the effectiveness of vaccines against Omicron variant to settled 38 cents lower at $71.29 a barrel...oil prices continued falling on Tuesday, reaching a low of $69.51 a barrel by late morning, after the International Energy Agency (IEA) said the Omicron coronavirus variant was set to dent global demand recovery, before staging a partial recovery and ending off 56 cents at $70.73 a barrel, even as record producer prices reinforced expectations of a faster stimulus withdrawal by the Fed, thus supporting the US dollar...oil prices moved lower overnight and extended their decline into Wednesday, sliding to $69.39 as Omicron-driven demand fears, reinforced by ugly Chinese retail and industrial output data, coincided with US shale and OPEC+ supply surplus anxiety. but rebounded back to above $70 after the EIA reported across the board inventory declines and the largest crude draw since early September, and settled with a gain of 14 cents at $70.87 a barrel...oil prices followed equity markets higher on Thursday, after the Fed signaled the end of its ultra-easy monetary policy earlier than was previously expected, and settled with a gain of $1.51 at $72.38 a barrel, supported by record U.S.demand data and falling crude stockpiles, even as the spread of the Omicron coronavirus variant threatened to put a brake on consumption worldwide...but oil prices completely reversed those gains on Friday, falling $1.52 to $70.86 a barrel, triggered by growing concerns that a rapid spread of the COVID omicron variant across several major oil-consuming economies would lead to an avalanche of quarantine closures this winter, and thus finished the week 1.1% lower, their seventh weekly decline in eight weeks, for prices based on the front month contract...
meanwhile, natural gas prices finished lower for the third straight week on continued mild temperature forecasts, and are now down by more than 33% since Thanksgiving...after falling 5% to $3.925 per mmBTU last week on a dearth of forecasts for sustained heating demand, the contract price of natural gas for January delivery opened higher on Monday on a chillier weekend forecast and rose by more than 4% in early trading, only to tank by afternoon as subsequent weather data backed off the cold forecast and sent the gas contract price tumbling to settle 13.1 cents lower at $3.794 per mmBTU, despite an 11% jump in European gas prices that was expected to keep our LNG exports near record highs....warm weather continued to pressure gas prices on Tuesday, despite a huge day over day decline in production, as they fell another 4.7 cents to $3.747 per mmBTU, but they recovered to close 5.5 cents higher at $3.802 per mmBTU on Wednesday on forecasts for slightly cooler weather over the next two weeks than was previously expected...however, natural gas prices slipped 3.6 cents to $3.766 per mmBTU on Thursday on a midday forecast for milder weather than expected over the next two weeks, and on expectations for a smaller-than-usual weekly storage withdrawal in the week to come due to the warm weather, and then tumbled another 7.6 cents, or 2% to $3.690 per mmBTU on Friday, the lowest close since Decemer 6th and down 6.0% on the week, on forecasts for even milder weather through the end of December...
The EIA's natural gas storage report for the week ending December 10th indicated that the amount of working natural gas held in underground storage in the US fell by 88 billion cubic feet to 3,417 billion cubic feet by the end of the week, which left our gas supplies 326 billion cubic feet, or 8.7% below the 3,743 billion cubic feet that were in storage on December 10th of last year, and 64 billion cubic feet, or 1.8% below the five-year average of 3,481 billion cubic feet of natural gas that have been in storage as of the 10th of December over the most recent years...the 88 billion cubic foot withdrawal from US natural gas working storage this week was equal to the average forecast for a 88 billion cubic foot withdrawal from a S&P Global Platts' survey of analysts, but was much less than the 118 billion cubic feet that were pulled from natural gas storage during the corresponding week of 2020, and was also less than the average withdrawal of 114 billion cubic feet of natural gas that have typically been pulled out 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 December 10th showed that after a near record jump in our oil exports, we needed to pull oil out of our stored commercial crude supplies for the fifth time in twelve weeks and for the twenty-fifth time in the past thirty-seven weeks….our imports of crude oil fell by an average of 28,000 barrels per day to an average of 6,471,000 barrels per day, after falling by an average of 105,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 1,375,000 barrels per day to an average of 3,645,000 barrels per day during the week, which together meant that our effective trade in oil worked out to a net import average of 2,826,000 barrels of per day during the week ending December 10th, 1,403,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, production of crude oil from US wells was reportedly unchanged at 11,700,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to have totaled an average of 14,103,000 barrels per day during the cited reporting week…
Meanwhile, US oil refineries reported they were processing an average of 15,670,000 barrels of crude per day during the week ending December 10th, an average of 115,000 fewer barrels per day than the amount of oil that our refineries processed during the prior week, while over the same period the EIA’s surveys indicated that a net of 933,000 barrels of oil per day were being pulled out 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 210,000 barrels per day less 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 plunked a (+210,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a balance sheet fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed...moreover, since last week’s EIA fudge factor was at (-420,000) barrels per day, that means there was a 630,000 barrel per day difference in the EIA's crude oil balance sheet error from a week ago, and hence the week over week supply and demand changes indicated by this week's report are fairly useless....however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing, and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it's published, and just as it's watched & believed to be reasonably 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)….
This week's 933,000 barrel per day decrease in our crude oil inventories came as 655,000 barrels per day were being pulled out of our commercially available stocks of crude oil, while 279,000 barrels per day of oil were pulled out of our Strategic Petroleum Reserve, part of the first installment from Biden's plan to release 50 million barrels from the SPR, in order to incentive continued use of US gas guzzlers; however, most of that oil is expected to go to China and India, so how it would impact US prices is unclear...including the drawdowns from the Strategic Petroleum Reserve under such politically motivated programs, a total of 57,232,000 barrels have been removed from the Strategic Petroleum Reserve over the past 18 months, and as a result the amount of oil in our Strategic Petroleum Reserve has fallen to an 227 month low of 598,917,000 barrels per day, or the lowest since December 27, 2002, as repeated tapping of our emergency supplies for political expediency or to “pay for” other programs had already drained those supplies over the past dozen years...based on an estimated prepandemic consumption level of 18 million barrels per day, the US will have roughly 30 1/2 days of oil supply left in the Strategic Petroleum Reserve when the Biden program is complete..
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,502,000 barrels per day last week, which was 15.4% more than the 5,633,000 barrel per day average that we were importing over the same four-week period last year….this week’s crude oil production was reported to be unchanged at 11,700,000 barrels per day even though the EIA's rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day higher at 11,300,000 barrels per day, because Alaska’s oil production was 5,000 barrels per day lower at 449,000 barrels per day and subtracted 100,000 barrels per day from the reported rounded national production total (by the EIA's math)...US crude oil production had hit a pre-pandemic record high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was still 10.7% below that of our pre-pandemic production peak, but 38.8% above the interim low of 8,428,000 barrels per day that US oil production had fallen to during the last week of June of 2016...
US oil refineries were operating at 89.8% of their capacity while using those 15,670,000 barrels of crude per day during the week ending December 10th, unchanged from the prior week, but still a bit lower than normal utilization for early December refinery operations… the 15,670,000 barrels per day of oil that were refined this week were 10.5% more barrels than the 14,183,000 barrels of crude that were being processed daily during the pandemic impacted week ending December 11th of last year, but 5.4% less than the 16,562,000 barrels of crude that were being processed daily during the week ending December 13th, 2019, when US refineries were operating at what was then also a less than seasonal 90.6% of capacity...
Even with the decrease in oil being refined this week, the gasoline output from our refineries was quite a bit higher, increasing by 479,000 barrels per day to 10,042,000 barrels per day during the week ending December 10th, after our gasoline output had decreased by 86,000 barrels per day over the prior week.…this week’s gasoline production was also 17.8% more than the 8,522,000 barrels of gasoline that were being produced daily over the same week of last year, and 2.1% more than the gasoline production of 9,840,000 barrels per day during the week ending December 13th, 2019….on the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 105,000 barrels per day to 4,812,000 barrels per day, after our distillates output had increased by 45,000 barrels per day over the prior week…after that decrease, our distillates output was still 4.5% more than the 4,604,000 barrels of distillates that were being produced daily during the week ending December 11th, 2020, but 5.1% less than the 5,072,000 barrels of distillates that were being produced daily during the week ending December 13th, 2019..
Even with the big jump in our gasoline production, our supplies of gasoline in storage at the end of the week fell for the eighth time in ten weeks, and for the twentieth time in thirty-four weeks, decreasing by 719,000 barrels to 218,585,000 barrels during the week ending December 10th, after our gasoline inventories had increased by 3,882,000 barrels over the prior week...our gasoline supplies decreased this week because the amount of gasoline supplied to US users increased by 509,000 barrels per day to 9,472,000 barrels per day, and as our imports of gasoline fell by 59,000 barrels per day to 499,000 barrels per day, while our exports of gasoline fell by 171,000 barrels per day to 621,000 barrels per day…after this week’s inventory decrease, our gasoline supplies were 8.5% lower than last December 11th's gasoline inventories of 238,879,000 barrels, and about 6% below the five year average of our gasoline supplies for this time of the year…
With the decrease in our distillates production, our supplies of distillate fuels decreased for the twelfth time in sixteen weeks and for the 24th time in 36 weeks, falling by 2,852,000 barrels to 123,758,000 barrels during the week ending December 10th, after our distillates supplies had increased by 2,733,000 barrels during the prior week….our distillates supplies fell this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, jumped by a record 1,318,000 barrels per day to a 18 1/2 year high of 4,896,000 barrels per day, even as our exports of distillates fell by 445,000 barrels per day to 773,000 barrels per day, and as our imports of distillates rose by 181,000 barrels per day to 450,000 barrels per day....after twenty-five inventory decreases over the past thirty-six weeks, our distillate supplies at the end of the week were 18.2% below the 151,259,000 barrels of distillates that we had in storage on December 11th, 2020, and about 9% below the five year average of distillates stocks for this time of the year…
Meanwhile, with the big jump in our oil exports, our commercial supplies of crude oil in storage fell for the 19th time in the past twenty-nine weeks and for the 34th time in the past year, and by the most in 14 weeks, decreasing by 4,584,000 barrels over the week, from 432,870,000 barrels on December 3rd to 428,286,000 barrels on December 10th, after our commercial crude supplies had decreased by 241,000 barrels over the prior week…after this week’s decrease, our commercial crude oil inventories slipped to around 7% below the most recent five-year average of crude oil supplies for this time of year, but were still about 24% above the average of our crude oil stocks as of the second weekend of December over the 5 years at the beginning of the past decade, 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 jumped to record highs during the Covid lockdowns of last spring and remained elevated for most of the year after that, our commercial crude oil supplies as of this December 10th were 14.4% less than the 500,096,000 barrels of oil we had in commercial storage on December 11th of 2020, and are now 4.2% less than the 446,833,000 barrels of oil that we had in storage on December 13th of 2019, and 3.0% less than the 441,457,000 barrels of oil we had in commercial storage on December 14th of 2018…
Finally, with our inventory of crude oil and our supplies of all products made from oil all near multi year lows, we are continuing to track the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR....the EIA's data shows that total oil and oil product inventories, including those in the Strategic Petroleum Reserve and those held by the oil industry, and including everything from gasoline and jet fuel to propane/propylene and residual fuel oil, fell by 17,816,000 barrels this week, from 1,827,222,000 barrels on December 3rd to 1,809,406,000 barrels on November 10th and is now at the lowest level since January 2nd, 2015, or at an 83 month low...coincidental with that near seven year low in oil and oil product supplies, implied demand based on product supplied of all petroleum products rose to a record high of 23,191,000 barrels per day during the week ending December 10th, beating the previous record that was set during week ending August 27th of this year, when total demand had topped out at 22,820,000 barrels per day...
OPEC's December Oil Market Report
Monday of this week saw the release of OPEC's December Oil Market Report, which includes OPEC & global oil data for November, and hence it gives us a picture of the global oil supply & demand situation for the fourth month after 'OPEC+' agreed to increase their output by 400,000 barrels per day monthly from the previously agreed to July level, which was part of the fifth production quota policy reset that they've made over the past year and a half, all in response to the pandemic-related slowdown and subsequent irregular recovery...again, we'll caution that the oil demand estimates made by OPEC herein, while the course of the Covid-19 pandemic still remains uncertain in most countries around the globe, should be considered as having a much larger margin of error than we'd expect from this report during stable and hence more predictable periods..
the first table from this monthly report that we'll review is from the page numbered 47 of this month's report (pdf page 59), and it shows oil production in thousands of barrels per day for each of the current OPEC members over the recent years, quarters and months, as the column headings below 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 on the bottom line of the above table, OPEC's oil output increased by 285,000 barrels per day to 27,717,000 barrels per day during November, up from their revised October production total averaging 27,432,000 barrels per day....however, that October output figure was originally reported as 27,453,000 barrels per day, which therefore means that OPEC's October production was revised 21,000 barrels per day lower with this report, and hence OPEC's November production was, in effect, a 264,000 barrel per day increase from the previously reported OPEC production figure (for your reference, here is the table of the official October OPEC output figures as reported a month ago, before this month's revision)...
According to the agreement reached between OPEC and the other oil producers at their Ministerial Meeting on July 18th, the oil producers party to that agreement were to raise their output by a total of 400,000 barrels per day each month through November, which would include an increase of 254,000 barrels per day from the OPEC members listed above...so as we can see from the above table, OPEC's increase of 285,000 barrels per day was a bit more than that...however, since OPEC's production was already 588,000 barrels per day short of their quota in October, the 31,000 extra barrels per day they produced in November is pretty inconsequential, especially since those OPEC members who saw larger than allotted increases in November were already lagging their quotas..
Recall that last year's original oil producer's agreement was to cut oil 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 of last year, but that initial 9.7 million bpd production cut agreement had been extended to include July 2020 at a meeting between OPEC and other producers on June 6th, 2020....then, in a subsequent meeting in July of last year, 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 2020 and subsequent months, which thus became the agreement that governed OPEC's output for the rest of 2020...the OPEC+ agreement for this January's production, which was later extended to include February and March and then April's output, was to further ease their supply cuts by 500,000 barrels per day to a cut of 7.2 million barrels per day from that original baseline...then, during a difficult meeting on April 1st of this year, OPEC and the other oil producers that are aligned with them agreed to incrementally adjust their oil production higher each month by a set amount over the next three months, taking their joint output cut agreement through July....production levels for August and the following months of this year were to be determined by a July 1st OPEC meeting, but that meeting was adjourned on July 2nd due to a dispute between the UAE and the Saudis over reference production levels, and a subsequent attempt to restart that meeting on July 5th was called off....so it wasn't until July 18th that a tentative compromise addressing August quotas was worked out, allowing oil producers in aggregate to increase their production by 400,000 barrels per day in August and again by that amount in each of the following months, and boosting reference production levels for the UAE, the Saudis, Iraq and Kuwait beginning in April 2022...OPEC and other producers then agreed to increase their production in January 2022 by a further incremental 400,000 barrels per day in a meeting concluded on the 2nd of December, two weeks ago...
OPEC arrived at the production quotas for August through November of this year by repeatedly adjusting the original 23%, or 9.7 million barrel per day production cut from the October 2018 baseline that they first agreed to for May and June 2020, first to a 7.7 million barrel per day output reduction from the baseline for the remainder of 2020, then to a 7.2 million barrel per day production cut from the baseline for the first four months of this year, which was actually raised to an 8.2 million barrel per day oil output reduction after the Saudis unilaterally committed to cut their own production by a million barrels per day during February, March, and then later during April of this year....under the prior agreement, OPEC's production cut in April was at 4,564,000 barrels per day from the October 2018 baseline, which was lowered to a cut of 3,650,000 barrels per day from the baseline with the latest comprehensive agreement, which thus set the July production quota for the "OPEC 10" at 23,033,000 barrels per day, with war torn Libya and US sanctioned producers Iran and Venezuela exempt from the production cuts imposed by this agreement....for OPEC and the other producers to increase their output by 400,000 barrels per day from that July level, each producer would be allowed to increase their production by just over 1% per month...for the ten members of OPEC who agreed to impose cuts on themselves, that would mean their August output quota would be roughly 23,277,000 barrels per day, then 23,531,000 barrels per day in September, then roughly 23,786,000 barrels per day in October, and then 24,041,000 barrels per day in November....therefore, the 23,478,000 barrels those 10 OPEC members produced in November were still 563,000 barrels per day short of what they were expected to produce, with Nigeria, Angola and the Saudis accounting for the most of this month's shortfall..
The next graphic from this month's report that we'll highlight has the months mislabelled, but it still correctly shows us both OPEC's and worldwide oil production monthly on the same graph, over the period from December 2019 to November 2021, and it comes from page 48 (pdf page 60) of OPEC's December Monthly Oil Market Report....on this graph, the cerulean blue bars represent OPEC's monthly oil production in millions of barrels per day as shown on the left scale, while the purple graph represents global oil production in millions of barrels per day, with the metrics for global output shown on the right scale....
Including this month's 285,000 barrel per day increase in OPEC's production from their revised production of a month earlier, OPEC's preliminary estimate indicates that total global liquids production increased by a rounded 880,000 barrels per day to average 98.28 million barrels per day in November, a reported increase which came after October's total global output figure was apparently revised down by 160,000 barrels per day from the 97.56 million barrels per day of global oil output that was estimated for October a month ago, as non-OPEC oil production rose by a rounded 590,000 barrels per day in November after that revision, with most the increase coming from non-OECD countries, predominantly in Latin America, even as European OECD countries increased their output by 90,000 barrels per day...
After that increase in November's global output, the 98.28 million barrels of oil per day that were produced globally during the month were 5.93 million barrels per day, or 6.4% more than the revised 92.35 million barrels of oil per day that were being produced globally in November a year ago, which was the fourth month after OPEC and other producers agreed to reduce their output cuts from 9.7 million barrels per day to 7.7 million barrels per day (see the December 2020 OPEC report (online pdf) for the originally reported November 2020 details)...with this month's increase in OPEC's output, their November oil production of 27,717,000 barrels per day amounted to 28.2% of what was produced globally during the month, unchanged from their share of the global total in October....OPEC's November 2020 production was reported at 25,109,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 2,608,000 barrels per day, or 10.4% more barrels per day of oil this November than what they produced a year earlier, when they accounted for 27.1% of global output...
Even after the increases in OPEC's and global oil output that we've seen in this report, the amount of oil being produced globally during the month again fell short of the expected global demand, as this next table from the OPEC report will show us..
The above table came from page 25 of the OPEC December Oil Market Report (pdf page 37), and it shows regional and total oil demand estimates in millions of barrels per day for 2020 in the first column, and then OPEC's estimate of oil demand by region and globally, quarterly over 2021 over the rest of the table...on the "Total world" line in the fifth column, we've circled in blue the figure that's relevant for November, which is their estimate of global oil demand during the fourth quarter of 2021... OPEC is estimating that during the 4th quarter of this year, all oil consuming regions of the globe have been using an average of 99.49 million barrels of oil per day, which was unrevised from their estimate for the 4th quarter a month ago, still reflecting a bit of coronavirus related demand destruction compared to 2019, when global demand averaged over 101 million barrels per day during second half of the year....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 only producing 98.28 million barrels per day during November, which would imply that there was a shortage of around 1,210,000 barrels per day in global oil production in November when compared to the demand estimated for the month...
in addition to figuring that November oil shortage implied by this report, the downward revision of 160,000 barrels per day to October's global oil output that's implied in this report means that the 1,930,000 barrels per day global oil output shortage we had previously figured for October would now be revised to an oil shortage of 2,090,000 barrels per day....
Note on the table above that we've circled in green a downward revision of 230,000 barrels per day to the third quarter's demand....that means that the 2,070,000 barrels per day global oil output shortage we had previously figured for September would now be revised to a shortage of 1,840,000 barrels per day....in like manner, 230,000 barrels per day downward revision to 3rd quarter demand means that the shortage of 2,580,000 barrels per day we had previously figured for August would now be revised to a shortage of 2,350,000 barrels per day, and that the shortage of 2,160,000 barrels per day barrels per day we had previously figured for July would have to be revised to a shortage of 1,930,000 barrels per day...
On the other hand, you can see in green that we've also circled a modest upward revision of 60,000 barrels per day to the second quarter's demand, a quarter when there was also a shortage of oil being produced globally.... based on that upward revision to demand, our previous estimate that there was a shortage of 680,000 barrels per day in June would now be revised to a 740,000 barrels per day shortage, the oil shortage of 2,010,000 barrels per day that we had previously figured for May would have to be revised to a shortage of 2.070,000 barrels per day, and that the 2,360,000 barrels per day global oil output shortage we should have figured for April would have to be revised to a shortage of 2,420,000 barrels per day...
Also note that in green that we have circled a significant upward revision of 950,000 barrels per day to OPEC's previous estimate of first quarter demand, during a period when supply and demand seemed to be closer to being in balance....for March, that means that the global oil output surplus of 140,000 barrels per day we had previously figured for March would now be revised to a shortage of 810,000 barrels per day... similarly, the upward revision to first quarter demand means that the 870,000 barrels per day global oil output shortage we had previously figured for February would now be revised to a shortage of 1,820,000 barrels per day, and that the global oil output surplus of 350,000 barrels per day we had previously figured for January would now be revised to a shortage of 600,000 barrels per day, in light of that 950,000 barrel per day upward revision to first quarter demand...
You might also note that we have also circled a 190,000 barrel per day upward revision to 2020's demand circled in orange....while we're not inclined to go back and recompute the figures for each month of last year in light of that revision, suffice it to say that the quantities of oil being produced globally during the pandemic of 2020 averaged over 3 million barrels per day more than anyone wanted, and that an average 190,000 barrels per day upward revision to global demand during that period would be a drop in the bucket in comparison...
This Week's Rig Count
The number of drilling rigs active in the US increased for the 55th time during the past 65 weeks during the week ending December 17th, but still remained 27% below the prepandemic rig count....Baker Hughes reported that the total count of rotary rigs running in the US increased by three to 579 rigs this past week, which was also 233 more rigs than the pandemic hit 346 rigs that were in use as of the December 18th report of 2020, but was also still 1,350 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, a week before OPEC began to flood the global oil market in an attempt to put US shale out of business….
The number of rigs drilling for oil increased by 4 to 475 oil rigs during this week, after they had increased by 4 rigs during the prior week, and there are now 212 more oil rigs active now than were running a year ago, even as they still amount to just 29.5% of the shale era 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 fell by 1 to 104 natural gas rigs, which was still up by 23 natural gas rigs from the 81 natural gas rigs that were drilling during the same week a year ago, but still only 6.5% of the modern high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….note that last year's rig count also included a rig that Baker Hughes had classified as "miscellaneous', while there are no such "miscellaneous' rigs deployed this week...
The Gulf of Mexico rig count was up by one rig to 15 rigs this week, with thirteen of this week's Gulf rigs drilling for oil in Louisiana waters and two more drilling for oil in Alaminos Canyon, offshore from Texas...that's now one less than the count of 16 rigs that were active in the Gulf a year ago, when 13 Gulf rigs were drilling for oil offshore from Louisiana and three deployed for oil in Texas waters…looking at the well records in the Gulf, it appears that most of those rigs appear to be directional, targeting oil at depths greater than 15,000 feet, and include five targeting the Mississippi Canyon and three targeting oil under the Green Canyon...since there is now no drilling off our other coasts, nor was there a year ago, the Gulf rig count is equal to the national offshore totals..
In addition to those rigs offshore, we continue to have one water based rig drilling for oil inland in the Galveston Bay area; the directional rig that had been targeting oil from an inland body of water in Plaquemines Parish, Louisiana, near the mouth of the Mississippi was shut down this week, and hence the inland waters rig count of one is now down from two a year ago..
The count of active horizontal drilling rigs was unchanged at 521 horizontal rigs this week, which was still 213 more than the 308 horizontal rigs that were in use in the US on December 18th of last year, but also 62.1% less than the record 1,374 horizontal rigs that were deployed on November 21st of 2014...meanwhile, the directional rig count was up by one to 31 directional rigs this week, and those were also up by 11 from the 21 directional rigs that were operating during the same week a year ago….in addition, the vertical rig count was up by 2 to 26 vertical rigs this week, and those were up by 9 from the 17 vertical rigs that were in use on December 18th 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 December 17th, the second column shows the change in the number of working rigs between last week’s count (December 10th) and this week’s (December 17th) count, the third column shows last week’s December 10th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 18th of December, 2020...
with Texas up three rigs and the Permian up two, we'll start by checking the Rigs by State file at Baker Hughes for changes in the Texas Permian basin...there we find that four rigs were added in Texas Oil District 8, which is the core Permian Delaware, but that a rig was pulled out of Texas Oil District 8A, which covers the southern counties in the Permian Midland....since the Texas Permian rig count was thus up by 3 and the national rig count was just up by two, that means that the rig that was removed from New Mexico had been deployed in the western Permian Delaware...
elsewhere in Texas, two rigs were added in Texas Oil District 1, but a rig was pulled out of Texas Oil District 2, and another rig was pulled out of Texas Oil District 4, all districts where drilling is primarily into the Eagle Ford shale...however, since the Eagle Ford rig count was changed, we can't easily tell if all or even none of those changes involved the Eagle Ford...that can be determined by tediously checking the individual well records in the North America Rotary Rig Count Pivot Table (Feb 2011 - Current), if anyone needs to know..
in other states, we find that two oil rigs were added in Oklahoma, including one in the Arkoma Woodford and another in a basin that Baker Hughes doesn't track...in Louisiana, there was an oil rig added offshore, and another oil rig added in the Haynesville shale in the northwest, one of just two oil rigs in that natural gas basin, while the inland waters rig that had been drilling for oil near the mouth of the Mississippi in Plaquemines Parish was removed...meanwhile, an oil rig was pulled out of a basin that Baker Hughes doesn't track in California...
all the changes among natural gas rigs were in Marcellus shale this week; the Marcellus shale rig count was down by one as two natural gas rigs that had been drilling in West Virginia's Marcellus were pulled out, while a natural gas rig was added in Pennsylvania's Marcellus...
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WALMART DONATES TO UTICA SHALE - Walmart Distribution Center #7017, Wintersville, donated $2,500 to the Utica Shale Academy. The Utica Shale Academy (USA) is a dropout prevention and recovery school serving students in Columbiana, Carroll, Harrison, Jefferson and Mahoning counties. USA provides individual instruction, as well as various career pathways for students, including over 25 Ohio Industry Recognized Credentials.
Utica Shale Academy hopes to secure more grants – With many parts of the Utica Shale Academy’s new equipment and programming coming through grants in the past, the USA board voted on Tuesday to increase the number of hours for the person seeking grants on their behalf. Superintendent Bill Watson recommended to the board to increase the number of hours the USA will pay the career specialist, a grant writer from the Jefferson County Educational Service Center, from 20 hours to 40. Because the board contracts through the ESC, the ESC is responsible for the benefits for the position. The USA currently pays $25,000 for the services and expects that could double. Watson said he believes with other funding sources coming to the schools, there could be less competition for some of the grants this year. He hopes the USA will be applying for up to 50 grants, even though many will be smaller. During Tuesday’s meeting, the board voted to accept a $600 Best Practice Grant from the ESC. Additionally, Watson announced the USA has received a $2,500 donation from Walmart in Wintersville, which will be used for smart tech to help with interventions. The board also approved the creation of a stipend for a dean of discipline position, which will allow Carter Hill to be paid an additional $5,000 to handle discipline concerns at the school whenever Watson is out of the school doing other duties such as recruiting for the school. The USA currently has 94 students enrolled and another eight students in progress to enroll. He also said due to the large amount of growth in the programs, he would like the board to think about possible expansion into Harrison or Carrolton Counties in the future.
Utica Shale Pumped Up Promises to Valley Landowners - – Mel Cadle scopes out the well pad that was constructed on his North Jackson farm nearly 10 years ago. The site, dominated by six large, green storage tanks, is unkempt, strewn with weeds, and sits back on a 20-acre plot he owns along Blott Road. Cadle once envisioned years of lucrative royalties streaming directly into his bank account from oil and gas pumped from the two wells drilled on his property. “It didn’t work out like it was supposed to for me,” the 87 year-old Cadle says. “I don’t have any income from these wells. I lost five acres for nothing.” Cadle personifies a complicated legacy of the oil and gas industry 10 years after energy companies descended on eastern Ohio in search of reserves trapped in the Utica/Point Pleasant shale formation. The development of hydraulic fracturing and horizontal drilling made it possible – and profitable – for exploration companies to tap into tight shale formations 6,000 feet deep and extend laterals thousands of feet across these thin strata. The expectations of long-standing economic benefits to the region were enormous. Energy companies touted investments in the billions of dollars for drilling programs, leasehold contracts, processors, pipelines and support services to the industry. Companies supporting the oil and gas supply chain would also relocate, augmenting further job growth in the region. For some, drilling the Utica meant up-front lease signing bonuses between $1,000 and $6,000 an acre, and many believed the big payoff would come in the form of monthly royalty checks. Early in the play, it was estimated that landowners with a producing Utica well pad on their property could reap as much as $1,000 per acre, per month. For many landowners, though, the promise of sustained wealth remains just that. In Cadle’s case, complications arose because of a lease he purchased in 2008 on the 20 acres where the well pad sits. When he purchased the property, he was under the impression that all of the mineral rights were included. Instead the rights to the Consol wells, now owned by Northwood Energy Corp., remain in the hands of a family trust from the previous owners. “I was so looking forward to getting a well drilled there and then getting rich,” Cadle says. “I bent over backwards to get those wells drilled.” Instead, the only income derived from his land today is through farming soybeans and corn.
FERC Floats $40M Pipeline Penalty Against Energy Transfer - Law360-- The Federal Energy Regulatory Commission on Thursday proposed a $40 million penalty against Energy Transfer Partners LP for allegedly cutting corners during the construction of its Rover gas pipeline, which led to a 2017 spill in Ohio. At its monthly open meeting — the first to feature recently confirmed commissioner Willie Phillips — FERC hit Energy Transfer with a show cause order directing the pipeline giant to respond to enforcement staff allegations that it intentionally and regularly used diesel fuel and other toxic and unapproved substances during the horizontal directional drilling of Ohio's Tuscarawas River along the pipeline's route. Traces of diesel….
FERC seeks answers on Energy Transfer pipeline violations - The US Federal Energy Regulatory Commission (FERC) on December 16 asked midstream company Energy Transfer Partners to explain why it should not have to pay a $40mn penalty for violations during the construction of its Rover natural gas pipeline. In a letter to Energy Transfer Partners and its Rover Pipeline subsidiary, FERC asked why it should avoid blame for “intentionally” including diesel, “other toxic substances and unapproved additives” into drilling mud during operations for pipeline construction in Ohio.FERC alleged that shortly after that drilling began in April 2017 under the Tuscarawas River in Ohio, there was a “large, inadvertent release” of 2mn gallons of contaminated drilling mud that migrated to a nearby protected wetland. Testing carried out by Ohio’s Environmental Protection Agency found the leaked fluid had characteristics similar to diesel fuel.FERC asked “Rover to show cause why it should not be assessed a civil penalty” in the amount of $40mn.The Rover pipeline extends 711 miles, carrying gas from the Appalachia shale basin to Midwest outlets.Alexis Daniels, a spokesperson for Energy Transfer, told the Reuters news agency that the company learned after the fact that “a rogue employee of an independent subcontractor has admitted under oath to have committed this act on his own volition and then tried to hide it.” Parties involved have 30 days to reply to FERC’s letter.
Regulators' endless devotion to fracking industry will cost Ohioans in money, health - Columbus Dispatch – by Leatra Harper - The Ohio Department of Natural Resources Division of Oil and Gas Resource Management has once again demonstrated its complete fealty to the fracking industry. It has done so by its continuing failure to propose rules to appropriately protect the environment and public health from the consequences of the irresponsible handling, processing and disposal of toxic, radioactive frack waste. Instead of addressing the serious issues arising from the disastrous federal failure to regulate through the “Halliburton Loophole,” thereby falsely classifying frack waste as “non-hazardous,” the division fails to address the problems this entails, although it has seen enough of the serious issues the lack of regulation has caused. Even the courts have not demanded the agency do needed rulemaking, and our citizen’s case lost on standing only – not on the merits. We even appealed to the U.S. Environmental Protection Agency to revoke primacy because the agency was not properly protecting citizens from the harms of the lack of regulation. Without recourse, we waited over 8 years for the division to propose rules that would effectively address the mishandling and toxic releases from frack waste processing and disposal. The agency obviously has no intention to deal with this serious issue as evidenced by its most recent attempt at rulemaking by proffering totally inadequate rules with public review and comment closed in only 30 days ending Nov. 29, just after a holiday. The very little time to engage, educate and formulate responses to the substantial deficiencies in the proposed rules substantiates our continued experience that the agency does not genuinely want public input to counter its support of the fracking industry by allowing cheap disposal of its massive amounts of toxic waste. To be most expeditious in the flawed process, the division combined the review and commenting process for two totally different waste handling/disposal schemes, Class II injection wells and Surface Waste Processing Facilities, into one. Frack waste facilities are handling millions of tons of frack waste with inadequate traceability of where the resultant concentrations of toxic chemicals and radionuclides go to assure proper disposal and accountability for those generating the waste. Historically, both types of facilities lack adequate monitoring and oversight, which will not be addressed in the proposed regulations. This ruse of rulemaking process is just another example of industry capture of the Ohio Department of Natural Resources. Our elected representatives are letting this happen, and Ohio taxpayers will pick up the bill, just as we are paying already to remediate leaking frack waste injection wells and cap abandoned wells. In addition to the lack of adequate bonding and severance taxes assessed the fracking industry, Ohio is giving the industry another massive subsidy in the completely inadequate rules proposed by the Division of Oil and Gas Resource Management. Ohioans will pay with their health and tax dollars for the continuing designation of the state as the cheap dumping ground for frack waste generated within the state and imported from other states, solving the industry’s biggest problem at our expense.
Utica/Marcellus Gas Production Expected to Increase in January - - – Oil and gas production from the Utica and Marcellus shale formations is expected to increase in January, according to data from the U.S. Energy Information Administration. The EIA’s Drilling Productivity Report shows that natural gas output stands to increase 78 million cubic feet per day by next month in the Appalachia region, which includes eastern Ohio’s Utica play and the Marcellus shale in Pennsylvania and West Virginia. This week, Hilcorp Energy Co. filed applications with the Ohio Department of Natural Resources for permits to deepen three of its wells in Fairfield Township in Columbiana County. So far this year, Hilcorp Energy Co. has been awarded 14 permits from ODNR to drill new wells in Columbiana County and one permit to deepen an existing well. EAP Ohio has been awarded seven permits for new wells in the county, and five permits to deepen existing wells. There were no new well permits issued in either Mahoning or Trumbull counties this year. Oil in the Appalachia region is expected to tick upward by 1,000 barrels per day next month, according to EIA. The agency reports that gas production is anticipated to increase in six of the seven shale plays across the country. The Permian Basin in Texas stands to post the greatest increase at 115 million cubic feet per day in January, while the Anadarko play in Oklahoma is projected to see production drop by 31 million cubic feet per day.
Where does Ohio rank in natural gas production? See the top 10 states - cleveland.com- Ohio has become a major producer of natural gas over the past decade with the advent of horizontal fracking, a technique that allows for greater access to reserves. The state’s natural gas output has increased more than 30-fold from 2010 to 2020, said Mike Chadsey, director of public relations for the Ohio Oil and Gas Association, and most of that can be attributed to ramped up production from the Utica shale reserve in the eastern part of the state.
Pa. releases final rule to cut methane leaks from existing oil and gas well sites Pennsylvania regulators have released a long-awaited final draft of rules to cut releases of smog-forming and climate warming air pollution from the state’s existing oil and natural gas well sites, but they will still not require companies to find and fix leaks at tens of thousands of low-producing wells. The rules are a last piece of the methane-reduction strategy that Gov. Tom Wolf announced nearly six years ago to cut down on emissions of the potent greenhouse gas from new and old sites across Pennsylvania’s oil and gas production industry. They are expected to take effect by the middle of next year. Scientists attribute about a third of the planet’s warming from greenhouse gases today to human-caused emissions of methane, which traps more than 80 times as much heat as carbon dioxide over 20 years. In the U.S., about a third of methane emissions come from the oil and gas industry. The new state rules will require some well owners to perform leak searches four times a year and upgrade equipment already in the field to cut down on pollution from controllers, pumps, compressors and tanks. In total, the rules are expected to reduce emissions of a smog-forming group of chemicals called volatile organic compounds by nearly 12,000 tons per year and methane emissions by about 214,000 tons per year — more than doubling the impact that was expected when the first draft of the rules was published two years ago. Mark Hammond, director of the Department of Environmental Protection’s air quality bureau, said the major driver for that improvement was better data that state regulators gathered by looking at Pennsylvania facilities to assess the rules’ impact, rather than relying on national estimates. The department made modest changes to the proposal after receiving comments from roughly 36,000 people and groups.
Massive aid on way to plug pollution from oil, gas wells - For decades, Pennsylvania has barely made a dent in stopping pollution from hundreds of thousands of abandoned or orphaned oil and gas wells. Now, the state may soon receive nearly $400 million to tackle one of its most insidious legacy pollution problems. “It’s a game changer,” said Kurt Klapkowski, director of Pennsylvania’s Bureau of Oil & Gas Planning and Program Management. He was referring to the $1.2 trillion Infrastructure Investment and Jobs Act that was passed by Congress on Nov. 5 and signed into law by President Joe Biden on Nov. 15. In addition to Pennsylvania's $400 million cut of federal dollars, the state will add matching funds for some projects. Climate change and pressure to throw a lifeline to communities that long survived on fossil fuel extraction provided a strong tailwind for bipartisan support. The legislation will deliver $4.7 billion nationwide, over the coming decade, to end the ongoing pollution of air, water and soil from abandoned oil and gas wells that pepper the country. Pennsylvania will get the most of any state from that big new pie to plug old wells, which emit methane and other pollutants that threaten public health and the environment. To put the funding increase in perspective, consider that Pennsylvania’s Office of Oil and Gas Management has spent a total of $37 million over the last three decades to plug 300 wells — most of them to rectify emergency situations like contaminated water, houses blowing up or methane gas filling up a church. In contrast, the state Department of Environmental Protection is lining up a batch of 500 wells to plug with just the first $25 million infusion of federal money from the U.S. Department of the Interior. Much of the pollution comes in the form of escaping methane from abandoned natural gas wells. Methane is a more potent greenhouse gas than carbon dioxide in the short term — 86 times more effective at trapping heat in the atmosphere when measured over a 20-year period. Methane is the second-most abundant greenhouse gas, and the process of oil and gas extraction is its largest source. Gas wells emit methane at a much higher rate than oil wells. In 2016, Stanford University researcher Mary Kang studied 88 abandoned wells in the state and found that 90% were leaking methane. A 2016 paper published in the Proceedings of the Academy of Natural Sciences estimated that abandoned wells were leaking 40,000–70,000 metric tons of methane a year, representing 5–8% of Pennsylvania’s total human-caused methane emissions. Other sources include hydraulic fracturing (fracking) for natural gas, livestock, fertilizers, industrial processes, wastewater treatment plants and landfills.
Pa. shale gas permits plunge to 13-year low as drillers keep focus on cash flow -- Pennsylvania shale gas drillers pulled just 34 permits for wells in November, the lowest number in 13 years, continuing their trend of keeping production low despite rising market prices for their product. The last time the state issued so few permits was in November 2008 just before the fracking boom brought a massive surge of development to the Marcellus Shale that peaked in December 2010 with 402 permits issued in a single month. The first unconventional well targeting the Marcellus Shale was drilled in 2004 by Range Resources Corp. November's total was about 53% less than the previous month's count, according to state Department of Environmental Protection data, and 38% less than in November 2020. The five largest exploration and production companies in Pennsylvania — EQT Corp., Chesapeake Energy Corp., Coterra Energy Inc., Range and Southwestern Energy Co. — spent another month keeping drilling and spending to a minimum and accumulating cash thanks to higher commodity prices. EQT pulled seven permits to drill, a decrease from 11 permits a year ago. National Fuel Gas Co.'s upstream unit, Seneca Resources Corp., pulled two permits in November. Four of the five top-producing counties in Pennsylvania — Susquehanna, Bradford and Lycoming in the northeast part of the state and Washington in the southwest — were among the most active counties for permitting in November, with seven permits each in Lycoming and Washington. Clarion, a county northeast of Pittsburgh that had no drilling activity in 2020, had three permits, bringing its year-to-date total to eight.
EIA DPR 12-2021: M-U Gas Production Still Lower than One Year Ago | Marcellus Drilling News Six of the seven largest shale plays in the U.S. will see an increase in natural gas production in January according to the latest monthly Drilling Productivity Report (DPR) issued by the U.S. Energy Information Administration (EIA). The Marcellus/Utica, collectively lumped together as “Appalachia” in the report, will see an increase of 78 MMcf/d (million cubic feet per day) in production next month. The M-U’s chief rival, the Haynesville, continues to see big growth, with an increase of 104 MMcf/d next month. The oil-based Permian will see an increase in natgas production of 115 MMcf/d due to associated gas coming out of the ground along with oil. The Permian’s oil production is set to hit a new all-time high this month, in December, and hit (for the first time ever) 5 million barrels of production per day in January.The cumulative increase in natural gas production across all plays is estimated to be a big 341 MMcf/d next month–roughly one-third of a billion cubic feet!M-U gas production was, last month, forecast to hit 35.6 MMcf/d in December (see EIA DPR: Shale NatGas & Oil Production Flirt with Record Highs). It didn’t happen. The EIA number crunchers were way off. Production is now recast to be 34.8 MMcf/d this month. EIA predicts production in the M-U for January will be 34.9 MMcf/d. We are still well below last December’s 35.6 MMcf/d. Below are the three charts the EIA doesn’t include in the official PDF of the report (for whatever reason). We think these are the three best charts they issue each month.Below is the one chart we obsess over each month–our favorite chart produced by EIA. It shows estimates for total production in the coming month. We also like the following chart which shows drilled but uncompleted (DUC) numbers. Notice the story the chart below tells: New drilling in all plays has slowed down and producers are finishing already-drilled wells at a faster clip. Sooner or later we’ll run out of DUCs to complete. The full December DPR (with estimates for January):
A pipeline runs through it: Stream crossings by the Mountain Valley Pipeline - an overcast October afternoon, clouds cloaked the top of Poor Mountain as a construction crew worked to string a natural gas pipeline across the highest point in the Roanoke Valley. At 3,720 feet above sea level, this is one of the places where concerns about the Mountain Valley Pipeline begin. When it rains, dirt unearthed by clearing land and digging a trench for the pipe turns to mud and silt. The sediment is washed downhill, channeled by a 125-foot-wide strip cut into the mountain. Some of it reaches the streams and wetlands below. Although much of the controversial project is completed, Mountain Valley still needs state and federal approval to cross the remaining water bodies, either by digging through or boring under them. If the State Water Control Board grants a permit when it meets Tuesday, opponents say it will replicate a known harm. “MVP has shown an inability to construct without violating water quality standards, so crossing streams in the remaining steepest portions of the route will inevitably bring more sediment pollution and harm to water resources,” said Jessica Sims, state field coordinator for Appalachian Voices, one of the groups fighting the pipeline. At public hearings in September, many speakers pointed to the company’s environmental record — more than 300 violations of sediment and erosion control regulations since work began in 2018 — in urging the board to deny the permit.
Pipeline opponents hold ‘violation vigil’ in Richmond - Opponents of the Mountain Valley Pipeline held a ‘Violation Vigil’ Saturday in advance of a key hearing in Richmond next week. The event at the Dogwood Dell amphitheater highlighted more than 300 water quality violations along the path of the pipeline in Virginia. “My violation is number 48,” one of the participants said during the event. “It happened on January 22nd 2019 in Franklin County.” Tuesday, the State Water Control Board will consider a key permit that would allow MVP to cross more than 200 streams and wetlands in the Commonwealth. “And we must understand that when we fight this fight against the pipelines or environmental injustice, we’re fighting against lives being destroyed,” said keynote speaker Rev. William Barber II, Chair of the National Poor People’s Campaign. " We’re fighting against communities being disrupted,” he said. Friday, a spokesperson for the Mountain Valley Pipeline said crews have successfully completed multiple crossings. In a written statement, Natalie Cox said completing construction and fully restoring the remainder of the right-of-way represents the best outcome for the environment, landowners and communities along the route. Following is the complete statement from MVP: Mountain Valley appreciates the Virginia DEQ staff’s diligence in performing a comprehensive review of the MVP project’s remaining waterbody and wetland crossings in Virginia. Total project work on the Mountain Valley Pipeline is nearly 94 percent complete, including more than half of the right-of-way fully restored; and crews have previously and successfully completed multiple crossings using both open-cut and trenchless crossing methods. Mountain Valley believes that completing construction and fully restoring the remainder of the right-of-way remains the best outcome for the environment, affected landowners, and communities along the route, as well as the homes and businesses – in Virginia and across the eastern United States – that need greater and more reliable access to affordable natural gas.
Hundreds rally in Va. in opposition to natural gas pipeline (AP) — Hundreds of opponents of a natural gas pipeline rallied on Saturday in Virginia’s capital in advance of an upcoming key regulatory decision. The Virginia State Water Control Board is expected to vote Tuesday on whether to allow construction of portions of the Mountain Valley Pipeline in wetlands and across over 200 Virginia waterways, the Richmond Times-Dispatch reported. The Rev. William Barber, a North Carolina-based civil rights leader, told the crowd at Byrd Park that projects like the proposed pipeline are “an abusive sin” that would harm the poor. The planned 303-mile (488-kilometer) mile pipeline will take natural gas drilled from the Marcellus and Utica shale formations and transport it through West Virginia and Virginia. A 75-mile extension into central North Carolina is also proposed. Barber, who is now the head of the national Repairers of the Breach movement among other roles, pointed out how developers of the Atlantic Coast Pipeline cancelled the project in 2020 following fierce opposition by environmental groups and residents along parts of the line’s path. “We had to fight against one pipeline,” Barber said. “They should have learned by now, Virginians aren’t having this stuff. West Virginians aren’t having it. North Carolinians aren’t having it. They must not know who we are, but they’ll learn.” Mountain Valley Pipeline spokesperson Natalie Cox called Barber’s message that the project is sinful “an uninformed and unproductive comment.” The pipeline, Cox added, is “designed to provide reliable, affordable, clean-burning natural gas to homes and businesses in Virginia and throughout the eastern United States.” The proposed North Carolina extension took a hit earlier this month when Virginia’s State Air Pollution Control Board voted against a permit for a gas compressor station located in a county that borders North Carolina.
State panel approves stream-crossing permit for Mountain Valley Pipeline — The Mountain Valley Pipeline made it across troubled waters Tuesday. In a 3-2 vote, the State Water Control Board granted a permit for the natural gas pipeline to cross about 150 streams and wetlands in Southwest Virginia, surmounting one of the beleaguered project’s most protracted struggles. Although a similar permit from West Virginia and federal approval is still required, Mountain Valley expressed confidence that it will complete construction “in a way that protects natural resources and meets public demand for reliable, affordable and lower-carbon energy.” About 94% of the pipeline is finished, spokeswoman Natalie Cox wrote in an email Tuesday, and “the remaining waterbody crossings can be completed successfully and without adverse impacts to sensitive resources.” However, the Virginia Department of Environmental Quality has already cited the joint venture of five energy companies building the pipeline with nearly 400 violations of erosion and sediment control regulations. Opponents argue that the true number is much higher — and will only increase if stream crossings are allowed to resume after earlier permits were struck down by the courts. In recommending approval for a company that it has cited repeatedly since work began in 2018, DEQ said most of Mountain Valley’s failures to adequately control muddy runoff from construction sites did not ultimately lead to sediment reaching water bodies.
Virginia board approves stream-crossing permit for gas pipeline - A Virginia board has granted a waterbody crossing permit for the Mountain Valley Pipeline. The State Water Control Board voted 3-2 on Tuesday to grant a permit for the natural gas pipeline to cross about 150 streams and wetlands in southwest Virginia, The Roanoke Times reported. The pipeline still needs a similar permit from West Virginia and federal approval. The planned 303-mile (488-kilometer) pipeline will take natural gas drilled from the Marcellus and Utica shale formations and transport it through West Virginia and Virginia. The project has faced legal challenges from environmental groups. A 75-mile (121-kilometer) extension into central North Carolina also has been proposed. The Virginia Department of Environmental Quality has cited the joint venture building the pipeline with nearly 400 violations. Opponents argue that the true number is higher and will increase if crossings resume. In its recommendation for approval, the department said most failures to control runoff did not lead to sediment reaching water bodies. David Sligh, conservation director for Wild Virginia, called the decision "heartbreaking." “Yet another public agency that’s supposed to protect us and our natural treasures has failed to live up to the standards we have a right to expect,” Sligh said in a statement.
Mountain Valley Pipeline stream-crossing permit approved by Virginia regulators - Virginia Mercury - A divided Virginia State Water Control Board approved a necessary stream-crossing permit for the embattled Mountain Valley Pipeline Tuesday despite opponents’ hopes that its record of environmental violations would tank it.The board voted 3-2 to issue a Virginia Water Protection Permit to MVP, with board members Paula Jasinksi and Ryan Seiger dissenting. Board chair Heather Wood and member Jillian Cohen were absent. “The facts show that remaining waterbody crossings can be completed successfully and without adverse impacts to sensitive resources as the project team has proposed,” Mountain Valley spokesperson Natalie Cox wrote in a statement. “In fact, Mountain Valley already has successfully performed multiple crossings of waterbodies and wetlands in Virginia, without adverse impacts to water quality.” The approval came as a blow to pipeline opponents, who have long argued that there is no need for the natural gas the project will supply and that it will continue to cause environmental degradation along its 107-mile path through Giles, Craig, Montgomery, Roanoke, Franklin and Pittsylvania counties. “We’re fighting against communities being disrupted. We’re fighting against monies being diverted to fossil fuel companies that ought to be put in health care and put in the creation of green jobs,” civil rights leader the Rev. William J. Barber II said in a fiery speech at an anti-pipeline rally Saturday in Richmond. Opponents have particularly pointed to Virginia Attorney General Mark Herring’s 2018 lawsuit against Mountain Valley over violations related to erosion and sedimentation. The suit was settled in 2019 with Mountain Valley agreeing to pay a $2.15 million penalty and submit to third-party environmental monitoring. “While there were a number of violations … we’re told by our [erosion and sedimentation] folks that these violations are not ongoing and regular and that they’re being addressed shortly after they’re identified,” Dave Davis, director of the Department of Environmental Quality’s Office of Wetlands and Stream Protection, told the board Tuesday. Furthermore, he added, state regulations outline “nine reasons to deny a VWP permit, but not one of those is to deny a permit based on past violations of” erosion and sediment limits. However, the nonprofit Wild Virginia, which has fought the project since its inception, said its own analysis of Virginia Department of Environmental Quality inspection reports has shown that Mountain Valley has violated environmental rules more than 1,500 times during its existence. “The DEQ has consistently failed to acknowledge the magnitude of these problems or take effective action to stop them,” the group said in a statement. “DEQ’s description of MVP’s record of violations to the board was inaccurate and woefully incomplete.” Tuesday’s approval of the Virginia Water Protection permit was the latest chapter in Mountain Valley’s long and twisting road to getting — and keeping — water-crossing approvals….
D.C. Circuit eminent domain battle may hit FERC gas projects - Federal judges yesterday considered the path for landowners to pursue an unusual, sweeping challenge to takings for natural gas pipelines. Homeowners located along the route of the Mountain Valley pipeline appeared before the U.S. Court of Appeals for the District of Columbia Circuit after filing a legal challenge alleging that it is unconstitutional for the Federal Energy Regulatory Commission to delegate its eminent domain authority to pipeline developers. Yesterday’s D.C. Circuit arguments turned on a narrow procedural question, but a lawyer for the landowners said a broad ruling in favor of her clients could potentially void FERC certificates for natural gas projects across the country. "If enabling legislation is unconstitutional, then all decisions are set aside," said Mia Yugo, a lawyer at the firm Hafemann Magee Thomas. She argued that a judge of a lower court had wrongfully dismissed her clients’ challenge. The legislation at issue in the case is the Natural Gas Act, which extends the federal government’s authority to condemn private land for public use to private entities that have secured from FERC certificates of public convenience and necessity. FERC has in recent years issued a spate of certificates to natural gas pipelines like Mountain Valley. Opponents of those projects have argued that building a large network of gas pipelines is neither necessary nor in the public’s interest. Yugo’s clients had originally brought their case in the U.S. District Court for the District of Columbia but hit a roadblock last year when a judge of that court said the case should land instead before the D.C. Circuit, which gets the first bite at lawsuits over FERC certificates. Judge Cornelia Pillard said yesterday that the D.C. Circuit also has the power to address constitutional questions. The judge, an Obama appointee, asked Yugo whether the court could sidestep the constitutional question by ordering a reconsideration of the Mountain Valley route, which would put a new set of landowners in the pipeline’s path. Those newly affected homeowners might not raise the same concerns as Yugo’s clients, said Pillard. Yugo replied that such a decision would remove her clients’ ability to bring their lawsuit at all. Judge Justin Walker, a Trump appointee, asked whether the landowners hoped to modify Mountain Valley’s FERC certificate if they were allowed to pursue their challenge in district court. Yugo replied that her clients want the courts to invalidate the "entire scheme" of pipeline condemnations under the nondelegation doctrine, which says Congress cannot hand off its legislative powers to federal agencies. Conservative jurists have expressed interest in reviving the long-dormant nondelegation doctrine in other contexts, such as a looming Supreme Court battle over EPA’s authority to regulate climate change under the Clean Air Act.
FERC cracks down on pipelines - The Federal Energy Regulatory Commission toughened its stance on alleged violations associated with natural gas pipelines yesterday, saying enforcement has been too lax in the past and that stricter policies may be needed. "We are being more aggressive and ensuring that those conditions are actually being enforced," FERC Chair Richard Glick told reporters after the agency’s open meeting yesterday. "Under previous leadership, the commission did not adequately enforce its conditions." Yesterday’s meeting showcased the sharp divisions among commissioners about the agency’s oversight of natural gas projects. In contrast to Glick’s get-tough rhetoric, Republican members of the panel warned that putting up obstacles to pipeline development can lead to problems, such as potential gas outages this winter in the Northeast. "We’re going to have to face the reality that the need for gas-fired generation is not going to go away next month, next year, in the short term. It is not,” said Republican Commissioner Mark Christie. “We’re going to have to deal with that and be willing to build the transportation facilities to get the gas to the generators so we can keep the lights on.” Commissioner Allison Clements, a Democrat on the panel, said the agency’s moves "illustrate the profound challenges" facing natural gas projects and signal the need for broader policy changes. She and fellow Democrat Glick reiterated their support for changing how the agency assesses proposed new natural gas pipelines, a process outlined in its certificate policy statement. "To address the challenges ahead, we need to stop debating whether change is necessary and take the forward-looking steps required to meet our statutory obligations," Clements said. The meeting was the first with Willie Phillips, a fellow Democrat who was sworn in this month as FERC’s fifth commissioner. Phillips could give Glick and Clements the votes they need to revise the pipeline policy statement and add "greater emphasis on environmental impacts" into FERC’s review processes, ClearView Energy Partners said in a note Dec. 3. Phillips, for his part, did not vote on any of the items yesterday, but he said he looked forward to getting up to speed while prioritizing electric reliability and affordability.
About half of U.S. oil pipeline space is empty after boom time building spree (Reuters) - About half of U.S. oil pipeline space is sitting unused, heating up competition for barrels in higher-output areas like the Permian Basin in Texas. Overall U.S. pipeline capacity utilization is at around 50%, compared with a range of 60% to 70% headed into early 2020 before the coronavirus pandemic hit, according to consultancy Wood Mackenzie. Pipelines overall are now half-full, as production, which surged to 13 million barrels per day in early 2020 to make the United States the top oil producer, has averaged just 11 million bpd in 2021. Oil and gas shippers often find themselves building pipelines amid a production boom only to find there is too much capacity when downturns occur. Numerous pipelines were built in the Permian in Texas and New Mexico - the largest U.S. oilfield - to export locales while production surged between 2017 and 2020. Some pipeline operators in areas like the Permian Basin have responded by cutting pre-pandemic shipping rates, as the U.S. oil industry has been slow to recover from the coronavirus outbreak. Generally, basins that are overbuilt, like the Permian, have lower uncommitted shipping rates than before the pandemic, but basins with less pipeline capacity have managed to raise rates, because there are fewer shipping options, said Ryan Saxton, head of oil data at Wood Mackenzie. During the pandemic, companies began offering discounted rates to committed shippers as an incentive, said Jesse Mercer, senior director of oil markets at Enverus. As production continues to return, companies are likely to wind down those offers, he said. The best-performing pipeline in the Permian right now at around 94% utilization, is Phillips 66's Gray Oak Pipeline, Saxton said. The uncommitted tariff rate to ship on Gray Oak is about $2.97 per barrel, he said, compared with the more than $4.00-per-barrel on the BridgeTex, another Permian pipeline. BridgeTex, a joint venture from Magellan Midstream Partners LP, is at around 70% utilization, Saxton said. The 440,000-bpd line delivers crude to Magellan's terminal in East Houston. BridgeTex volumes in the third quarter 2021 fell to just over 315,000 bpd, about 5% below volumes in 2020 due to a decrease in uncommitted shipments in the quarter and unfavorable pricing differentials, Magellan said in its most recent earnings call. North Dakota's Bakken production is lagging pre-pandemic levels, and Energy Transfer LP's Dakota Access Pipeline, which can carry about 570,000 bpd out of the region, is at about 77% of utilization, compared with nearly full utilization before the pandemic, Saxton said. However, Dakota Access' uncommitted tariff rate is $6.64 per barrel, above the around $6.28 per barrel before the pandemic, Saxton said. There are fewer pipes out of the Bakken than in the Permian. Energy Transfer declined to comment for this article.
A Missouri gas company figured out how to keep its illegal pipeline running - Thousands of Missourians received an alarming email from their utility company last month: Unless federal regulators allowed a new natural gas pipeline in the region to keep operating, as many as 400,000 St. Louis residents could be without heat this winter. The message came from Spire Missouri Inc., a natural gas utility serving some 1.2 million customers in Missouri. “The level of panic was something I had not seen,” said Dawn Chapman, a St. Louis resident and co-founder of Just Moms STL, a group that educates people about Superfund waste sites in the area. Missouri Representative Cori Bush called on the Federal Energy Regulatory Commission, or FERC, to investigate the nature of Spire’s claims. “I am gravely concerned that Spire Inc. may be actively weaponizing the fears of our community members,” she wrote in a November 17 letter, “many of whom are low-income individuals, families with small children, and older adults — for their own personal gain and profit.” Spire’s warning to its customers – and the resulting panic – is the latest in a long-running saga over the controversial 65-mile-long Spire STL pipeline. In 2018, FERC granted Spire permission to build a new pipeline capable of carrying 400,000 dekatherms of natural gas everyday. The route would connect the Rockies Express Pipeline in southwest Illinois to the St. Louis area. Construction finished and the pipeline went online a year later. But in 2020, the nonprofit Environmental Defense Fund, or EDF, filed a lawsuit against FERC for authorizing the project. It argued that FERC granted permission without the legally-required proof that a new pipeline was needed and beneficial for the region. There were already five natural gas pipelines serving the St. Louis area, some of which were carrying Spire’s natural gas. The pipeline’s construction ultimately cost $287 million. Normally, pipelines must show market demand before construction. Evidence for market demand is usually shown through multiple contracts or agreements with utilities that are interested in utilizing the pipeline. But in the case of the STL project, their only contract was, and is, with their own affiliate, Spire Missouri.
Tennessee Gas Pipeline Announces Responsible Gas Pooling Service - Yesterday Tennessee Gas Pipeline (TGP), a subsidiary of Kinder Morgan, filed a proposal with the Federal Energy Regulatory Commission (FERC) to implement a “responsibly sourced natural gas (RSG) supply aggregation pooling service” at select locations across the TGP system. Translation: Utilities and other buyers will be able to buy RSG certified natural gas for their customers, costing them more money. According to yesterday’s announcement, “The proposed service is designed to enable suppliers and customers on TGP to purchase and sell RSG supply at non-physical trading locations, ultimately serving end-users, utilities, power plants and LNG facilities connected to the TGP system.” Here’s how it works. A driller like Southwestern Energy, or Chesapeake Energy, or EQT, or any of a number of other drillers in the Marcellus/Utica already signed up with one of several certification services, produces RSG molecules and flows them on the TGP. The pipeline itself doesn’t shut down for all other non-RSG producers. The RSG-produced molecules mix and mingle with non-RSG molecules in the same pipeline. There is no distinction between methane (CH4) molecules produced one way or the other. However, drillers can charge a small premium for RSG gas, and customers like utility companies that want to prove their green credibility can pay more to buy it. The actual molecules that the utility ends up with may or may not be RSG-produced molecules. But that’s not the point. Sorry to say this, but this is the same scam utility companies try to pull all the time: You can sign up to get electricity produced by “renewable” sources like windmills and solar farms, paying more for it. Yet the juice that flows to your home most likely got produced at a natural gas or coal-fired power plant. You pay a lot more just to feel good about getting the same electricity delivered to your home. Same thing with RSG methane molecules. But hey, if TGP call sell this film flam because there’s a market for it, who are we to get in the way, right? Everyone makes more money–and rate payers get hosed.
Lower 48 E&Ps, Midstreamers Eyeing RSG Label for Natural Gas - More Lower 48 producers and increasingly, midstream operators, are looking to Project Canary to earn environmental certification for their natural gas supplies. Tug Hill Operating LLC and XcL Midstream Operating LLC, which principally operate in West Virginia’s Marshall and Wetzel counties, have partnered to gain the responsibly sourced gas (RSG) designation across all of their upstream and midstream operations. Earlier this year, privately held exploration and production (E&P) company Tug Hill launched a pilot in which 45 wells were certified through Project Canary’s TrustWell system. “The partnership between Tug Hill and XcL means, for the first time, gas purchasers will have the opportunity to buy RSG that has been TrustWell certified from the wellhead to the receipt point,” said CEO Michael Radler, who oversees both companies. Tug Hill produces more than 800 MMcf/d of gas and delivers it to market via XcL’s gathering system. Tug Hill and Xcl, both sponsored by private equity giant Quantum Energy Partners, would be the first upstream and midstream companies to jointly seek independent certification of 100% of their operating assets. The management teams “believe the integration of independent, high fidelity upstream and midstream certifications will result in a unique and unmatched RSG offering for the market.” Earlier this year, Tug Hill joined Our Nation’s Energy Future, aka ONE Future, a coalition that has pledged to reduce collective methane emissions to 1% or lower. “Tug Hill places an extremely high focus on operational excellence, sustainability and being a good neighbor within the communities where we operate,” said COO Sean Willis. “Tug Hill is committed to utilizing high fidelity technology and rigorous operating standards to reduce the methane intensity of our operations and produce energy responsibly.” XcL COO Justin Trettel noted that the gathering assets and interconnect points are “in the overlapping core” of the Marcellus and Utica/Point Pleasant shales. The independent certification “helps ensure midstream assets minimize unwanted methane emissions and maintain top tier operating practices, which will provide additional value for our customers.” Project Canary noted that its TrustWell and Midstream certifications analyze more than 600 unique operational, environmental, social and governance (ESG) data points on a per-well and midstream asset basis. In addition to independent review and ESG certification, Tug Hill plans to install Canary X continuous emissions monitors on locations that represent about 80% of its production in the region. The monitors measure and record methane emissions. XcL also would install the emissions monitors at each of its major locations, including the Clearfork Processing facility and several central dehydration and compressor stations.
New York City Bans Natural Gas From New Buildings --The New York City Council voted on Wednesday to ban the use of natural gas in new buildings in a bid to reduce the city's carbon footprint."The bill to ban the use of gas in new buildings will (help) us to transition to a greener future and (reach) carbon neutrality by the year 2050," said City Council Speaker Corey Johnson, noting:"We are in a climate crisis and must take all necessary steps to fight climate change and protect our city."Once it does, new buildings after 2027 will be heated by fossil fuel alternatives, most likely electricity, the report notes.The idea of moving away from gas is not new. In California, the city of Berkeley became the first to enact a ban on new natural gas hookups in new buildings back in 2019. New York was among the cities that have been considering the measure for a while now, along with Denver, Seattle, and San Francisco.For the proponents of gas bans, the benefits are clear and come down to lower carbon emissions. For the opponents, there are too many disadvantages, from the cost of switching a house from gas to electricity to the effect of more all-electric households on the grid."The intermittent nature of renewable sources like solar and wind necessitates another form of energy when the sun isn't shining, and the wind isn't blowing," wrote the chief executive of the American Public Gas Association in an article commenting on the bans for Utility Dive.State authorities seem to be against the measure in most of these places, but New York appears to be an exception. In New York City, heating, cooling, and electricity supply for buildings account for as much as 70 percent of carbon emissions, and supporters of the gas ban see it as a necessary step to reduce this amount.Yet opponents don't see it this way."Eliminating the direct use of natural gas in homes and businesses would simply shift the use of natural gas from inside the home to powering an already overburdened electric grid through natural gas-fired power plants—if we're lucky—and in some cases, coal-powered plants," Dave Shryver from the American Public Gas Association said back in June this year.Until now, the most populated U.S. city that has banned gas in new buildings is San Jose in California with about 1 million residents.However, as Reuters reports, New York's move to all-electric buildings could mean a higher price tag for consumers using electricity for heat than those relying on gas. This winter, the average household in the U.S. Northeast is expected to pay $1,538 to heat their home with electricity, compared with gas at about $865.
More than 32 GW of New Gas-Fired Power Plants in U.S. Pipeline - Recent reports from groups analyzing U.S. power generation note how states near the nation’s largest shale plays are expected to bring significant new natural gas-fired generation online over the next few years, despite concerns about recent market volatility that sent gas prices to their highest levels in more than a decade. With a long-term outlook favoring natural gas as U.S. coal stockpiles continue to dwindle, utilities are moving forward with plans to add gas-fired generation capacity through 2025, according to Colorado-based BTU Analytics, a FactSet Company. Andrew Bradford, Vice President Power for FactSet, told POWER on Dec. 14 his group “is tracking 32.3 GW of natural gas-fired power plants with in-service dates through 2025 that are in advanced stages of development.” Bradford said “14.2 GW have a status of under construction, 3.4 GW are at pre-construction, and 14.7 GW have a status of advanced permitting.” Bradford said the PJM and MISO regions, along with the U.S. Southeast, are the most-active new-build regions with 15.8 GW, 3.8 GW, and 6.2 GW, respectively, planned to come online over the next few years. “It is important to think about all of these different generation types as backstops for each other,” said Sarp Ozkan, Senior Director of Power & Renewables Analytics at Enverus. “So, as the price of natural gas as the fuel increases, the backstops like coal and fuel oil become more competitive and are called upon to serve the load. As the price of natural gas as the fuel decreases, coal and fuel oil get moved further away from being in the money.” Ozkan on Tuesday told POWER that “natural gas provides two distinct advantages. One advantage is that it is dispatchable, making it necessary for peak demand periods. Additionally, it is the cleaner in terms of emissions profile than coal and fuel oil.”
Natural Gas Futures Erase Early Gains, Finish in Red on Continued Warmth; Cash Rallies A chillier weekend forecast lifted natural gas futures back above $4.000/MMBtu early in Monday’s session. The gains, however, were not to last as subsequent weather data backed off the cold and sent the January Nymex gas futures contract tumbling 13.1 cents to $3.794. February slid 12.8 cents to $3.761. m Spot gas prices were higher to start the week despite mostly mild conditions across the country. Gains were strongest out West with a Pacific storm in place, which helped boost NGI’s Spot Gas National Avg. up 45.5 cents to $4.175. After hinting that temperatures could finally turn a bit more wintery, the weekend weather models shifted a little colder, showing enough chill in the pattern to bring demand closer to normal in the latter part of the month. From here, the key would be to see if models move toward an actual colder pattern, according to Bespoke Weather Services. This is possible, the forecaster said, given a healthy blocking signature showing up in the North Atlantic Oscillation region. However, much depends on the Pacific side, so Bespoke is holding a neutral view for now. NatGasWeather said the weather data does still bring an increase in demand this weekend and continues to show very cold air over Western Canada Dec. 27-31, teasing the northern United States. Overall, the timing of swings in national demand and major features remain intact, and the midday Global Forecast System did gain several heating degree days (HDD) Dec. 24-26 by forecasting a slightly stronger cold shot into the northern United States, according to the forecaster. “But what we expect will be most important going forward is how much Arctic air over Canada Dec. 28-31 is able to bleed into the northern United States,” NatGasWeather said. Until then, national demand is expected to be much lighter than normal for the current week, “by a lot,” according to the firm. Demand is expected to be so low that next week’s government inventory report is likely to be more than 70 Bcf lighter than normal. EBW Analytics Group also noted the very mild near-term outlook, cautioning that Wednesday and Thursday of this week may each feature 10 heating degree days (HDD) below normal, constraining attempts to rally. As the market bridges extreme near-term warmth and turns its focus to a colder late-December that could add 17 Bcf/d of weather-driven demand in two weeks, further upside for the Nymex winter contract appears likely as a long-awaited relief rally sets in. “The extent of gains, however, may pale in comparison to the $1.79/MMBtu loss in the January contract’s first six trading sessions as the front month,”
U.S. natural gas futures fall 3% on mild weather forecasts (Reuters) - U.S. natural gas futures climbed almost 2% on Wednesday on forecasts for colder weather over the next two weeks than previously expected. That price gain came despite near record U.S. output, a decline in U.S. liquefied natural gas (LNG) exports this week, a 4% slide in European gas prices and forecasts for less U.S. demand next week than previously expected. Front-month gas futures rose 5.5 cents, or 1.5%, to settle at $3.802 per million British thermal units (mmBtu). On Tuesday, the contract closed at its lowest since Dec. 7. Global gas prices have soared to all-time highs over the last few months - most recently in Europe on Tuesday - as utilities around the world scrambled for LNG cargoes to replenish low stockpiles in Europe and meet surging demand in Asia, where energy shortfalls caused power blackouts in China. Analysts have said European inventories were about 20% below normal for this time of year, compared with just 3% below normal in the United States. Looking ahead, many analysts said milder-than-normal weather in December will cause U.S. utilities to leave enough gas in storage to allow stockpiles to reach above-normal levels in a week or two, the first above-normal storage levels since April. Data provider Refinitiv said output in the U.S. Lower 48 states has averaged 96.53 billion cubic feet per day (bcfd) so far in December, just shy of November's monthly record of 96.54 bcfd. Refinitiv projected average U.S. gas demand, including exports, would jump from 109.4 bcfd this week to 118.2 bcfd next week as the weather turns seasonally colder. Those forecasts, however, were lower than Refinitiv's outlook on Tuesday. The amount of gas flowing to U.S. LNG export plants has averaged 11.8 bcfd so far in December now that the sixth train at Cheniere Energy Inc's Sabine Pass plant in Louisiana is producing LNG. That compares to 11.4 bcfd in November and a monthly record of 11.5 bcfd in April. This month's record-setting LNG feed gas came despite reductions this week at Sabine Pass and Freeport LNG's export plant in Texas. With gas prices around $41 per mmBtu in Europe and $36 in Asia, compared with about $4 in the United States, traders said buyers around the world would keep purchasing all the LNG the United States can produce.
US gas storage inventory drops by 88 Bcf as weaker withdrawal lies ahead | S&P Global Platts - US gas inventories fell by 88 Bcf for the first full storage week of December, which equaled the S&P Global Platts' survey expectation, while a draw nearly one-third the five-year average appears likely for the week in progress. Storage systems withdrew 88 Bcf for the week ended Dec. 10, according to data released by the US Energy Information Administration on Dec. 16. It equaled the 88 Bcf draw expected by an S&P Global Platts survey of analysts. Over the past five weeks, the survey has missed the EIA estimate by an average of 2 Bcf. The draw was less than the five-year average of 114 Bcf as well as last year's 118 Bcf pull in the corresponding week. Demand this winter has so far been unremarkable, and the long-expected boost to supplies is materializing as producers ramp up output in the marginal-producing basins. Combined, these have left the market longer on supply than in comparable historical periods, according to Platts Analytics. Working gas inventories decreased to 3.417 Tcf. US storage volumes now stand 326 Bcf, or 8.7%, less than the year-ago level of 3.743 Tcf and 64 Bcf, or 1.8%, less than the five-year average of 3.481 Tcf. Platts Analytics' supply and demand model forecasts a 52 Bcf draw for the week in progress, which is roughly one-third of the five-year average pull of 153 Bcf. This would flip the deficit to the five-year average to a surplus as US production strengthens and cold weather has failed to materialize at a nationwide level. Under normal weather, Platts Analytics expects total US storage inventories to draw down to 1.52 Tcf by the end of March 2022, roughly 100 Bcf above the previous forecast end of winter level. This outlook is based in part on US demand, excluding exports, averaging 101 Bcf/d during the ninety-day peak winter period of December through February. The NYMEX Henry Hub futures have contracted in response to the loosening of US balances. The January contract was down 3 cents to $3.77/MMBtu on Dec. 16. While this is far below the $6/MMBtu seen in October, it is still more than $1/MMBtu above this time last December. The persistence of this augmented supply, and the fact it is unwavering even when temperatures are mild and demand is weak, leaves the market with a bearish overhang that will take some serious winter demand to shake loose, according to Platts Analytics.
U.S. natgas slips 2% to one-week low on milder weather forecasts (Reuters) - U.S. natural gas futures fell 2% on Friday to a one-week low on record output and forecasts for milder weather through late December than previously expected. Mostly mild weather since mid-November has kept heating demand low and allowed utilities to leave so much gas in storage that there will soon be more of the fuel in stockpiles than is usual for the time of year for the first time since April. The U.S. futures decline came despite near-record gas prices in Europe and Asia that were over 11 times higher than U.S. prices and should keep demand for U.S. liquefied natural gas exports (LNG) strong for months to come. Front-month gas futures fell 7.6 cents, or 2.0%, to settle at $3.690 per million British thermal units (mmBtu), their lowest close since the contract settled at a four-month low on Dec. 6. For the week, the contract fell about 6%, putting it down for a third week in a row. The premium of March 2021 futures over April 2021 NGH22-J22 slid to a record low of around 5 cents per mmBtu. The industry uses the March-April spread to bet on the winter heating season when demand for gas peaks. That puts the March-April spread, known as the 'widow maker', close to going into contango with summer contracts (April) trading over winter contracts (March) even before the official start of winter with the solstice on Dec. 21. In the spot market, next-day power prices in New England E-NEPLMHP-IDX spiked to their highest since January 2018 on forecasts the region will experience its first winter cold snap next week. Global gas prices have repeatedly reached all-time highs over the last few months as utilities around the world scrambled for LNG cargoes to replenish low stockpiles in Europe and meet surging demand in Asia, where energy shortfalls caused power blackouts in China. U.S. futures jumped to a 12-year high of more than $6 per mmBtu in early October, but have retreated because the United States has plenty of gas in storage and ample production for winter. Analysts have said European inventories were about 20% below normal for this time of year, compared with just 2% below normal in the United States. Data provider Refinitiv said output in the U.S. Lower 48 states has averaged 96.8 billion cubic feet per day (bcfd) so far in December, which would top the monthly record of 96.5 bcfd in November. Refinitiv projected average U.S. gas demand, including exports, would jump from 109.7 bcfd this week to 120.6 bcfd next week and 123.6 bcfd in two weeks as the weather turns seasonally colder. Those forecasts were higher than Refinitiv's outlook on Thursday. The amount of gas flowing to U.S. LNG export plants has averaged 11.9 bcfd so far in December, now that the sixth train at Cheniere Energy Inc's Sabine Pass plant in Louisiana is producing LNG. That compares to 11.4 bcfd in November and a monthly record of 11.5 bcfd in April.
How Biden's agencies order hits natural gas - President Biden’s executive order to decarbonize federal agencies last week left unanswered questions about which energy industries — including emerging technologies like hydrogen — will benefit most and how federal agencies will go about complying. Because of the federal government’s sheer size, the order — which covers everything from federal buildings’ level of energy efficiency to the fuels they use for space and water heat — could reshape the economics of building energy policy in the public and private sectors for years to come. That, in turn, could influence debates over banning the use of natural gas, which continue to roil statehouses and city halls across the country. It also could sway emissions, considering buildings are a significant source of U.S. greenhouse gases. "The main thing this [plan] will do is to help show, by example, that building electrification is possible," said Amy Turner, a senior fellow for the Cities Climate Law Initiative at Columbia University’s Sabin Center. The federal government, with its over 300,000 buildings, "may be able to benefit from economies of scale" when it buys clean heat technologies, she said. The order called for the federal government to halve greenhouse gas emissions from its own buildings by 2032 — then hit net zero by 2045. That goal was packaged into a broader directive for federal agencies to stop buying vehicles and electricity that emit carbon, at varying dates in the future. A top priority, according to the Biden administration, will be ditching fossil fuel equipment in new and existing buildings in favor of electric-powered technologies — an idea that has spurred bitter debates between climate activists and gas utilities in states and cities across the U.S. But the administration’s plans didn’t prescribe electrification in all cases, leaving room for other technologies to meet its definition of “net-zero” emissions. That means the natural gas industry’s favored alternative fuels, like hydrogen or biomethane, could presumably play a role at some point in the future. The definition of "net zero" also allowed for some amount of offsets, including through natural carbon sinks, carbon capture and storage, and direct air capture.
Halting the Gas Export Boom -- LAKE CHARLES IS A SMALL CITY of some 80,000 people located in the southwest corner of Louisiana, not far from the Texas border. On the surface, it might seem tailor-made for a massive new build-out of industrial facilities designed to export gas. There's plenty of gas produced in the region, there's a well-developed network of pipelines to deliver the fuel from fracking fields farther away, and the Gulf of Mexico is just 35 miles due south, offering a portal to overseas markets. Lake Charles is also situated in the heart of Trump country, and local and state governments have long been committed to the fossil fuel industry. Incidents of local resistance to fossil fuel and chemical corporations have been few and far between, and resolutely squashed. Today, no national environmental groups have a presence in Lake Charles, where nearly half the residents are Black.In announcing plans for a liquefied natural gas (LNG) "center of excellence" in Lake Charles last March, Mayor Nic Hunter, a Republican, said, "The growth of Southwest Louisiana's LNG industrial complex has put our region on the map and gained us a seat at the global table in recent years." George Swift, president and CEO of the Southwest Louisiana Economic Development Alliance, the leading business network in the Lake Charles area, predicts that "Louisiana could be the LNG export capital of the world."So it must have come as quite an unwelcome shock to a who's who of large energy companies when local resident Roishetta Ozane started showing up to put a kink in their plans—virtually a lone voice against the LNG build-out. "My mission is to ensure that Southwest Louisiana, specifically Lake Charles and the surrounding areas, aren't made into a climate sacrifice zone," Ozane says.
Permian, Haynesville to Spur Natural Gas Production Growth in January, Says EIA - The Permian Basin and Haynesville Shale will keep domestic natural gas production growing into the new year, according to updated modeling from the Energy Information Administration (EIA). In its latest monthly Drilling Productivity Report (DPR), EIA said it expects natural gas production from seven key U.S. regions — the Anadarko, Appalachia and Permian basins, alongside the Bakken, Eagle Ford, Haynesville and Niobrara shales — to rise to a combined 89.346 Bcf/d in January, a 341 MMcf/d sequential increase. The Permian projects to increase output the most for the period, rising 115 MMcf/d from December and January to 19.688 Bcf/d. The Haynesville will follow close behind in growth rate, increasing output an estimated 104 MMcf/d from December to January to just under 14 Bcf/d. Other notable natural gas production gains for the period will come from Appalachia (up a projected 78 MMcf/d month/month to 34.903 Bcf/d) and the Eagle Ford (up 59 MMcf/d to 6.071 Bcf/d). Only the Anadarko is expected to see natural gas production decline from December to January, off an estimated 31 MMcf/d to 6.290 Bcf/d, according to the latest DPR. The next largest sequential gains in crude output for the period will come from the Eagle Ford (up 13,000 b/d to 1.103 million b/d) and the Bakken (up 8,000 b/d to 1.154 million b/d). Operators in the seven regions drew down their backlog of drilled but uncompleted (DUC) wells by 226 units from October to November, according to the most recent EIA data. The largest drawdown occurred in the Permian, where the DUC backlog fell 105 units month/month to 1,564 in November. The Anadarko (down 10), Appalachia (down 26), Bakken (down 30), Eagle Ford (down 35), Haynesville (down nine) and Niobrara (down 11) also saw their respective DUC counts decline for the period. EIA’s DPR makes use of recent rig data along with drilling productivity estimates and estimated changes in production from existing wells to model changes in production from the seven regions.
BP's Haynesville Wells Achieve Top Grade for Methane Emissions Performance - BP plc has become the latest major to differentiate its natural gas through MiQ, with the U.S. onshore business achieving a top grade for the methane emissions performance of some wells in the Haynesville Shale. MiQ’s independently audited certification system reviewed emissions in the Haynesville that are managed by BP’s Lower 48 arm BPX Energy Inc. MiQ helps operators differentiate themselves through methane-emissions performance. MiQ currently certifies about 10 Bcf/d, or around 2.5% of the global gas market and 11% of U.S. gas production. “Tackling methane emissions is vital for natural gas to play its fullest role in the energy transition,” said BPX’s Faye Gerard, vice president of Low Carbon and Sustainability. “We’re in action to reduce these emissions from our operations. MiQ’s certification helps validate the steps we’re taking and makes us even more confident we’re providing the energy the world needs with fewer emissions.” BPX’s South Haynesville Facility in Texas produces about 0.2 Bcf/d. The 70 well sites were certified using the MiQ Standard, which grades a facility’s production from “A” to “F” based on its methane emissions. An A grade represents methane intensity of less than 0.05%, while F represents up to 2%. Third-party auditor GHD independently verified and awarded the top grade to the BPX facility. BPX now is “assessing further certification opportunities across its U.S. onshore operated portfolio” in the Haynesville, as well as the Eagle Ford Shale and Permian Basin.
Lessons from the slow death of Louisiana's oil industry -- As the executive director of the Center for Energy Studies at Louisiana State University, David Dismukes has spent the last 30 years pinpointing the industry’s challenges and theorizing around it’s rapidly changing future. This is what he wants you to know: The energy transition from fossil fuels to solar and wind sources is real. “It’s happening and it’s gonna continue to happen.” “At this point, It doesn’t matter if you’re right, wrong, for, or against,” said Dismukes. “People and industries are making, not just hundreds of millions, but billion-dollar decisions based on the belief that this transition is here.” It’s creating – and taking away – jobs, swaying the economy, andtransforming how we commute. The transition is also killing refineries, to the sounds of praise from environmental groups and uncertainty from the thousands of oil industry workers. In January 2020, a few months before the first coronavirus pandemic shutdown, the American oil refining industry reached its highest capacity peak in history. It didn’t last long. Within months, six refineries, including the Philadelphia Energy Solutions refinery in Philadelphia – the 13th largest in the country – shut off oil production. By December, U.S. oil consumption reached a 25-year low. In the next two years, Wood Mackenzie, an energy consulting group, forecasts that 20 refineries across the globe, including roughly a dozen in the U.S., will cease operations. No other place in the country will feel this more than the Gulf Coast, where roughly 55 percent of the country’s oil production lies. As of January 1, 2021, there were 51 refineries located in the Gulf states of Texas, Louisiana, Alabama, Mississippi, and Florida, compared to 113 in 1982, according to the U.S. Energy Information Administration. Many Louisianians already feel the energy transition’s scope, namely the more than 25,000 former oil production workers in the state who have lost their jobs since 2014. Since the state’s oil production peak in the early 1980s, at least 20 oil refineries have shuttered. As of January 1, 2021, there were 14 facilities still operating. Since then, two more facilities, owned by Shell and Phillips 66 respectively, have closed their doors – in part because of a sweeping convergence of COVID-19, severe weather events, and waning demand for oil. To the tune of at least 900 layoffs, the Phillips 66 refinery – the 25th largest oil-producing refinery in America – located in Plaquemines Parish, Louisiana, announced its closure in early November after experiencing $1.3 billion worth of damage from Hurricane Ida.
Joe Manchin Rejects Democratic Plan to Ban New Drilling in Atlantic and Pacific - The senator from West Virginia, a coal and gas stronghold, has single-handedly stripped key elements from his party’s plan to tackle climate change. — A provision to permanently ban new offshore drilling off the Atlantic and Pacific coasts has been stripped from a draft version of a $2.2 trillion climate change and social spending bill after objections by Senator Joe Manchin III of West Virginia.Draft language of the bill circulated by the Senate Energy and Natural Resources committee, which is led by Mr. Manchin, does not include the drilling ban. According to people who were briefed on Mr. Manchin’s position, he rejected the coastal drilling plan and also raised concerns about a provision that would cancel drilling leases and block future oil and gas extraction in the Arctic National Wildlife Refuge, although that part remains in the section of the bill that he handled, according to a draft.The drilling ban was the latest in a string of climate provisions that have been dropped from the pending legislation because of objections from Mr. Manchin. As the swing Democratic vote in an evenly split Senate, Mr. Manchin enjoys an outsize role and has been able to single-handedly set the limits for the president’s climate agenda.A spokeswoman for Mr. Manchin declined to comment. With direct negotiations with President Biden over the legislation souring in recent days, Mr. Manchin has largely brushed off questions about the bill, known as the Build Back Better Act.While Democratic leaders have been pushing to pass the legislation by Christmas, a Senate vote is set to slip into 2022 in part because of Mr. Manchin’s concerns with the details and costs of the package.Ali Zaidi, the White House deputy national climate adviser, declined on Thursday to comment on what he called “the minutia of the negotiations.”But environmentalists said Mr. Manchin was systematically weakening what was designed to be a robust response to the climate crisis.“This is a tragic milestone in the seemingly inevitable dismantling of the Build Back Better Act,” said Brett Hartl, government affairs director at the Center for Biological Diversity. “Why Senator Manchin wants to poison our coasts while he lives the good life in his landlocked state only shows just how out of touch he is with the overwhelming public support for ending offshore drilling.”Senator Bernie Sanders, the Vermont Independent and chairman of the Senate Budget Committee, called his Democratic colleague “dead wrong.”“Scientists are telling us we have to move progressively, not only as a nation, but as a world to cut carbon emissions,” Mr. Sanders said.Representative Frank Pallone, Democrat of New Jersey who has sponsored legislation to ban offshore drilling along the Atlantic seaboard, called pulling the provision “absurd” and said he would fight to reinstate the measure.A version of the bill that passed the House last month would permanently ban new offshore oil and gas leasing along the Atlantic and Pacific coasts as well as in the eastern Gulf of Mexico. It would not have halted existing offshore drilling activity.
High rates of methane spewing from U.S. Permian oilfield operations – report -- Methane continues to escape at a high rate from oil and gas operations in the Permian Basin, according to an aerial survey released on 14 December that detected major methane plumes from 40% of 900 sites that were measured.The latest research conducted by the Environmental Defense Fund (EDF) via helicopter during the first 2 weeks of November found that 14% of those plumes were the result of malfunctioning flares.Researchers also found that at one-third of smaller wells significant emissions persisted for days. The aerial survey of the largest US oil field showed that leaks arose from different pieces of equipment at different times.This was the eighth aerial survey conducted by EDF's PermianMAP initiative, which monitors methane from the upstream, downstream, and midstream operations in the oil field. The survey comes weeks after the US Environmental Protection Agency proposed the first regulations targeting methane from the country's existing oil and gas facilities.The Biden administration also set a goal to reduce 30% of all methane emissions by 2030 as part of its participation in the Global Methane Pledge, which was formally launched at the UN Climate summit in Glasgow.
USA Expects Permian Oil Output to Hit Record in December - Crude production in the Permian Basin is expected to surpass a pre-pandemic high this month as a rebound in the U.S. shale industry fuels activity in its most prolific patch.Supplies from the Basin, which straddles West Texas and New Mexico, is projected to reach 4.96 million barrels a day in December, the Energy Information Administration said Monday in a report. The current record of 4.91 million barrels a day was set in March 2020. The agency also sees supplies exceeding 5 million barrels a day next month for the first time in data going back to 2007.Crude production from the Permian exceeds that of each OPEC member except Saudi Arabia, underscoring its importance in balancing the oil market. Its low production costs make it appealing to drillers with most producers focusing their U.S. plans for expansion on the sprawling oil patch, at the expense of other shale basins.U.S. shale oil producers will increase capital spending by nearly 20% to $83.4 billion in 2022, the highest since the pandemic began, according to Rystad Energy. Still, that’s about a third lowest than forecast levels in 2019, indicating that companies are more disciplined about basing production decisions on near-term changes in crude prices.Exxon Mobil Corp. and Chevron Corp. have both made the Permian a key focus for next year, even as they keep overall capital spending near multi-year lows. Chevron plans to spend $3 billion in the basin next year, 50% higher than this year’s budget and about a fifth of its global total.Even with the Permian’s growth, total U.S. oil output is still a long way from full recovery. Pioneer Natural Resources Co., said last week that U.S. drillers will need half a decade for nationwide production to reach pre-pandemic levels.*
Earthquakes linked to drilling are messing with Texas - Neta Rhyne frequently feels earthquakes that she worries will destroy the spring and pool in Balmorhea State Park. "We fear these springs are one earthquake away from disappearing forever," Rhyne said. The oil and gas industry — which dominates the West Texas economy — is causing the shaking, scientists say. Specifically, the quakes are linked to injecting underground the billions of gallons of wastewater that come up from wells in the drilling zone known as the Permian Basin. It’s made the forbidding stretch of Chihuahuan Desert east of El Paso one of the shakiest spots in the nation. The plain between El Paso and Midland has been hit this year by 15 earthquakes of magnitude 4 or greater — large enough to rattle dishes and make cracking sounds in houses. And that’s just the most dramatic example of the surge in earthquakes in Texas and southeastern New Mexico in recent years, much of it linked to oil and gas. There have also been quakes around population centers — including Midland, Snyder and San Antonio. The trend is turning Texas into a seismic state and has even prodded the state’s industry-friendly oil and gas regulators into scaling back some oil field activity. So far this year, there have been been almost 200 quakes of magnitude 3 or greater in Texas, nearly doubling the roughly 100 registered in 2020. On top of that, there have been five in southeast New Mexico. There have been no injuries, and little damage has been reported, but there’s concern about what could happen if the quakes keep getting bigger, more frequent or closer to population centers. "We know the historical baseline. We’re way above that," said Mairi Litherland, manager of the New Mexico Tech Seismological Observatory, who is studying the quakes from across the state line. "The present level of seismicity is not really a problem. It could cause problems if it continues." The biggest quake came in March 2020. At magnitude 5, it was big enough to cause real damage. But since it was centered under a flat, empty rangeland between the Pecos River and the Rustler Hills, there wasn’t much to damage. Still, Rhyne felt it 50 miles to the south. She said it caused about $2,000 worth of damage to her home. She worries that more such quakes could damage the San Solomon Spring, which feeds the pool in the state park across the road from her house. An earthquake about 60 miles to the south in the 1990s made the spring turn milky for a time. Now, there’s an earthquake of magnitude 3 or greater in her region every three days on average. Ruining the spring could ruin Rhyne, who runs a dive shop serving people who visit the park to snorkel and scuba dive. The area has several other springs, where the water burbles up from faults. They’re home to at least two endangered fish species. Rhyne has been protesting heavy drilling in the area since 2016, when Apache Corp. announced a large-scale drilling project in the area. By her count, she’s protested about 120 disposal wells to the Texas Railroad Commission, which regulates oil and gas, and failed each time. Her neighbors, she acknowledges, haven’t rallied to the cause. She says she has "closet supporters" in the area.
Kimray acquires Texas-based CEI --Kimray Inc., an Oklahoma City-based manufacturer of oil and gas control equipment, has purchased Texas-based Control Equipment Inc. (CEI).CEI, which serves as Kimray’s largest distributor, operates offices in Cleburne, Lubbock, Odessa, Pampa and Wichita Falls, Texas.“As the oil and natural gas industry has undergone rapid change in recent years, both Kimray and CEI have looked for ways to improve how we operate our businesses and how we can best serve our customers,” said Kimray Vice President of Sales and Marketing Dustin Anderson. “Combining Kimray’s innovation and production capabilities with CEI’s distribution network and expertise will provide huge benefits for the industry in the Permian Basin, southeast New Mexico, north Texas and the Texas Panhandle.”
DOE to Issue Notice of Sale from SPR - The U.S. Department of Energy (DOE) revealed Friday that it will issue a notice of sale for 18 million barrels of crude oil from the Strategic Petroleum Reserve (SPR) on December 17 to address market disruptions. The move follows President Biden’s action to release 50 million barrels of oil from the SPR, which was announced back in November. This release is taking place in two ways, with 32 million barrels released in the form of an exchange over the next several months and 18 million barrels released in the form of a sale that Congress had previously authorized. In a statement posted on its website on Friday, the DOE said it had reviewed and approved the first exchange of 4.8 million barrels for release to ExxonMobil. Delivery will be conducted from the Bryan Mound, West Hackberry and Bayou Choctaw SPR storage sites, according to the DOE. The organization noted that, as it moves forward with its sale, exchange requests will continue to be accepted from interested parties and approved as appropriate to address supply disruptions. “Exchanges and sales from the Strategic Petroleum Reserve are important tools we are using to address oil supply disruptions as the world recovers from a once in a century pandemic,” Secretary Jennifer M. Granholm said in a DOE statement. “The president rightly believes Americans deserve relief now and has authorized the use of the SPR to respond to market imbalances and reduce costs for consumers,” Granholm added in the statement. As the global economy recovers from the pandemic, oil supply has failed to increase at a pace necessary to meet demand, the DOE said in the statement posted on its site. “While oil prices have fallen 10 percent on average over the last month and prices at the pump have started to drop, the administration is continuing to take action to help address the supply-demand gap in the market and lower energy prices for Americans,” the DOE stated. Biden stands ready to take additional action to the 50 million barrel SPR release, if needed, according to a White House statement in November.
US DOE sets SPR sale for Dec. 17, approves 4.8 million barrels to ExxonMobil - The US Department of Energy scheduled a Dec. 17 sale of 18 million barrels from the Strategic Petroleum Reserve and approved an exchange of 4.8 million barrels to ExxonMobil as part of the Biden administration's plan to tap into the SPR to help alleviate fuel prices, the DOE said Dec. 10. The White House previously announced Nov. 23 that the US would release 50 million barrels from the SPR by early next year alongside releases from other major oil-consuming countries to help combat high prices at the pump and record inflation. That release includes an exchange of up to 32 million barrels that would be delivered in mid-December through April and returned in 2022-2024, in addition to 18 million barrels that were already required by Congress to be sold by the end of 2022. The Dec. 10 announcement sets a quick date for the sale of the 18 million barrels, and reveals the first of multiple exchanges. Another 27.2 million barrels of SPR exchanges could still remain. However, since the November announcement, US Deputy Energy Secretary David Turk has said that the timing of SPR releases could be adjusted if oil prices fall and pain at the pump for US consumers begins to ease. US Energy Secretary Jennifer Granholm said, "Exchanges and sales from the Strategic Petroleum Reserve are important tools we are using to address oil supply disruptions as the world recovers from a once-in-a-century pandemic. The president rightly believes Americans deserve relief now and has authorized the use of the SPR to respond to market imbalances and reduce costs for consumers." Crude oil and fuel prices have dipped a bit in December largely from concerns about the COVID-19 omicron variant, although those fears have alleviated a bit. The SPR release news had some impact on prices in November, but the relatively modest size of the release -- and the much smaller releases from other countries -- did not move the markets much. On Dec. 10, NYMEX January WTI settled 73 cents higher at $71.67/b, and ICE February Brent climbed 73 cents to $75.15/b. The Energy Department said it approved the first ExxonMobil exchange for barrels from the Bryan Mound, Texas SPR storage site, as well as the Louisiana sites at West Hackberry and Bayou Choctaw. DOE said exchange requests will continue to be accepted from interested parties and approved as appropriate to address supply disruptions. The coordinated release with India, China, Japan, South Korea and the United Kingdom is the first of its kind. India has announced it would release 5 million barrels, and the UK said it would allow companies in the country to voluntarily release up to a combined 1.5 million barrels of private stocks..
Biden’s strategic crude sale hasn’t inspired action from other nations --It’s been almost three weeks since the U.S. unveiled an internationally coordinated release of oil from national reserves, but so far there’s been little follow through from the other five nations. President Joe Biden said on Nov. 23 that the U.S. would release 50 million barrels of crude from its Strategic Petroleum Reserve in “the next several months.” The unprecedented move would be done in parallel with China, Japan, South Korea, India and the U.K., he said. While the U.S. has granted its first release of SPR oil to Exxon Mobil Corp., and intends to issue another sale notice for 18 million barrels this week, there’s been radio silence from the other participants. That’s starting to prompt some skepticism in the market about whether they’ll go ahead at all, particularly after the omicron virus variant led to a sharp drop in global prices. The Asian nations’ participation in what looks like a buyers’ cartel puts them in a tough spot. “They can’t afford to jeopardize their relationships with major producers to satisfy a U.S. president who’ll be up for re-election in a few years,” They may also “be reluctant to tap into their reserves ahead of peak winter demand, when supply disruptions can lead to major issues,” Driscoll said. The joint release was unprecedented, given that there was no supply shock, and followed weeks of intensive lobbying by Biden after the OPEC+ alliance rebuffed calls to increase supply faster. It contributed to a decline in prices leading up to the announcement, but many in the market were underwhelmed by the volumes that the countries other than the U.S. pledged to release. India was the only Asian nation that was definitive on volume, pledging to release 5 million barrels, although questions remain on timing. The head of Indian Strategic Petroleum Reserves Ltd. said Dec. 3 that he was still waiting for advice from the federal government on how and when to sell the crude. Japan has given no details on volumes or timing, although the Nikkei newspaper reported last month the country would release around 4.2 million barrels. South Korea said on Nov. 23 that it would decide on details such as volume and timing after discussing with partner countries but indicated it would be about 3.5 million barrels. China has been somewhat ambiguous, with Beijing not wanting to look like it was following the U.S. It said in November that it was working on a sale of oil from its reserves, just days after a virtual summit between Biden and President Xi Jinping. A Western official familiar with the matter initially said the Chinese could sell between 7 million and 15 million barrels. There have been no official announcements since.
There’s Not Enough Oil – Doomberg - Rory Johnson is the writer of Commodity Context and his most recent piece, US Shale Patch’s Lackluster Recovery is a Problem for the Post-COVID Oil Market, is a fascinating and sobering read (subscribe to Johnson’s Substack here and follow his Twitter account here). As Johnson explains, US shale operators function in an analogous manner to the miners on Gold Rush, balancing the drilling of new oil wells with completing them for production. Just like overburden can be stripped for future processing, so too can oil wells be drilled but left uncompleted. Such wells are colloquially known as DUCs. Here’s a relevant quote from Johnson’s piece: “Drilled but uncompleted wells are a function of the fact that the US shale production process has two major steps: (1) a well is drilled with a drilling rig and then (2) it is “completed” by a different team (i.e., the actual fracking part) after which it begins to produce marketable crude. When drilling runs ahead of completions as it largely did through 2017-19, the industry accumulates a sizable mountain of this potential production. These DUCs were yet one more bearish factor weighing on pre-COVID market prospects: even when US drilling declined, producers could lean into their DUC inventory to keep production humming along despite weaker rig activity.” The shale boom enabled the US to reestablish itself as the top global producer of oil and gas. Prior to the Covid-19 lockdowns, the US was producing approximately 13 million barrels of oil per day (mbpd) – more than double what it had been generating just a decade earlier. To put that number into context, the world consumed an average of just under 100 mbpd in 2019 (i.e., pre-Covid). For 2020, that number dropped to 91 mbpd, but some estimates peg current global demand to have fully recovered to the 100 mbpd mark in Q4 2021. Interestingly, US oil and gas production is still lagging its early 2020 peak: While many assume the gap in current production from the pre-Covid highs represents spare production capacity that can readily respond to incremental oil demand once the global economy fully reopens, the reality on the ground is different. As Johnson flags, producers are busily completing previously drilled wells at a rapid pace without backfilling the inventory of DUCs. In effect, US shale oil producers are sluicing previously stripped ground and not opening enough new cuts. This is clearly unsustainable. What explains this behavior? We see a combination of factors. First, shale operators destroyed significant shareholder value through excess drilling and mismanagement during the boom. Many companies filed for bankruptcy protection shortly after the Covid-19 lockdowns were implemented and the price of oil collapsed. The recapitalized companies that emerged from reorganization are expressing a commitment to more a disciplined approach, and the numbers certainly reflect this. Second, the Biden administration has signaled its desire to move beyond fossil fuels, which – at a minimum – makes the investment environment for new exploration and drilling more uncertain than it was under Trump. Third, the move to defund the fossil fuel industry by environmental activists and Wall Street financiers alike is making access to capital more challenging. Finally, uncertain timing of the world’s emergence from both the pandemic and the ongoing supply chain crisis is likely adding to the cautionary stance.
Oil spill: 400 gallons discharged into Menomonee, Milwaukee rivers, Milwaukee Riverkeeper says — A used oil transfer error discharged 400 gallons of oil to the Menomonee River last Friday, according to Milwaukee Riverkeeper. Milwaukee Riverkeeper says the Wisconsin Department of Natural Resources confirmed Komatsu has taken responsibility for the incident. Milwaukee Riverkeeper said on Thursday they received several reports of an oil sheen on both the Menomonee and Milwaukee Rivers. Officials say the discharge of oil went into the Menomonee River from a stormwater outfall near American Family Field. "They've placed a boom on site to contain oil, and continue to clean up the contaminated stormwater outfall," Milwaukee Riverkeeper said in a statement on Thursday. Officials say the oil sheen has been observed along both rivers, both downstream and upstream of the Menomonee River confluence, due to the lake seiche and wind pushing some product upstream. According to officials, Komatsu will be conducting spot cleanups of product from the rivers. Komatsu released a statement Thursday regarding the oil spill. Officials say staff at its Joy Global facility on National Ave. initially believed it was a small spill of waste oil from a container. They say upon learning of the spill, they immediately began cleanup procedures and reported the matter to the appropriate authorities. "As cleanup work continued this week, it became clear that the spill was more extensive than initially thought and we began to implement a more aggressive cleanup and remediation effort," Komatsu said in a statement. "We are in the midst of investigating how this very regrettable accident occurred and we are focused on continuing to implement aggressive cleanup efforts to remediate the situation as quickly as possible."
BNSF pays $1.5 million fine for oil spill --One of the country’s largest railways has agreed to pay more than $1.5 million in fines for an oil spill caused by a derailment.According to the U.S. Environmental Protection Agency (EPA) release, approximately 117,500 gallons of heavy crude oil was released into Iowa’s Rock River, Little Rock River and Burr Oak Creek, in June 2018 after one of BNSF’s freight trains derailed.EPA says that the derailment occurred in an area where there was heavy flooding, which resulted in an evacuation order for residents nearby, increased levels of hazardous materials in the area, closed nearby water wells, destroyed crops, and at least 3 animals’ death.BNSF agreed to pay a total fine of $1,513,750.“Illegal discharges of oil into streams, rivers and wetlands present a significant threat to human health and the environment,” said EPA Region 7 Administrator Meg McCollister. “EPA is committed to protecting our nation’s waterways and will ensure that Clean Water Act protections are upheld.”The news release explained that any discharges of pollutants, such as oil, into waterways, that are federally protected, is considered a violation of the Clean Water Act.
Tribal leaders say state’s consultations on Line 5 are lacking -A little more than a year after Gov. Gretchen Whitmer ordered Enbridge to shut down the Line 5 pipeline in the Straits of Mackinac, the state retreated on its key lawsuit seeking to close the twin pipelines.While the move late last month was meant to shift the legal focus to Attorney General Dana Nessel’s separate effort in state court, Indigenous tribal leaders who are united in their Line 5 opposition have expressed cautious optimism to Whitmer’s move — with an emphasis on cautiousness. “While I can understand the legal nuances that are in play while you’re reaching such a decision, it was concerning,” Whitney Gravelle, president of Bay Mills Indian Community in the Upper Peninsula, said of Whitmer’s decision. “The only calculus I can see here is that a stronger battle remains in state court.”Moreover, Gravelle and at least one other tribal leader say the Whitmer administration’s consultations with tribes over Line 5 have been insufficient given a 2019 executive directive that Whitmer issued promising stronger state-tribal relations.“On this issue, I think it’s fallen short,” said Aaron Payment, chairperson of the Sault Ste. Marie Tribe of Chippewa Indians. “Gov. Whitmer is the first to give specifics (about mandating consultation with tribes), but I would say sometimes the devil gets lost in the details. As it relates to Line 5 or the wolf hunt, in a lot of these issues we get relegated to basically another constituency. I think it’s her intent, but I would like to see more direct attention from the governor. You would expect these consultation sessions would happen at a higher level rather than administrative staff that are often four or five rungs below.”
Biden asks tribes to weigh in on high-stakes pipeline talks – The Biden administration has invited Great Lakes tribes for input on unprecedented, upcoming talks with Canada over the fate of a contentious pipeline that’s creating what sources say is a rift between the two countries.At issue in the fight over Enbridge Inc.’s Line 5 is a dispute resolution process set out by the "Transit Pipeline Treaty of 1977" that Canada invoked for the first time for this case.The treaty, Canada argues, guarantees the uninterrupted flow of petroleum products between the U.S. and Canada, while Democratic Michigan Gov. Gretchen Whitmer pushes to shutter Line 5 in state court (Energywire, Dec. 1).Because the negotiations are unprecedented, experts say there’s no way to tell when talks will start, how long they will last or if the results will be public.“This thing has really never been used — period,” said Andy Buchsbaum, an attorney for the National Wildlife Federation and a lecturer at the University of Michigan law school. ”And certainly negotiations between these two countries have never happened under this treaty.”The 68-year-old Line 5 pipeline, which moves light crude and natural gas liquids from Superior, Wis., to Sarnia, Ontario, has emerged as a lightning rod among tribal communities and activists concerned about the effects a spill could have on the Great Lakes.In addition to treaty talks, the pipeline is also at the center of a fight in Michigan state court and an environmental review by the Army Corps of EngineersWhile the State Department has repeatedly said it’s weighing policy options and plans to engage in the talks with Canada under the treaty soon, the department has provided few details.But Aaron Payment, chair of the Sault Ste. Marie Tribe of Chippewa Indians, confirmed the State Department invited his tribe to weigh in on the treaty talks with Canada.Payment joined Michigan’s 12 federally recognized tribes last month in calling on President Biden to support Whitmer’s efforts to decommission the pipeline, citing tribal fishing and hunting rights in the pipeline area that date back to an 1836 treaty.A spokesperson for the State Department in an email confirmed the agency had invited the tribes to voice their views and concerns surrounding the Line 5 project before engaging with Canada under the 1977 treaty.The Biden administration’s invitation is notable given how little is known about how treaty talks would proceed. But the White House has been outspoken about giving tribes a great say in treaties and boosting consultation on energy issues.“The Biden administration has been very quiet on this issue, and they’re going to have to take a position soon,” said Kristen van de Biezenbos, a law professor at the University of Calgary.
Line 5: A symbol of North America's debate over continued fossil fuel investment - Canadian-based Enbridge’s plan to encapsulate its controversial Line 5 fuel pipeline with a $500 million tunnel beneath the Straits of Mackinac lakebed is the kind of investment in fossil fuels that America needs to stop if it is going to address climate change in a more meaningful way, a University of Michigan researcher said Monday.Julia Cole, a U-M earth and environmental sciences professor, said the project “absolutely works against” collective efforts to reduce greenhouse gases that are warming the planet and disrupting climate patterns.“When you are in a hole — and we are in a big hole — the first thing you have to do is stop digging,” Ms. Cole said. “The pipeline and the tunnel represent the investments we have to avoid.”Ms. Cole was the featured speaker of a webinar hosted by the Chicago-based Environmental Law & Policy Center.The moderator was Margrethe Kearney, an Environmental Law & Policy Center senior attorney, who opened the event by calling Line 5 “an immediate threat to the Great Lakes” and Enbridge’s plan for a tunnel “a disruptive and dangerous undertaking.”At no time during the event, though, was there any mention of pipelines delivering fuel products far more efficiently and with fewer greenhouse gases than by ship, rail, or truck.That’s assuming there are no accidents, of course.In fact, Line 5 was built in 1953 to reduce the potential of crude oil spilling into the Great Lakes and their tributaries when moved by those other modes of transportation.But a tugboat’s 2018 anchor strike which dented Line 5 has raised questions about the need for the 645-mile pipeline which delivers 42 percent of the products refined throughout northwest Ohio and southeast Michigan.The webinar’s theme wasn’t about the fate of area gasoline, jet fuel, propane, or refinery workers, though.It was a big picture look at how continued investments in major pipelines keep North Americans hooked on fossil fuels.Ms. Cole said it’s time to move on and encourage more focus on renewable energy and other alternatives.The administration of Ohio Gov. Mike DeWine, meanwhile, remains adamantly opposed to efforts undertaken by Michigan Gov. Gretchen Whitmer and Michigan Attorney General Dana Nessel to shut down Line 5.“Our administration has always stood for an all-of-the-above energy strategy,” Ohio Lt. Gov. Jon Husted said in a statement the governor’s office issued to The Blade on Monday. “To execute that, we cannot simply shut down access to certain types of energy with no long-term plan to replace it or the thousands of jobs these industries support. It will take decades for America to transition away from the internal combustion engines that power our cars, trucks and air travel. Until that day, if Governor Whitmer closes Line 5, she will drive up the price of fuel and hurt the working people of the Midwest who can’t afford to pay more at the pump to go to work and take care of their families.”
US requires higher safety standards for more pipelines - (AP) — A new federal regulation requires higher safety standards for pipelines carrying oil and other hazardous liquids through the Great Lakes region, marine coastal waters and beaches, officials said Thursday. The rule issued by the U.S. Pipeline and Hazardous Materials Safety Administration designates those locations as “high consequence” zones where pipeline operators must step up inspections, repairs and other measures to avoid spills. The agency estimated that 2,905 additional miles (4,675 kilometers) of hazardous liquid pipelines will be covered under the new rule, primarily in states along the Gulf of Mexico. “The Great Lakes and our coastal waters are natural treasures that deserve our most stringent protections,” said Tristan Brown, the agency's deputy administrator. “This rule strengthens and expands pipeline safety efforts." Congress ordered the pipeline safety agency last year to include the Great Lakes, coastal beaches and coastal waters among “unusually sensitive areas" meriting extra attention. “We know a pipeline spill in the Great Lakes would be catastrophic,” said Sen. Gary Peters, a Michigan Democrat who sponsored the provision. The natural gas and oil industry "is committed to the safe and environmentally responsible operation of U.S. energy infrastructure, and pipelines remain one of the safest ways to deliver affordable, reliable energy," said Robin Rorick, a vice president of the American Petroleum Institute, a trade association. “As our industry works to protect the environment and communities where we live and work, this rule provides the opportunity to further that commitment.” Large oil releases would severely damage shoreline and underwater environments, fisheries, human health and coastal community economies, the regulation says. The 53-page document acknowledges there's no way to know how many disasters the new requirements will prevent. But it offers several previous examples of damaging spills in the designated areas. Among them: last month's release from an oil pipeline in Southern California and a 2010 spill of about 840,000 gallons (3.2 million liters) of crude near Marshall, Michigan, which contaminated nearly 40 miles (64 kilometers) of the Kalamazoo River. It also notes a 2018 anchor strike that dented Enbridge Energy's Line 5 in Michigan's Straits of Mackinac connecting Lake Huron and Lake Michigan, although it didn't cause an oil leak. The new rule requires operators to include any pipeline that could affect the designated environments in their safety management programs. Those procedures include in-line inspections, pressure tests and other methods to measure pipeline integrity, as well as analyses of significant threats such as corrosion.
Indigenous and environmental activists say they were illegally spied on -Tribal members and environmental advocates filed a lawsuit against the Oregon Department of Justice on Tuesday for “illegal domestic spying” through its Oregon TITAN Fusion Center – one of approximately 80 intelligence hubs tasked with surveilling potential domestic terrorists. “It is astonishing and disturbing to become the target of a well-resourced secret police, solely because of my participation in peaceful rallies opposing a harmful fossil fuel pipeline across my ancestral lands,” Ka’ila Farrell-Smith, an environmental and Indigenous rights advocate, said in a press release. Farrell-Smith is a plaintiff in the case and a member of the Klamath Tribe. She has protested against Jordan Cove, a 229-mile long natural gas pipeline that would have run through ancestral lands in Oregon. She has also created protest art and organized against a lithium mine in Nevada. Other plaintiffs include Rowena Jackson, Francis Eatherington, and Sarah Westover. Jackson is also a member of the Klamath Tribe, a water protector, and works at the Klamath Tribes Administrative Office. Eatherington is president of the Oregon Women’s Land Trust, a conservation nonprofit. Westover was an organizer with No LNG Exports Coalition, an alliance of groups opposed to the Jordan Cove pipeline. According to the lawsuit, “fusion centers” have little oversight and less is known about them. At least 3,000 state and federal employees work at fusion centers where they monitor individuals that pose possible domestic terrorist threats. Using tips from the public, social media, public records, and governmental materials, Oregon’s TITAN Fusion Center collects and shares data with “more than 170 local law enforcement agencies, dozens of federal and state intelligence hubs, and an unknown number of public and private partners,” the lawsuit states. Following 9/11, at least 80 fusion centers have been created to prevent future terrorist attacks, but a 2012 Senate investigationfound that they are ineffective and come at a cost of $330 million to taxpayers yearly. Originally created by the U.S. Department of Homeland Security, the cost of funding them has largely shifted to states. According to the lawsuit, Oregon’s TITAN facility is run through Oregon’s Department of Justice’s Criminal Intelligence Division. The lawsuit, filed by the Policing Project at the New York University School of Law, which partners with communities and police to promote accountability, claims that TITAN is illegally spying on environmental advocates that aren’t breaking the law. The Policing Project has also been involved in a case against Microsoft, siding with the company and its stance to not release data to law enforcement, and an audit of Ring, a video doorbell company that works with police departments across the country.
Sinclair Fracking With Large Amounts Of Water -- December 12, 2021 - Bruce Oksol - The other day we took a look at the wells recently posted by Sinclair. I didn't get a chance to look at the frack data until today. Looking at one of those wells, it appears Sinclair is completing these wells with large fracks, using over 12 million gallons of water. This is in contrast to MRO recently reporting wells fracked with six million gallons of water.
Thousands of gallons of oil by-product spilled in ND - The North Dakota Department of Environmental Quality (DEQ) is investigating a produced water spill north of Williston. The DEQ says produced water is a by-product of oil production. Originally, Summit Midstream Partners, LLC, said approx. 10 barrels of produced water spilled, but now it’s estimating 176 barrels or 7,300 gallons of produced water spilled into agricultural land. The cause of the spill is under investigation.
U.S. grand jury accuses Amplify Energy of negligence in oil spill – A federal grand jury has accused Amplify Energy Corp and two of its subsidiaries of illegally and negligently discharging oil during a pipeline break in California in October and failing to respond to alarms.The Department of Justice said the indictment alleges that the companies, which own and operate the 17-mile (27 km) San Pedro Bay Pipeline, failed to properly respond to eight alarms over more than 13 hours on October 1-2. The indictment also accuses Amplify and its Beta Operating Co LLC and San Pedro Bay Pipeline Co subsidiaries of shutting and restarting the pipeline five times after the first five alarms were triggered, sending oil flowing through the damaged pipeline for more than three hours.Amplify said it investigated the pipeline but it was then not known to the crew that the leak detection system was malfunctioning. The detection system was "wrongly signaling a potential leak at the platform where no leak could be detected by the platform personnel and where no leak was actually occurring," it said in a statement.The oil spill left fish dead, birds mired in petroleum and wetlands contaminated, in what local officials called an environmental catastrophe. An estimated 25,000 gallons of crude oil were discharged from a point approximately 4.7 miles west ofHuntington Beach from a crack in the 16-inch pipeline, the statement said.An earlier report by the Associated Press showed how the spill was not investigated for nearly 10 hours.
Amplify Energy Faces Federal Charge For Orange County Oil Spill -- — The company that owns the underwater pipeline that ruptured and spilled thousands of gallons of oil in Orange County waters October was indicted Wednesday on federal charges of illegally distributing oil, City New Service reported. Amplify Energy Corp. and two of its subsidiaries — Beta Operating Co. and San Pedro Bay Pipeline Co. — were charged with failing to adequately respond to eight leak alarms during a 13-hour period, prosecutors said. The company is additionally charged with improperly restarting the pipeline after it had been shut down in response to the alarms. The indictment filed in Los Angeles federal court charges the companies with one misdemeanor count of negligent discharge of oil. For a "corporate defendant," the charge carries a penalty of up to five years of probation, and fines that could possibly total millions of dollars, according to the U.S. Attorney's Office. Prosecutors said the pipeline began leaking the afternoon of Oct. 1, but the companies continued pumping oil through the line until the next morning. The oil spill occurred after an underwater pipe ruptured and leaked roughly 30,000 gallons of oil into Orange County waters. Soon after, tarballs began washing up on Orange County shores, and residents began to notice oil sheens in the ocean water. This triggered a 800-plus strong force of U.S. Coast Guard crews and volunteers to take to the beach in a massive cleanup effort. The leak also forced the cancellation of the popular Huntington Beach Airshow, which was already underway when the spill was noticed. While the cleanup ensued, Orange County residents questioned what caused the oil spill to begin with, and pushes calling for an end to offshore drilling intensified across the Golden State. Orange County elected officials wondered why neither they or the public were notified of the spill sooner.The federal indictment alleges the companies:
- Failed to properly respond to eight alarms from an automated leak-detection system between 4:10 p.m. Oct. 1 and 5:28 a.m. Oct. 2.
- Shut down and then restarted the pipeline five times after the first five alarms were triggered, meaning oil continued flowing through the damaged line for more than three hours
- Pumped oil for three additional hours late on Oct. 1 into the early morning hours of Oct. 2 while a manual leak test was performed, despite the sixth and seventh alarms.
- Despite the eighth alarm, operated the pipeline for nearly one hour in the predawn hours of Oct. 2 after crew on a boat the company contacted failed to spot any discharged oil in the middle of the night.
- Operated the pipeline with crew members who were not adequately trained on the automated leak detection system
- Operating the pipeline with an "understaffed and fatigued crew."
More than a dozen companies doing business in the region have sued Amplify Energy Corp. for damages resulting from the spill.
OC spill: 3 companies charged after thousands of gallons of oil leaked into ocean - Three companies are facing federal charges in connection to the Oct. 2021 oil spill that damaged the Orange Countycoastline.According to an announcement from the U.S. Department of Justice (DOJ), the following companies are accused of illegally discharging oil during the pipeline break off the coast of Huntington Beach back in early October:
- Amplify Energy Corp.
- Beta Operating Co. LLC, a subsidiary of Amplify
- San Pedro Bay Pipeline Co., a subsidiary of Amplify
Amplify and its two subsidiaries are also accused of "failing to properly respond to eight separate leak alarms over the span of more than 13 hours and improperly restarting the pipeline that had been shut down following the leak alarms," according to the DOJ.The leak happened on October 1, but the DOJ is accusing Amplify and its two subsidiaries of continuing their operations – on and off – through the next morning, despite the pipeline being damaged. The DOJ claims the companies' negligence caused about 25,000 gallons of crude oil to leak up to 4.7 miles off the coast of Huntington Beach. The DOJ said the U.S. Coast Guard, the U.S. Department of Transportation, Office of Inspector General, the U.S. Environmental Protection Agency, Criminal INvestigation Division and the FBI are teaming up in the investigation of the Huntington Beach oil spill.
Repair to ruptured California oil pipeline to start Friday, leaked documents reveal — The oil company accused of negligence this week for failing to properly respond to an October oil spill off the Southern California coast is set to begin permanent repair work, according to leaked documents reviewed by NBC News, but critics say approval of the work appears rushed. As early as Friday morning, divers will descend about 160 feet below the surface to begin placing what documents describe as a “steel patch” over a cracked area of pipe that was temporarily repaired in the wake of the Oct. 1 spill. The patch is designed to allow the pipeline to be thoroughly cleaned and flushed before two large sections of pipe — totaling nearly 300 feet — are removed from the seafloor and ultimately replaced at a later date. The plan was circulated to state and federal regulators by the U.S. Army Corps of Engineers no more than 48 hours before the work was set to begin and required agencies to notify the Corps within a day if they had comments on the work. The listed contact person for the Bureau of Safety and Environmental Enforcement, a federal regulatory agency that oversees offshore oil work, was out of the office during that time according to an automatic reply when contacted by NBC News. Later phases of the plan call for new sections of pipe to be brought in, and finally concrete mats to be installed over top to protect it. A spokesperson for pipeline owner Amplify Energy said so far only the first part of the job has been approved by the Pipeline and Hazardous Materials Safety Administration. One critic points to the emergency repair process as an example of a cozy relationship between industry and regulators. Miyoko Sakashita, oceans director and senior counsel at the Center for Biological Diversity, said the repair plan should have gone through a permitting process that allowed for more agency and public oversight. She likened the permit notice to a “Christmas Gift” for Amplify Energy. “This looks like an instance where the Army Corps is essentially thinking of itself as customer service to the oil company to get the pipeline and platform going again, rather than providing the strict oversight to protect against water pollution,” Sakashita said.
Coast Guard, California officials monitoring potential oil spill — The Coast Guard and California state officials are monitoring a potential oil spill. The Huntington Beach Police Department shared a photo Thursday, showing an oil sheen that appeared overnight.Right now, it’s about the size of a football field and officials are keeping a close eye on the situation. Several emergency response teams are on standby as the Coast Guard races to determine what's causing it. The oil appeared roughly two miles off the coast in the same area where a large oil spill happened in October. The Coast Guard is conducting regular flights over the area while state teams are stationed along several beaches. No oil has impacted shoreline areas at this time.
Huntington Beach Oil Sheen Does Not Affect Beach, Cause Still Unknown -- - An oil sheen spotted off the coast of Huntington Beach does not appear to have been caused by a pipeline leak, officials said today. The ``unified command'' of authorities that responded to the oil spill in October that consists of the U.S. Coast Guard, California Department of Fish and Wildlife and Office of Spill Prevention and Response and Orange County issued a news release saying, ``there is no indication of an unsecured discharge of oil.'' The authorities could not find any evidence of oiling of the beaches. The authorities expect to release their response team as of Saturday. The samples collected on Wednesday ``are inconsistent with natural seep oil and with the oil associated with the discharge on Oct. 2, 2021, Pipeline P00547 incident,'' according to the unified command. Officials will continue investigating to determine what caused the oil sheen spotted about two nautical miles off the coast. The U.S. Coast Guard received a report about the oil sheen at about 4:30 p.m. Wednesday, said U.S. Coast Guard Petty Officer Aidan Cooney. ``It was getting too dark to send out our assets, so we contacted other agencies nearby to see if they could assist,'' Cooney said. Officials from Cal Fire and the state Fish and Wildlife Service sent out aircraft and boats to investigate the report, Cooney said. ``They found some sheen, pulled a sample and we're waiting for test results to identify the source,'' he said. Orange County Supervisor Katrina Foley said she was informed that there was a ``pinhole leak'' in a pipeline, but officials said they did not know which one. It is expected to be a minor leak, and at this point the experts believe it is gas that is in the water, she added. Orange County CEO Frank Kim said he was called about the incident Wednesday night. He directed the county's public works department to help build a berm at Talbert Marsh on Wednesday night at the city's request. Huntington Beach firefighters smelled ``a strong petroleum scent'' that indicated some kind of oil sheen near the coastline. Oil response officials were deployed Wednesday night but did not find any evidence of oiling and decided to conduct an aerial view Thursday morning at first light, Kim said. The sighting came on the same day that the company that owns the underwater pipeline that ruptured in October, leaking thousands of gallons of oil, was indicted along with two of its subsidiaries on a federal charge of illegally discharging oil.
Manchin opposes drilling bans offshore and in the Arctic National Wildlife Refuge - Democratic plans to restrict new oil and gas development off both coasts and in Alaska’s Arctic National Wildlife Refuge have emerged as a new flash point in the Build Back Better bill, highlighting the party’s political schism as it tries to advance the massive spending legislation. Sen. Joe Manchin III (D-W.Va.), a critical swing vote, has rejected a provision that would prohibit all future drilling off the Atlantic and Pacific Coasts, as well as the eastern Gulf of Mexico, according to three people familiar with the matter, all of whom spoke on the condition of anonymity to discuss private deliberations. He also expressed surprise at top Democrats’ decision to include language ending an oil and gas leasing program in the pristine refuge, a longtime priority for party leaders and their environmentalist allies, but he has not indicated whether he will oppose it.Manchin, who chairs the Senate Energy and National Resources Committee, exercises a de facto veto over the $2 trillion climate and social spending plan because it needs all 50 Democrats’ votes to win Senate passage.A spokeswoman for Manchin declined to comment on the matter. Asked about the senator’s opposition during the White House press briefing Thursday, deputy national climate adviser Ali Zaidi declined to address it or say how it would affect the president’s climate targets.Manchin’s objection to the proposal comes amid a broader rift between the influential senator and top Democrats over President Biden’s Build Back Better bill, which party leaders had hoped to pass by the end of the year. Despite months of negotiations and Democrats’ attempts to shrink the bill’s size to win Manchin’s vote, he has withheld his support and a long list of disagreements remain.The senator, who earns millions from his family’s waste coal business, succeeded in killing a key piece of Biden’s climate agenda — a $150 billion plan to push power companies toward cleaner energy. He also has targeted measures that would affect the oil and gas industry, objecting to a tax credit for electric cars and a provision that would reduce emissions of methane, a potent greenhouse gas.Manchin also criticized the design of the funding measure, arguing that Democrats are relying on funding gimmicks to say their legislation is paid for.House Democrats’ version of the spending bill included a permanent ban on new offshore drilling — which would not apply to existing leases — as well as language that would end the oil and gas leasing program authorized on the Arctic National Wildlife Refuge’s coastal plain in the 2017 tax bill.Senate leaders jettisoned the offshore drilling provision from their version of the bill in light of Manchin’s opposition but have preserved language ending the oil and gas leasing program on the refuge.Two weeks before President Donald Trump left office, the Interior Department’s Bureau of Land Management auctioned off the right to drill on more than 550,000 acres of the refuge’s coastal plain for $14.4 million. When the leases were later modified, the revenue generated dropped to $12 million. Federal law requires the department hold another lease sale by 2024.
Fuel leak at Pearl Harbor military base contaminates drinking water on the Hawaiian island of Oahu --A massive contamination of the drinking water supply for residents of Joint Base Pearl Harbor-Hickam was discovered on November 20, when 14,000 gallons of jet fuel spilled at the Red Hill Bulk Fuel Storage Facility on the Hawaiian island of Oahu. CNN reported on December 5 that “Records show a history of fuel leaks plaguing Joint Base Pearl Harbor-Hickam in the past decade, with the most recent leak occurring 11 days before the Navy announced it had discovered contamination in the Red Hill well on Oahu.” The Board of Water Supply (BWS) for Honolulu closed down the Halawa Shaft, Oahu’s largest water source, on Thursday, December 2, after the Navy reported in a virtual town hall meeting that it found “a likely source of the contamination,” according to a CNN report. According to the Associated Press, Rear Admiral Blake Converse told state lawmakers Friday that Navy officials are very confident that the contamination happened on November 20, when 14,000 gallons of jet fuel spilled at the Red Hill Bulk Fuel Storage Facility inside a tunnel that provides access to fire suppression and service lines for the complex. The complex supplies fuel for military aircraft and ships that operate in the Pacific. Use of the facility has been suspended. The spill was cleaned up, Converse claimed, but residents have been warning for weeks of an odor from the water and some have reported going to hospitals for cramps and vomiting after they drank the water. The Red Hill Bulk Fuel Storage Facility has a long history of leaks dating back to 1943 when it was first built, during the intensive military build-up for WWII. The Sierra Club told Honolulu Civil Beat that since 1943, the facility has recorded at least 73 fuel leaks totaling at least 180,000 gallons, numbers the Navy disputes.Red Hill Bulk Fuel Storage Facility consists of 20 fuel tanks and an array of pipelines that use gravity to deliver fuel to Pearl Harbor, a short 2.5 miles away. The massive facility, which holds approximately 180 million gallons of fuel, rests 100 feet above a groundwater aquifer that supplies 77 percent of the island’s total water, according to the Department of Health (DOH). The underground steel tanks enclosed by a concrete shell are now corroding. The Navy claims the tanks are inaccessible and thus impossible to maintain. The pipeline system and the tanks are the same age.
Plans to Reopen St. Croix’s Limetree Refinery Have Analysts Surprised and Residents Concerned - The St. Croix neighborhood of Clifton Hill overlooks a quieted Limetree Bay Refinery on Tuesday, May 25 after a stack fire and massive oil flare caused a 60-day shutdown ordered by the U.S. Environmental Protection Agency. Clifton Hill residents, many of whom migrated to St. Croix from nearby Vieques, are no strangers to the refinery’s discharges under its previous owner, Hovensa. But the most recent shower of oil on their homes, cars, gardens and cisterns was the second in little over three months as the beleaguered 60-year-old refinery struggled to resume operations after an eight-year hiatus.An accident-prone oil refinery in the U.S. Virgin Islands with a history of serious environmental violations could soon reopen under new ownership, despite strong objections from nearby communities, a litany of environmental scandals and a shaky financial outlook.After shutting down in 2012 and declaring bankruptcy in 2015, St. Croix’s Limetree Bay refinery restarted operations under new ownership in February. But within days, the refinery began experiencing what became a series of high-profile accidents that enraged nearby residents, raining oil down on homes, contaminating drinking water and releasing hazardous fumes so pungent that officials shut down schools and offices for days. Environmentalists saw the restart as a testament to former President Trump’s pro-fossil fuel agenda for “American energy dominance” and his administration’s penchant for granting favorable terms to well-connected corporate interests. Trump officials expressed a willingness in emails to the refinery’s new owners to facilitate its reopening, and legal scholars said the administration ignored decades of precedent in issuing new permits. The Environmental Protection Agency dispatched investigators in early May to the island, where they declared Limetree was in violation of the Clean Air Act and ordered the facility to halt operations, citing an “imminent” health threat to residents. Then this summer, Limetree’s owners—a consortium of privately-funded companies that include Limetree Bay Refining and Limetree Bay Services—announced the facility would cease operations for good. They promptly declared bankruptcy, announced layoffs for more than a quarter of the refinery’s employees and began the process to auction off the property.In October, several bids emerged from companies seeking to dismantle the dysfunctional facility and sell it off for scrap. For many residents who live the closest to the property, which stretches for more than two square miles across the southern shore of the small Caribbean island, the moment presented a chance to get rid of a poorly run—and what some consider unnecessary—refinery that disproportionately harmed mostly Black and Brown communities.
At least 77 dead and dozens injured after gas tanker explodes in Haiti’s second largest city - A fuel tanker exploded in Haiti’s second largest city early Tuesday morning after overturning in the neighborhood of La Fossette, letting loose a massive fireball that has resulted in at least 75 deaths and dozens of injuries, according to local authorities. The explosion took place in the northern city of Cap-Haitien when a tanker transporting gasoline crossed into the Semarie district at the eastern entrance of the city. After crossing a bridge into La Fossette, the driver lost control of the tanker while trying to avoid hitting a motorcycle taxi, causing the truck to flip over and erupt in flames. Hours after the blast, surrounding buildings and overturned vehicles were engulfed in the blaze as firefighters desperately tried to put out the fire and find survivors. Most of the deaths happened as a result of passers-by rushing to the tanker moments after it tumbled over to collect the escaping fuel, a rare commodity as the entire country has been wrecked by severe fuel shortages. Early reports indicate onlookers rushed to the scene with buckets to scoop up what they could of the tanker’s valuable cargo, likely for resale on the black market, as the fuel spilled toward a nearby pile of trash before the entire tanker imploded. Monday saw demonstrations in major cities across the country against the government’s decision to raise fuel prices, with truck drivers leaving their vehicles parked blocking major roadways. The grave shortages of gas and the gruesome explosion resulting from it is the latest manifestation of widespread social suffering gripping the Caribbean nation and its working class. Haiti continues to reel from a 7.2 magnitude earthquake that killed more than 2,200 people and destroyed tens of thousands of homes this past summer. This was on top of the July 7 assassination of President Jovenel Moise, a killing that has left the political structure of the country in near-shambles and which has paved the way for evermore rampant violence by gangs connected to the government and its security forces. Local officials indicated that the death count from the tank disaster is expected to rise significantly as rescue efforts are still ongoing, and patients with massive burns are being treated in hospitals. Federal and state authorities said they have deployed two field hospitals to Cap-Haitien to help treat burn victims. Numerous people had been airlifted from Cap-Haitien to a hospital specializing in severe burns in the capital city of Port-au-Prince, according to Doctors Without Borders, the France-based international humanitarian organization that runs the hospital.
Major oil spill in Argentine Province of Rio Negro contained — Argentina's Federal Energy Secretary DarÃo MartÃnez has toured the area near the RÃo Negro town of Catriel where an oil spill caused environmental damage to assess the situation and order the measures to be taken. The incident took place in a section of the oil pipeline system known as the Oleoductos del Valle system (Oldelval). MartÃnez explained the works needed to solve the situation that will be undertaken. He also met with his RÃo Negro colleague Andrea Confini and with executives from Oldelval and of the Petróleos Sudamericana company to coordinate the joint efforts. “We have seen that the situation is controlled, that after cordoning off the affected area, the spill stopped, the pipeline began to be repaired and the spilt oil has already been collected. Now the specific work to remediate the entire affected area must begin,” MartÃnez said. “The Ministry technicians surveyed the situation, and [they] will work to analyze the tasks carried out and to determine the causes and responsibilities of this spill episode,” he added. Oldelval reported late on Friday that they had managed to contain the spill, while the Government of Neuquén overflew the area with a drone to measure the damages. “The nearby watercourses were not affected by the incident. Oldelval deployed an important operation in the area to start the oil recovery work and the cleaning of the area, both on the ground and on the vegetation,” the company said in a statement. The Federal Ministry of Environment also sent the Environmental Control Brigade to the area to evaluate the damages in the Medanito area. The Rio Negro Secretary of Energy reported that the incident occurred in a “16-inch pipeline, the responsibility of which is the Oldelval company, which connects the El Medanito pumping station with the Rincón de Los Sauces pumping station, in Neuquén ”. The failure occurred in the trunk pipeline system that transports the oil produced in the Neuquén Basin to Buenos Aires. As it is a national oil conduction network, inspectors from the National Energy Secretariat were involved.
Greenpeace calls on Greece to abandon deep-sea oil and gas exploration due to the threat of extinction of marine life. --Greenpeace urged Greece once more on Wednesday to abandon deep-sea oil and gas exploration, citing “unbearable” consequences for marine life. Greenpeace Greece’s Kostis Grimanis stated that the project should be stopped before it “starts to wreck the Mediterranean.” “Endangered species and critical ecosystems will be exposed to intolerable noise and pollution from seismic blasts and deep-sea drilling operations,” Grimanis said. “What is it for?” Continue to burn oil and gas, which are among the dirtiest and most expensive energy sources, when the climate crisis demands that we abandon them.” New research on sea mammal populations in areas of the Hellenic Trench, including those that would be impacted by the exploration, was recently published by the environmental group. In depths of up to 13,800 feet, researchers discovered 35 endangered sperm whales and dozens of threatened dolphins during a three-week summer project in collaboration with the Pelagos Cetacean Research Institute in Athens. Whаles аnd dolphins, which аre sound-sensitive cetаceаns, would be endаngered by sonic blаsts used in deep seа prospecting, аccording to Greenpeаce. Officiаls in Greece hаve stаted thаt they will аdhere to strict environmentаl regulаtions. In 2019, Greece grаnted energy compаnies TotаlEnergies аnd ExxonMobil with Greece’s Hellenic Petroleum explorаtion rights for two blocks of seаbed south аnd southwest of the islаnd of Crete.
China Tightens Its Grip On Qatar With New LNG Contract - Another new long-term contract for Qatar to supply China with liquefied natural gas (LNG) was signed last week, this time between QatarEnergy and Guangdong Energy Group Natural Gas Co for one million tons per annum of LNG starting 2024 and ending in 2034, although it can be extended.Qatar has long eschewed unequivocally aligning itself further with the U.S. directly or with any of its proxies in the Middle East, most notably Saudi Arabia. In January 2019, when it left OPEC after 60 years as a member, Saad Sherida al-Kaabi stated that the decision was: “Not political, it was purely a business decision for Qatar’s future strategy towards the energy sector.” It was, though, in reality, a highly political decision, founded partly on disaffection with being caught in the negative economic fallout of Saudi Arabia’s disastrous – but repeated - attempts to destroy or disable the U.S.’s shale oil sector through oil price wars, as analyzed in-depth in my new book on the global oil markets. This antipathy towards toeing the Saudis’ idiotic strategies was bolstered when Saudi Arabia attempted to cause Qatar further direct economic damage by instigating a blockade against it from June 2017 (to January 2021), supposedly for providing support to various Islamist groups, including the Muslim Brotherhood. Qatar publicly acknowledged that this was true as far as the Muslim Brotherhood went but privately railed at the hypocrisy of the Saudis. In this context – and one of the crucial reasons why the initial public offering of Saudi state flagship hydrocarbons company, Aramco, was not able to list in any major international financial center – Qatar alluded to Saudi Arabia’s own suspected links to terrorism, with 15 of the 19 hijackers in the ‘9/11’ attacks on the U.S. being Saudi nationals. Another reason – and arguably an even more important one – for Qatar avoiding further alignment with the U.S. directly or indirectly, is its inextricable links to Iran, Saudi Arabia’s (and the US.’s nemesis) in the region. Even a cursory understanding of the global hydrocarbons market would indicate that this ‘co-operation’ is required due to Qatar and Iran sharing a huge natural gas field (the 3,700 square kilometer ‘South Pars’ site on the Iran side and the 6,000 square kilometer ‘North Dome’ site on the Qatar side) and that Qatar has little choice but to co-ordinate policies and activities relating to it. Qatar had long accused Iran, with good reason, of over-exploiting its side of the world’s largest natural gas field to the detriment of Qatar’s ability in the future to tap the gas reserves on its side, particularly as Qatar had a moratorium over further development of North Dome from 2005 until the end of the first quarter of 2017. Following the U.S.’s unilateral withdrawal from the Joint Comprehensive Plan of Action (JCPOA) with Iran in May 2018, senior figures from Iran’s Petroleum Ministry and Qatar’s Energy Ministry began a series of meetings to agree on a new North Dome-South Pars joint development plan.
Saudi Arabia, Kuwait say they are working to raise Neutral Zone crude oil production | S&P Global Platts - Saudi Arabia and Kuwait are continuing work to increase crude oil production at the Neutral Zone fields they share, which could be a key source of additional barrels as OPEC+ spare capacity is expected to tighten significantly in 2022. "Coordination is currently underway between companies operating in the divided area and the submerged area adjacent to it," the two countries said Dec. 10 in a joint statement as Saudi Crown Prince Mohammed bin Salman capped off a tour of Gulf Cooperation Council countries with a visit to Kuwait that concluded Dec. 10. Crude production in the Neutral Zone's onshore Wafra and offshore Khafji fields has suffered from technical challenges stemming from its lengthy shutdown, sources have told S&P Global Platts, with output ranging from below 200,000 b/d some months to as high as 270,000 b/d. Prior to their shutdown in the mid-2010s, the fields typically produced a combined 500,000 b/d. As the OPEC+ alliance intends to phase out its production cuts by late 2022 and global oil demand rises in the pandemic recovery, the Neutral Zone may be counted on for incremental supply, though Platts Analytics forecasts that output will be capped at 250,000 b/d throughout 2022 due to the operational setbacks. Crude exports from the Neutral Zone in 2021 have ranged from a low of 158,000 b/d in August to a high of 257,000 b/d in November, according to Kpler shipping data. The exports have gone regularly to India, China, South Korea and the US, with Japan and Thailand also taking some cargoes in recent months, the Kpler data showed. The Neutral Zone fields, which lie in onshore and offshore territory shared by Saudi Arabia and Kuwait at their border, were offline for more than four years until 2020, due to a political dispute that was resolved with a signing of an agreement in December 2019. Production in the zone is divided evenly between the two countries. Sources involved in reviving production say the rehabilitation of the fields and infrastructure has encountered several challenges that have hindered a full ramp-up. The offshore Khajfi is operated by Saudi Arabia's Aramco Gulf Operations Co. and Kuwait Gulf Oil Co., while the onshore Wafra is operated by KGOC and Saudi Arabian Chevron. Besides the Neutral Zone, the two countries also said in their statement they would continue to support the OPEC+ alliance in "enhancing the stability of the global oil market, and stressed the importance of continuing this cooperation and the need for all participating countries to adhere to the OPEC+ agreement."
Mapping the world's oil and gas pipelines | Infographic News | Al Jazeera - Over the past 50 years, the world’s annual energy consumption has nearly tripled – from 62,949 terawatt-hours (TWh) in 1969 to 173,340 TWh in 2019.For centuries, burning coal was the main source of the world’s energy. By the 1960s, rapid advancements in sourcing, transporting and refining oil and gas allowed those energy-dense fossil fuels to overtake coal and become the world’s primary source of energy – which they remain today.Despite advances in renewable energy, fossil fuels including coal, oil and gas still make up more than 80 percent of the world’s primary energy consumption. Every day, the world consumes some 100 million barrels of oil and 60 million equivalent barrels of natural gas.To transport this massive amount of energy, pipelines – usually made out of carbon steel – are widely used.In the following infographic series, we map the world’s current and planned oil and gas pipelines.
Oil markets polarized as OPEC brushes off omicron fears - Oil market watchers are torn between dramatically different forecasts for crude prices, even after OPEC's upbeat forecast for crude demand in 2022. OPEC's outlook sees the world consuming 99.13 million barrels per day of crude in the first quarter of 2022, an increase of 1.1 million barrels per day from its last forecast a month ago, showing a more relaxed outlook on Covid-19 risks. The omicron variant's impact is projected to be "mild and short-lived," OPEC's latest monthly report said, adding that the world is better equipped to manage the pandemic. While the 13 member group of oil-producing states has not let fears of the omicron variant change its projected timeline for a return to pre-pandemic oil demand, the market is still feeling the weight of bearish sentiment. International travel restrictions have increased, and some state and local leaders have re-imposed things like mask-wearing and regular PCR test mandates. The U.K. raised its Covid alert level, while its Prime Minister Boris Johnson warned of a "tidal wave" of the more transmissible omicron cases, although data on the severity of the variant is still unclear. International benchmark Brent crude is trading in the low $70 range, around $73.54 a barrel at 10:00 a.m. ET on Tuesday, down just over 1%, with West Texas Intermediate was trading at $70.53 a barrel at the same time, also down just over 1%. "Very few trading days see the oil market so polarized as today," Louise Dickson, senior oil markets analyst at Rystad Energy, wrote in a note Tuesday. "While there is a clear bearish monster at the gates, the Omicron variant, bullish traders are placing bets that OPEC+ changes course and lowers crude output, which if realized will add to the support coming from Pfizer's efficacy confidence in its antiviral pill against the pandemic's latest strain." The decision of OPEC and its allies, in a larger group called OPEC+, is yet to be seen, as there is so far little indication of the group straying from its current plan of increasing crude production by 400,000 barrels per day in January of 2022. The group previously forecast a massive supply glut of 275 million barrels during the first quarter of next year, while stressing that it is prepared to reverse course if necessary on its plan to increase production. While it might seem counterproductive, the strategy there, analysts said, could be to increase market share and hobble U.S. shale producers with lower oil prices, as well as disincentivize Washington from pushing as hard for a return to the Iran nuclear deal that would bring back more Iranian crude to the market. United Arab Emirates Energy Minister Suhail al-Mazrouei described the oil market as being "in a good condition," speaking to reporters in Dubai on Monday. "We have made our latest decision based on studying all the fundamentals of the market and we are confident that we are moving to a well-supplied market in the first quarter," he said.
Column: Low hedge fund oil positions create re-entry point (Reuters) - Hedge fund selling of oil futures and options slowed in the most recent week, after a tidal wave of selling the week before, probably indicating the liquidation cycle is near its end. Hedge funds and other money managers sold the equivalent of 19 million barrels in the six most important futures and options contracts in the week to Dec. 7, down from 131 million in the week to Nov. 30. Sales over the last nine weeks have now totalled 313 million barrels, according to position records published by ICE Futures Europe and the U.S. Commodity Futures Trading Commission. The most recent week saw further sales of Brent (-13 million barrels), NYMEX and ICE WTI (-3 million), European gas oil (-2 million) and U.S. gasoline (-2 million) but small purchases of U.S. diesel (+1 million). Portfolio managers last week cut their combined position across the six contracts to just 558 million barrels (in the 40th percentile for all weeks since 2013) down from 871 million (79th percentile) on Oct. 5. But the reduced rate of selling suggests the most severe phase of liquidation associated with the new Omicron variant of coronavirus has now passed its peak (https://tmsnrt.rs/33g0NqQ).
OPEC raised its world oil demand forecast for the first quarter of 2022 - Oil futures ended lower on Monday, as traders focus on the spread of the omicron variant that causes COVID-19, and as they look toward this week’s Federal Reserve decision on monetary policy for clues on the economic outlook and energy demand. The oil market has been trying to look past the impact of the new variant, as more countries warn of the potential of wide spread infections from the omicron variant. January WTI fell 38 cents, or 0.5%, to settle at $71.29 a barrel, while Brent for February delivery lost 76 cents, or 1%, to settle at $74.39 a barrel. Petroleum products also ended lower, with January RBOB down 1% at $2.117 a gallon and January heating oil falling 0.8% to $2.233 a gallon. OPEC raised its world oil demand forecast for the first quarter of 2022 but left its full-year growth prediction steady, saying the Omicron coronavirus variant would have a mild impact as the world gets used to dealing with the pandemic. In its monthly report, OPEC said it expects oil demand to average 99.13 million bpd in the first quarter of 2022, up 1.11 million bpd from its forecast last month. OPEC maintained its forecast that world oil demand will increase by 5.65 million bpd in 2021, after last year's historic decline at the start of the pandemic. In 2022, OPEC expects further growth in demand of 4.15 million bpd, unchanged from last month, which will push world consumption above 2019 levels. The report showed OPEC output in November increased by 290,000 bpd to 27.72 million bpd led by increases in top two producers Saudi Arabia and Iraq and a recovery from outages in Nigeria. OPEC left its forecast for growth in U.S. tight oil largely steady at 600,000 bpd in 2022. The growth forecast for overall non-OPEC supply in 2022 was left unchanged. OPEC said it expects the world to need 28.8 million bpd from its members in 2022, up 200,000 bpd from last month. Iraq's Oil Minister said he expected OPEC at its next meeting to maintain its current policy of gradual monthly increases in supply by 400,000 bpd. Saudi Arabia's Energy Minister, Prince Abdulaziz bin Salman al-Saud, said oil markets could face a dangerous period as reduced investments in exploration and drilling threaten to cut crude production by 30 million barrels per day by 2030. He also stated that Saudi Arabia would be one of few countries that could raise its oil production capacity in 2022. He said oil will make up 28% of energy demand until at least 2045 compared with 30% in 2020. Saudi Arabia’s Energy Minister also stated that if demand for oil declines in the future, OPEC producers will represent a larger share of the market.The EIA reported that crude oil output from U.S. major shale formations is forecast to increase by 96,000 bpd to 8.439 million bpd in January.
Oil Settles Lower on Oversupply Concerns, Strong Dollar (Reuters) -Oil futures prices dropped toward $73 a barrel on Tuesday after the International Energy Agency (IEA) said the Omicron coronavirus variant is set to dent global demand recovery. U.S. data showing producer prices at 11-year highs reinforced market expectations of faster stimulus tapering by the Federal Reserve, which meets this week. This supported the dollar and weighed on oil, which typically move inversely. Brent crude futures fell 69 cents, or 0.9%, to $73.70. U.S. West Texas Intermediate (WTI) crude futures settled down 56 cents, or 0.8%, at $70.73. The U.S. dollar stayed near one-week highs on Tuesday versus a basket of major currencies, bolstered by the producer prices data. "As some accelerated tapering out of the Fed becomes more likely, US interest rates are apt to lift in pushing additional strength into the dollar in forcing price weakness into the oil," On Tuesday, the World Health Organization said the Omicron variant was spreading at an "unprecedented" rate, prompting markets to edge lower. "The surge in new COVID-19 cases is expected to temporarily slow, but not upend, the recovery in oil demand that is under way," the Paris-based IEA said in its monthly oil report.[IEA/S] Governments around the world, including most recently Britain and Norway, have tightened restrictions to stop the spread of the Omicron variant. The IEA lowered its forecast for oil demand this year and the next by 100,000 barrels per day (bpd) each, mostly because of the expected blow to jet fuel use from new travel curbs. The Asian Development Bank on Tuesday trimmed its growth forecasts for developing Asia for this year and next to reflect risks and uncertainty brought on by the variant, which could also hamper oil demand. On Monday, the Organization of the Petroleum Exporting Countries (OPEC) raised its world oil demand forecast for the first quarter of 2022 and stuck to its timeline for a return to pre-pandemic levels of oil use, saying the Omicron variant's impact would be mild and brief. OPEC+, which includes OPEC and other producers including Russia, plan to boost supply every month by 400,000 barrels per day (bpd) after sharply cutting output last year. Output in the largest U.S. shale basin is expected to surge to a record in January, according to a forecast from the U.S. Energy Information Administration.
Oil reverses early losses despite rising supply, Omicron fears -- Oil prices turned positive on Wednesday following the Federal Reserve's statement, snapping three straight days of losses. Brent crude futures jumped 18 cents, or 0.24%, to settle at $73.88 per barrel, after losing 69 cents on Tuesday. U.S. West Texas Intermediate (WTI) crude futures settled 14 cents, or 0.2%, higher at $70.87 a barrel, after losing 56 cents in the previous session. Earlier in the day both contracts had been negative on growing signs that supply growth will outpace demand next year, and as the World Health Organization said COVID-19 vaccines may be less effective against the Omicron variant. The front-month Brent contract is trading at a small premium to the second month , after trading briefly at a small discount on Tuesday, a market structure known as contango. The WHO on Wednesday said preliminary evidence indicates vaccines may be less effective against infection and transmission linked to the Omicron coronavirus variant, which also carries a higher risk of reinfection. The International Energy Agency (IEA) on Tuesday said a surge in COVID-19 cases with the emergence of the Omicron variant will dent global demand for oil at the same time that crude output is set to increase, especially in the United States, with supply set to exceed demand through at least the end of next year. In contrast, the Organization of the Petroleum Exporting (OPEC) on Monday raised its world oil demand forecast for the first quarter of 2022. In another bearish indicator, industry data showed that U.S. crude inventories last week did not decline as much as expected. American Petroleum Institute data showed U.S. crude stocks fell by 815,000 barrels in the week ended Dec. 10, according to market sources, compared with a 2.1 million barrel drop that 10 analysts polled by Reuters had expected. However, distillate stocks fell by 1 million barrels, compared with analysts' forecasts for an increase of 700,000 barrels, and gasoline stocks rose by 426,000 barrels, which was a smaller build than expected. Weekly data from the U.S. Energy Information Administration is due later on Wednesday.
WTI Rebounds Back Above $70 After Big Surprise Crude Draw --Oil prices are lower overnight - extending the most recent declines - as Omicron-driven demand fears (last night's ugly China data reinforcing that conviction) coincide with US shale and OPEC+ supply surplus anxiety. There appears to be a growing conviction that inventories are starting to rise and will accumulate more rapidly next year amid curbs on travel, a view adopted by the IEA on Tuesday.Additionally, prompt prices for Brent crude briefly dipped to a discount known as contango that signals oversupply.Gasoline stocks will be closely watched after the typical seasonal high demand pull for Thanksgiving didn’t really materialize as the Biden administration battled pricey gasoline at the pumps.API
- Crude -815k (-1.7mm exp)
- Cushing +2.257mm
- Gasoline +426k
- Distillates -1.016mm
DOE:
- Crude -4.584mm (-1.7mm exp) - biggest draw since Sept
- Cushing +1.294mm
- Gasoline -719k
- Distillates -2.852mm
Official data shows crude stocks dropping significantly last week - the biggest draw since September. Products also saw drawdowns as Cushing stocks rose for the 5th straight week...
Oil Edges up on Consumer Demand, Inventory Declines (Reuters) -Oil prices edged higher on Wednesday, rebounding from early losses after U.S. inventory data showed strong consumer demand and as the Federal Reserve said it would end its pandemic-era bond purchases in March to slow rising inflation. Prices had been pressured most of the day due to ongoing concerns that supply growth will outpace demand next year and worries that COVID-19 vaccines may be less effective against the spreading Omicron variant. Brent crude futures settled up 18 cents, or 0.2%, to $73.88 a barrel. U.S. West Texas Intermediate (WTI) crude ended up 14 cents to $70.87 a barrel. The Federal Reserve said it would end its pandemic-era bond purchases in March and begin raising interest rates as unemployment remains low and inflation has risen. Oil prices rose in line with other risky assets like U.S. equities, which responded positively to the Fed's statement. U.S. crude inventories sank by 4.6 million barrels last week and distillate and gasoline stocks also declined, weekly government data showed. Crude exports picked up sharply, while product supplied by refineries, a signal of consumer demand, hit a record 23.2 million barrels per day. "The EIA data was very strong across all elements, record implied oil demand, large draw of crude and oil products," said Giovanni Staunovo, commodity analyst at UBS. That said, oil analysts anticipate the Omicron variant will curb demand in the coming months. The World Health Organization said preliminary evidence indicated vaccines may be less effective against infection and transmission linked to the Omicron variant, which also carries a higher risk of reinfection. "As more information comes out about potential lockdowns or travel restrictions as a result of Omicron we could see a pullback from here," said Gary Cunningham, director of market research at Tradition Energy. U.S. officials said coronavirus cases are on the rise, but the combination of the two-shot vaccine and booster does still neutralize the disease.
Oil Edges Higher on Bullish EIA Data, Fed's Hawkish Pivot -- Chasing equity markets higher, oil futures nearest delivery on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange edged higher in market-on-close trade Wednesday. Gains accelerated post-settlement after the Federal Open Market Committee signaled the end of its ultra-easy monetary policy earlier than previously thought, making an aggressive policy change in response to rising inflation. Furthermore, a bullish inventory report released midmorning from the U.S. Energy Information Administration that has showed a sharp decline in U.S. petroleum stockpiles offered additional support. At settlement, NYMEX January West Texas Intermediate futures gained $0.14 to $70.87 per barrel (bbl), with ICE February Brent futures edging higher to $73.88 per bbl, up $0.18 per bbl on the session. NYMEX January ULSD futures gained 0.20 cent to settle at $2.2204 per gallon, with the January RBOB futures contract surging 1.67 cents to $2.1275 per gallon. FOMC concluded their final meeting of the year with a clear signal to the markets that the central bank is prepared to raise its short-term benchmark interest rate at least three times next year to cool higher inflation. The change in policy follows data from November showing the consumer price index spiked to 6.8% over the 12-month period, a 39-year high, while wholesale prices posted its highest year-on-year gain on record at 9.6%. Faced with eyepopping inflation data, the Fed will be buying $60 billion of bonds each month starting in January, half the level prior to the November taper and $30 billion less than it had been buying in December. Most Federal Reserve officials now expect U.S. gross domestic product annualized growth at 4% next year, down 1.5% from their September projection, while also seeing lower unemployment rate of 3.5% and a higher federal reserve funds rate of 0.9%, up 0.8% from three months ago. Core inflation is now seen at 2.6% for 2020, down from 4.4% expected in October. EIA's inventory report proved bullish for the oil complex, detailing a larger-than-expected drawdown from U.S. crude oil stockpiles accompanied by a surprise drop in refined fuels supplies. Total petroleum stockpiles declined 15.9 million bbl in the reviewed week, with 4.6 million bbl of that drop realized in crude stockpiles alone. At 428.3 million bbl, commercial crude oil inventories remain about 7% below the five-year average. Further bullish parts of the report could be found in refined fuel complex. Gasoline stockpiles unexpectedly fell by 719,000 bbl from the previous week to 218.6 million bbl compared with analyst expectations for inventories to increase by 1.2 million bbl. Demand for motor gasoline, meanwhile, shot up by 509,000 barrels per day (bpd) or 5.6% to 9.472 million bpd -- the highest since the week ended Oct. 29. Distillate inventories also decreased, down 2.9 million bbl to 123.8 million bbl, and are now about 9% below the five-year average, the EIA said. Distillate fuels supplied to the U.S. market spiked 1.318 million bpd or 36% from the prior week to 4.896 million bpd. That's the greatest weekly implied demand rate since late January 2003 when it was 4.926 million bpd, while total oil products supplied to U.S. market reached a record high of 23.191 million bpd last week. Offsetting some of the bullish effect from EIA's inventory report was concern over COVID, with the World Health Organization on Tuesday warning the new omicron variant of coronavirus is spreading faster than any previous strain and is likely already in most countries of the world.
Oil hits $75 as U.S. demand and Fed outweigh virus concern - Oil nudged above $75 a barrel on Thursday, supported by record U.S. implied demand and falling crude stockpiles, even as the spread of the Omicron coronavirus variant threatens to put a brake on consumption globally. Crude and other risk assets such as equities also got a boost after the U.S. Federal Reserve gave an upbeat economic outlook, which lifted investor spirits even as the Fed flagged a long-awaited end to its monetary stimulus. Brent crude futures gained $1.14, or 1.5%, to settle at $75.02 per barrel. West Texas Intermediate crude futures rose $1.51, or 2.13%, to settle at $72.38 per barrel. Demand has been rising in 2021 after last year's collapse, and the U.S. Energy Information Administration (EIA) on Wednesday said product supplied by refineries, a proxy for demand, surged in the latest week to 23.2 million barrels per day (bpd). "These figures suggest a healthy economic backdrop," said Tamas Varga of oil broker PVM. "Although the Fed's announcement triggered a jump in both oil and equity prices, the withdrawal of economic support together with the Omicron crisis are the two major headwinds the oil market is currently facing," he added. Lending further price support, the EIA also reported that U.S. crude stocks fell 4.6 million barrels, more than analysts had forecast. Worries about the virus and the prospect of a supply surplus next year, as flagged by the International Energy Agency in its monthly report this week, limited gains. Britain and South Africa reported record daily COVID-19 cases while many firms across the globe asked employees to work from home, which could limit demand going forward. "We are skeptical despite the latest news that the good sentiment on the oil market will be carried over into the first quarter," said Barbara Lambrecht of Commerzbank. "After all, a substantial supply surplus is looming."
Oil Futures Deepen Losses on Firmer US Dollar, Omicron Spread - Nearby-month delivery oil futures on the New York Mercantile Exchange and Brent crude on the Intercontinental Exchange settled Friday's session with steep losses. The losses were triggered by growing concerns that a rapid spread of the COVID omicron variant across several major oil-consuming economies would trigger an avalanche of quarantine closures this winter, undermining mobility and economic activity at the start of next year.The omicron variant of coronavirus, first detected in the United States only 17 days ago, has now been found in at least 40 states and is quickly overtaking delta as a dominant strain, according to public health officials. Sharply higher COVID-19 infections and hospitalizations this week have prompted a new wave of cancellations and disruptions as the country prepares for another pandemic holiday season. The U.S. is now averaging 118,717 new COVID-19 cases each day -- 40% higher than a month ago, according to data aggregated by Johns Hopkins University data. Some colleges and universities are moving to online classes, while multiple indoor entertainment venues are canceling performances and professional sports leagues are postponing games. Oil traders closely monitor unfolding developments around the omicron variant as it can affect mobility trends and fuel demand in major oil consuming economies, such as the U.S. The International Energy Agency revised lower demand expectations for both 2021 and 2022 by 100,000 barrels per day (bpd) in its December Oil Market Report released early this week. So far, the new variant has had limited effect on U.S. fuel consumption, with the latest government data showing a record-high 23.191 million of fuel supplied to the U.S. market during the week ended Dec. 10. Demand for motor gasoline shot up by 509,000 bpd or 5.6% to 9.472 million bpd -- the highest since the week ended Oct. 29, according to the Energy Information Administration. Distillate fuels supplied to the U.S. market spiked 1.318 million bpd or 36% from the prior week to 4.896 million bpd, the greatest weekly implied demand rate since late January 2003 when it was 4.926 million bpd, EIA said. Total petroleum stockpiles declined 15.9 million barrels in the week ended Dec. 10, with 4.6 million bbl of that drop realized in crude stockpiles alone. At 428.3 million bbl, commercial crude oil inventories remain about 7% below the five-year average.U.S. dollar index reversed higher in afternoon trade Friday after briefly pausing on a two-day pullback from a monthly high 96.895. At last look, the greenback traded near 96.560, up 0.57% against basket of foreign currencies. The Bank of England announced on Thursday that it would hike interest rates for the first time since the coronavirus pandemic, while warning that inflation was likely to hit 6% in April -- three times its target level. U.K. consumer price inflation surged to 5.1% in November, its highest level in more than a decade, leaving the economy at risk of stagflation, a toxic mix of weak growth and rising prices. The Bank of England said it expects prices to rise further. At settlement, NYMEX January West Texas Intermediate futures declined $1.52 to $70.86 per barrel (bbl), with ICE February Brent futures falling to $73.52 per bbl, down $1.50 bbl. NYMEX January ULSD futures plunged 4.64 cents or 1.7% to $2.2199 gallon, with the January RBOB futures contract falling more than 5.5 cents to $2.1217 per gallon.
Oil falls this week as Omicron and tightening Fed sour sentiment - Oil posted a weekly decline after a volatile few days that saw traders grow more concerned about the demand impact from the omicron variant and tighter monetary policy. Futures in New York fell as much as 3.4 per cent on Friday to briefly trade below US$70 a barrel. It ended the week losing over 1 per cent as daily COVID-19 cases in the U.K. jumped to a record, while hospitalizations surged across the U.S. Prices also weakened after the U.S. dollar rose in response to impending steps by the Federal Reserve and other central banks to tame inflation. Brent crude closed the weekly broadly steady. “We need to be ready for COVID headlines to continue driving the oil market on a day-to-day basis at least until the remainder of this winter,” Signs are also emerging of softening oil demand in Asia, while the International Energy Agency said this week that the global market had returned to surplus as omicron impedes travel. The weakness is showing up in the market’s structure, with Brent flicking in and out of a bearish contango, which signals oversupply. “Crude oil is struggling amid raised concerns about the fast-spreading omicron virus and its impact on global demand,” “Also, unseasonal warm weather in Asia is potentially softening demand for fuels toward heating and power generation.” The seventh round of Iran nuclear talks concluded in Vienna and will resume soon. The European Union’s Envoy Enrique Mora said parties have reestablished common ground for negotiations but that they have weeks, not months, to revive the 2015 Iran deal. This week has seen traders contend with conflicting signals on demand and supply. Those include the central banks’ moves, restrictions to limit the spread of omicron and declining inventories in the U.S. That has caused a generally risk-off attitude in oil markets, leading the aggregate volume of futures contracts to drop over the past two sessions. L West Texas Intermediate for January delivery fell US$1.52 to settle at US$70.86 a barrel in New York. Brent for February settlement fell US$1.50 to US$73.52 on the ICE Futures Europe exchange. Oil at US$100 a barrel cannot be ruled out in 2023 as supply additions are expected to be too slow to keep up with record demand, according to Goldman Sachs Group Inc. China ramped up its buying of Iranian crude last month after independent refiners were granted extra import quotas for 2021. Processing the high-sulfur crudes produced in the Gulf of Mexico hasn’t been this profitable since 2017, thanks to cheap shale gas.
Israeli airstrikes in Syria targeted chemical weapons facilities, officials say - Just after midnight on June 8, Israeli warplanes streaked across the country’s northern frontier for a highly unusual airstrike deep inside Syrian territory. The jets fired missiles at three military targets near the cities of Damascus and Homs, killing seven soldiers, including a colonel described in local news accounts as a “hero martyr” and an engineer who worked at a top-secret Syrian military lab. The Israel Defense Forces, following standard practice, declined to comment on the incursion into Syrian airspace. But intelligence analysts in Western capitals quickly observed a distinction in the operation: While previous Israeli attacks in Syria nearly always targeted Iranian proxy forces and arms shipments, the June 8 strike was aimed at Syrian military facilities — all with links to the country’s former chemical weapons program. An explanation emerged in the weeks that followed. According to current and former intelligence and security officials briefed on the matter, the June 8 strike was part of a campaign to stop what Israeli officials believe was a nascent attempt by Syria to restart its production of deadly nerve agents. On June 8, 2021, Syrian state media reported an Israeli aerial attack near the capital of Damascus and in the central province of Homs. (Alikhbaria Syria via AP) Israeli officials ordered the raid, and a similar one a year earlier, based on intelligence suggesting that Syria’s government was acquiring chemical precursors and other supplies needed to rebuild the chemical-weapons capability that it had ostensibly given up eight years ago, according to four current and former U.S. and Western intelligence officials with access to sensitive intelligence at the time of the strikes. They spoke on the condition of anonymity to discuss classified material and their understanding of Israeli deliberations. The attacks reflected grave concerns that arose within Israeli intelligence agencies beginning two years ago, after a successful attempt by Syria’s military to import a key chemical that can be used to make deadly sarin nerve agent, the officials said. The worries grew as intelligence operatives spotted activity at multiple sites that pointed to a rebuilding effort, the officials said.
Elite US Military Unit Named 'Talon Anvil' "Bombed Civilians At Will" In Syria --This week peace advocates responded to a report about a US military unit that killed Syrian civilians at 10 times the rate of similar operations in other theaters of the so-called War on Terror by accusing the United States of hypocritically sanctioning countries while committing atrocities of its own, and by reminding people that there is no such thing as a "humane" war. On Sunday, The New York Times reported the existence of Talon Anvil, a "shadowy force" that "sidestepped safeguards and repeatedly killed civilians" in aerial bombardments targeting militants in Syria. The unit "worked in three shifts around the clock between 2014 and 2019, pinpointing targets for the United States' formidable air power to hit: convoys, car bombs, command centers, and squads of enemy fighters." "But people who worked with the strike cell say in the rush to destroy enemies, it circumvented rules imposed to protect noncombatants, and alarmed its partners in the military and the CIA by killing people who had no role in the conflict," the paper reported, including "farmers trying to harvest, children in the street, families fleeing fighting, and villagers sheltering in buildings." Medea Benjamin, co-founder of the peace group CodePink, told Common Dreams Monday that "it is stomach-wrenching to read how secret US teams in Syria run by low-level officers made life-and-death decisions about when and where to drop 500-pound bombs." "Years later, we hear about all the civilians obliterated but are left with a fait accompli and no accountability," she added. "This, let's remember, is coming from the nation that just hosted a 'Summit for Democracy' where we droned on and on about human rights." Larry Lewis, a former Pentagon and State Department adviser who co-authored a 2018 Defense Department report on civilian harm, told the Times that Talon Anvil's civilian casualty rate was 10 times higher than in operations he tracked in Afghanistan. One former Air Force intelligence officer who worked on hundreds of Talon Anvil missions said those who ordered the strikes "were ruthlessly efficient and good at their jobs, but they also made a lot of bad strikes." In one of the deadliest of those "bad strikes," scores of civilians were killed in a March 18, 2019 airstrike on a crowd of mostly women and children in Baghuz. It was a so-called "double-tap" strike—first, an F-15E fighter jet dropped a 500-pound bomb; then another warplane dropped a 2,000-pound bomb to kill most of the survivors. US military officials then attempted to cover up the apparent war crime.
Taliban hoping US will 'slowly, slowly change its policy toward Afghanistan,' official says - A senior Taliban official says in a new interview that he is optimistic the U.S. will shift its Afghanistan-related policies as the new regime seeks “mercy and compassion” from the world. Afghan Foreign Minister Amir Khan Muttaqi told The Associated Press that he hopes “America will slowly, slowly change its policy toward Afghanistan.” “You are a great and big nation, and you must have enough patience and have a big heart to dare to make policies on Afghanistan based on international rules and relegation, and to end the differences and make the distance between us shorter and choose good relations with Afghanistan,” he said. Muttaqi, who reportedly has aides from both the previous government and members of the Taliban, said that group does not have any issues with the U.S., but that he wants the U.S. to release more than $10 billion in funds that were frozen when the Taliban took over Kabul in August, the AP reported. “Sanctions against Afghanistan would ... not have any benefit,” he said, adding that “making Afghanistan unstable or having a weak Afghan government is not in the interest of anyone" The foreign minister also told the AP that leaders from the former government can live without risks to their safety in Afghanistan. However, Human Rights Watch has previously reported that the Taliban killed or forcibly disappeared more than 100 former police and intelligence officials since its takeover. Muttaqi also discussed the international outrage of Afghanistan's restrictive lifestyles for women, saying that new Taliban leaders are "committed in principle to women participation" and that girls are in school through grade 12 in 10 of Afghanistan's 34 provinces.
Pakistan is trying to rally Muslim countries to help Afghanistan— Pakistan is rallying Muslim countries to help Afghanistan stave off aneconomic and humanitarian disaster while also cajoling the neighboring country's new Taliban rulers to soften their image abroad. Several foreign ministers from the 57-member Organization of Islamic Cooperation are meeting in Islamabad on Sunday to explore ways to aid Afghanistan while navigating the difficult political realities of its Taliban-run government, Pakistan's top diplomat said Friday. The new Taliban administration in Kabul has been sanctioned by the international community, reeling from the collapse of the Afghan military and the Western-backed government in the face of the insurgents' takeover in mid-August.The OIC meeting is an engagement that does not constitute an official recognition of the Taliban regime, said Pakistan's Foreign Minister Shah Mahmood Qureshi.He said the message to the gathering on Sunday is: "Please do not abandon Afghanistan. Please engage. We are speaking for the people of Afghanistan. We're not speaking of a particular group. We are talking about the people of Afghanistan." Qureshi said major powers — including the United States, Russia, China and the European Union — will send their special representatives on Afghanistan to the one-day summit. Afghanistan's Taliban-appointed Foreign Minister Amir Khan Muttaqi will also attend the conference.
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